Electric Power Wheeling and Dealing:

Technological Considerations for

Increasing Competition

May 1989

NTIS order #PB89-232748
Recommended Citation:

U.S. Congress, Office of Technology Assessment, Electric Power Wheeling and Dealing:

Technological Considerations for Increasing Competition, OTA-E-409 (Washington, DC:

U.S. Government Printing Office, May 1989).

Library of Congress Catalog Card Number 89-600706

For sale by the Superintendent of Documents

U.S. Government Printing Office, Washington, DC 20402-9325

(order form can be found in the back of this report)
Foreword

This assessment responds to a request by the House Committee on Energy and

Commerce for OTA to evaluate the technical feasibility of increased competition in the

electric utility industry. In particular, the Committee requested an analysis of the impact of

increased wheeling on the reliability and operation of the transmission systems. Wheeling is

the use of a utility’s transmission facilities to transmit power for other buyers and sellers.

Competition is being introduced into the electric utility industry in an effort to control

costs, encourage innovation, and create business opportunities. Competition among providers

of new generating capacity is increasing rapidly, and many purchasers of power are seeking

access to these suppliers through wheeling. However, doubts remain as to whether the

operation of the electric system will be as economic and reliable under competition as it has

been under the present industry structure and regulatory framework.

This assessment analyzes how the Nation’s power systems could accommodate various

proposals for competition intended to make the electric power industry more responsive to

market forces. Operation of an electric power system is extremely complex, and increased

competition could have serious effects on costs and reliability if not implemented carefully.

The assessment identifies the technical requirements that must be met to keep the system

working well as the level of competition increases, and determines how competitive

enterprises could meet these requirements.

OTA is grateful for the substantial help received from many organizations and

individuals in the course of this study. The project’s advisory panel and workshop participants

provided invaluable guidance. Reviewers of the draft report contributed greatly to its accuracy

and objectivity. Contractors prepared reports (which will be made available in Volume II of

this report) that were essential in evaluating the often speculative claims of the advantages and

disadvantages of competition.

JOHN . GIBBONS

Director

. . . Ill
Increased Competition in the Electric Power Industry

Advisory Panel

Richard Schuler, Chairman

Cornell University

Howard Allen

Southern California Edison Co.

John Anderson

Electricity Consumers Resource Council

William W. Berry

Dominion Resources

Jan Beyea

National Audubon Society

Ashley Brown

Public Utilities Commission of Ohio

Robert L. Bryant

Golden Spread Electric Cooperative

Bill Carnahan

City of Riverside

Will Comtois

Westinghouse Electric Corp.

Mark Cooper

Consumer Federation of America

Floyd Culler

Electric Power Research Institute

Charles E. Curtis

Van Ness, Feldman, Sutcliffe & Curtis

Richard Disbrow

American Electric Power Service Corp.

Jerry D. Geist

Public Service Company of New Mexico

Michehl R. Gent

North American Electric Reliability Council

Janice G. Hamrin

Independent Energy Producers of California

Leonard Hyman

Merrill-Lynch Capital Markets

Roger Naill

Applied Energy Services

Gail Garfield Schwartz

New York State Public Service Commission

Lee White

White, Fine, & Verville

Gene Zeltmann

General Electric Co.

RESIGNED December 1987

Andrew Varley

Iowa State Utilities Board

IN MEMORIUM

Samuel Huntington

New England Electric System

Fred Schweppe

Massachusetts Institute of Technology

NOTE: OTA appreciates and is grateful for the valuable assistance and thoughtful critiques provided by the advisory panel members.

The panel does not, however, necessarily approve, disapprove, or endorse this report. OTA assumes full responsibility for the

report and the accuracy of its contents.

iv
OTA Project Staff-Electric Power Wheeling and Dealing: Technological

Considerations for Increasing Competition

Lionel S. Johns, Assistant Director, OTA

Energy, Materials, and International Security Division

Peter D. Blair, Energy and Materials Program Manager

Alan T. Crane, Project Director

Karen Larsen, Senior Analyst

Robin Roy, Analyst

Joanne Sedor, Analyst

Administrative Staff

Lillian Chapman Linda Long Phyllis Brumfield

Contributor

Warren W. Schenler

Contractors

Boston Pacific Co., Inc. Kennedy P. Maize

James S. Cannon Pfeffer, Lindsey & Associates, Inc.

Carnegie Mellon University Power Technologies, Inc.

Casazza, Schultz & Associates, Inc. Public Utilities Commission of Ohio

Investor Responsibility Research Center, Inc. University of Pennsylvania

Acknowledgments

Hellen Gelband

Indira Nair

A. Jenifer Robison

Marybeth Zimmerman

American Public Power Association

Detroit Edison Co.

Edison Electric Institute

Energy Action

Federal Energy Regulatory Commission

Florida Public Service Commission

Great Lakes Electric Consumers Association

National Association of Regulatory Utility

Commissioners

National Governors Association

National Independent Energy Producers

National Regulatory Research Institute

National Rural Electric Cooperative Association

Pennsylvania Power & Light

Potlatch Corp.

Sierra Pacific Resources

Strategic Decisions Group

U.S. Department of Energy, Energy Information

Administration

v
Workshop on Alternative

John Anderson

Electricity Consumers Resource

Council

Jan Beyea

National Audubon Society

Ashley Brown

Public Utilities Commission of Ohio

Mark Cooper

Consumer Federation of America

Charles E. Curtis

Van Ness, Feldman, Sutcliffe & Curtis

Richard Disbrow

American Electric Power Service Corp.

Janice G. Hamrin

Independent Energy Producers of

California

Steve Herod

U.S. Department of

Larry Hobart

Scenarios, Sept. 21,1987

Energy

American Public Power Association

Leonard Hyman

Merrill-Lynch Capital Markets

Gerald M. Keenan

Palmer Bellvue Corp.

Kevin Kelly

National Regulatory Research Institute

Hyde Merrill

Power Technologies, Inc.

Everard Munsey

Dominion Resources, Inc.

Joellyn K. Murphy

Public Service Co. of New Mexico

Jerry Pfeffer

Pfeffer, Lindsay & Associates

Richard Schuler

Cornell University

Fred Schweppe

Massachusetts Institute of Technology

Ian Straughan

Southern California Edison Co.

Andrew Varley

Iowa Utilities Board

William C. Walbridge

Seminole Electric Cooperative

Oliver S. Yu

Electric Power Research Institute

Gene Zeltrnann

General Electric Co.

Workshop on Technology for Increased Competition, Feb. 25-26, 1988

Robert W. Fri, Chairman

Resources for the Future

John Casazza

Casazza, Schultz & Associates, Inc.

Laurel H. Eihusen

A.E. Staley Manufacturing Co.

Fred Ellert

General Electric Co.

Ralph Ferguson

Tennessee Valley Authority

Edward Fowlkes

Federal Energy Regulatory

Commission

Michehl Gent

North American Electric Reliability

Council

Richard E. Hughs

Sierra Pacific Resources

Joseph D. Jenkins William Reinke

Florida Public Service Commission Duke Power Corp.

Ray Maliszewski Ian Straughn

American Electric Power Service Corp. Southern California Edison Co.

Grayson McNair

Pennsylvania Power & Light Co.

Merrill Millet

Deseret Generation & Transmission

Cooperative

Roger Naill

Applied Energy Services

David Nevius

North American Electric Reliability

Council

W. J. Nicholson

Potlatch Corp.

Robert Sullivan

University of Florida

David R. Wolcott

New York State Energy Research and

Development Authority

Allen Wood

Power Technologies, Inc.

Frank Young

Electric Power Research Institute

NOTE: OTA appreciates and is grateful for the valuable assistance and thoughtful critiques provided by the participants in the

workshops. The workshop participants do not, however, necessarily approve, disapprove, or endorse this report. OTA assumes

full responsibility for the report and the accuracy of its contents.

vi
Contents

Chapter Page

Overview . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . viii

1.

2.

3.

4.

5.

6.

7.

8.

Introduction and Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3

An Overview of the Changing Electric Power Industry. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35

Alternative Scenarios for Increasing Competition in the Electric Power Industry . . . . . . . . . 61

Power System Technology . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 91

Technological Requirements and Performance Under Increased Competition . . . . . . . . . . . . 125

Regional Characteristics of the Electric Power Industry . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 155

Siting, Environmental, and Health issues Associated With Increased Competition and

Expanded Transmission Access . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 201

Public Policy Issues and Legislative Strategies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 245

Appendixes Page

A.List of Acronyms and Terms . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 263

B, Contractor Reports . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 265

vi/
Overview

Competition has been proposed as a mechanism to reduce costs and improve decisionmaking in the

heavily regulated electric power industry. Some elements of competition are already appearing. However, the

technical characteristics of electric power systems, and deficiencies in data and analysis of the requirements

for planning and operation under competition, result in uncertainty over the costs and benefits. In particular,

changes affecting the transmission system could cause major reliability and cost problems unless introduced

carefully.

Concerns that the bulk power system (generation and transmission) is inherently incompatible with

competition do not appear to be well founded. The system can be made to work under any of the

institutional/regulatory arrangements considered in this study. Problems and issues will arise with widespread

competition, but they will be much less technical than political and institutional.

The greatest challenge will be to maintain the coordination of the bulk power system as an integrated

whole when many different entities are involved. At present utilities (or groups of cooperating utilities) control

the output of all their generating plants to ensure reliability and lowest possible cost for the constantly changing

demand, considering the availability of transmission capacity. If competition is to be successful, it must find

a way to provide the same services that utilities now perform internally. The solution will depend more on

measures to define responsibilities and ensure adequate information sharing than on hardware modifications.

competition is not a single concept. The term encompasses a variety of proposed changes. The major

potential mechanisms are increasing competition among generating companies for the sale of their power, and

expanding access to the transmission system so that this power can be wheeled to different customers. The

various proposals differ largely in the rapidity of introduction and eventual extent of change in these two

themes.

The costs, benefits, and impacts of competition are very uncertain. Actual experience is limited, and little

analysis has been performed. The benefits from competition are speculative and difficult to quantify,

particularly from a national perspective. Rapid change will entail the greatest risks, and special attention will

have to be paid to developing appropriate institutional safeguards. Key data, such as the amount of wheeling

going on now and the amount of nonutility generation, is not being collected in useful form.

If implemented unwisely, competition easily could result in higher costs and lower reliability because

crucial functions such as economic dispatch would not work as effectively. Success is likely to depend on how

competition is implemented, both for the Nation as a whole and for individual transactions.

Some elements of competition are already being implemented. Several States are initiating bidding

procedures to allow nonutility companies to compete to supply new generating needs at the lowest possible

cost. Bulk power sales between utilities have been substantial for many years. Interest in such sales among

utilities, independent generators, and consumers is increasing.

The environmental impacts of competitive generation will depend on how it is implemented. Competitive

generators might select different fuels and technologies than would utilities, which would result in different

environmental impacts, but this cannot be predicted confidently. In addition, there has been increasing concern

over the health impacts of the electric and magnetic fields associated with transmission lines. These impacts

cannot be confined at this time, but neither have they been disproved.

If policymakers choose to encourage competition, modifications to the Federal Power Act, the Public

Utility Regulatory Policies Act and the Public Utilities Holding Company Act could remove disincentives to

bulk power competition and increased wheeling. In addition, several technical and institutional changes could

help ensure that the electric power system operates reliably and economically. Many services that utilities now

provide internally will have to be arranged by contract, which will require precise definition and evaluation.

Detailed data collection and analysis could identify risks to be avoided as competition is implemented. State

and Federal regulatory bodies may require increased expertise to handle complex issues.

viii
Chapter 1

Introduction and Summary
CONTENTS

Page

INTRODUCTION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Background . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Future Concerns . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

A MORE COMPETITIVE ELECTRIC POWER INDUSTRY . . . . . . . . . . . . . . . . . . . . . . . .

Suggested Advantages to Competition . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Suggested Disadvantages to Competition . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Uncertainties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

THE BULK POWER SYSTEM . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

The System Today . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Power System Technology and Requirements

. . . .

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Technical Issues in Competition . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

CHANGE AND THE BULK POWER SYSTEM . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Technical Implications of the Scenarios . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Regional Differences . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Economic and Institutional Impacts

. . . . . . . . . . .

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

SITING, ENVIRONMENTAL, AND HEALTH ISSUES . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Siting . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Environmental Impacts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Health Effects . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

POLICY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Maintaining Reliability and Economy of Operation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Better Information and Analysis for Public Decisionmaking . . . . . . . . . . . . . . . . . . . . . . .

Expanding Competition—Institutional and Public Policy Issues . . . . . . . . . . . . . . . . . . . .

Box

l-A. Electric Power Systems . . .

l-B. Coordinated Operations and

Figure

1-1. A Electric

Boxes

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Planning . . . . . . . . . . . . . . . . . . . . . . . .

Figure

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

3

3

5

6

6

7

7

9

9

12

15

20

22

23

24

25

25

25

26

27

27

29

30

Page

. . . . . . . . . . . . . . . . . . 10

. . . . . . . . . . . . . . . . . . 16

Page

. . . . . . . . . . . . . . . . . . 11

Table

1-1. Characteristics of the Nine Electric Reliability Council Regions

1-2. Technologies to Increase Transfer Capability . . . . . . . . . . . . . . . . .

1-3. Operation and Planning Functions . . . . . . . . . . . . . . . . . . . . . . . . . . .

1-4. Summary of Alternative Scenarios . . . . . . . . . . . . . . . . . . . . . . . . . . .

Page

. . . . . . . . . . . . . . . . . . 13

. . . . . . . . . . . . . . . . . . 14

. . . . . . . . . . . . . . . . . . 17

. . . . . . . . . . . . . . . . . . 21
Chapter 1

Introduction and Summary

INTRODUCTION

The electric utility industry is facing unprecedented changes. Problems of the past and

uncertainties in the future are prompting an

examination of alternative ways to manage the

Nation’s electric power systems. A major focus

of this search is competition—revising the

regulation that has controlled most aspects of

electric utilities to make better use of market

forces. However, competition itself raises a host

of questions: how can it best be applied to the

electric utility industry? what has to be done to

make the electric system work under these

arrangements? how would reliability and costs

compare to the present system? can the transmission network handle increased transfers of bulk

power? This assessment explores the technical

requirements for introducing greater competition into the operation and planning of the

electric power industry, with particular emphasis on reliability and operation of the transmission network.

Competition is not a single concept. It can be

applied in different ways that have quite different implications. This assessment considers two

major mechanisms: competition among generators to supply electric power; and expanding

access to the transmission network for wheeling

of bulk power from seller to buyer. Competitive

generation can be introduced without providing

access to transmission, but it is likely that any

significant move toward competition would

include some degree of both.

Background

For nearly a century, regulated utilities have

provided most electric power in the United

States. These utilities generate or buy the power

needed in their assigned service areas and

deliver it to their customers via long-distance

transmission and local distribution networks.

They also plan for future growth and build

needed facilities. Regulators review costs and

set the rates utilities charge customers. Until the

early seventies, this system appeared to work

well: the supply of electricity was reliable, and

each new plant contributed to lower costs.

The energy crisis of 1973 and subsequent

economic problems brought rapid and painful

change to the electric utility industry. Fuel

prices and construction costs of new power

plants, particularly nuclear, rose dramatically

during this period due to a combination of

factors—the OPEC oil embargo, increased environmental and safety requirements, high interest

rates, intentional construction stretchouts due to

lack of need, and poor management in some

cases.

Higher fuel and capital costs meant higher

electricity costs, and utilities sought substantial

rate increases. Customers responded by using

less electricity, a reaction that most utilities

underestimated at first. In addition, some consumer uses, such as major residential appliances, started approaching saturation. Many

large industrial users of electricity, such as

aluminum and bulk chemicals, experienced

declines in domestic production due to foreign

competition. In addition, some manufacturing

companies and other large electricity users

found they could save money by generating their

own power, usually in conjunction with the

production of process steam (cogeneration),

further depressing demand for utility power.

Growth rates of overall national demand plummeted from 7 percent per year to less than 2.5

percent by 1980 (with considerable regional

variation). Reductions in construction programs

lagged the drop in demand, and many utilities

developed considerable excess capacity.

As utility costs of production increased, State

regulatory commissions scrutinized utility expenditures much more closely, especially the huge

construction cost escalations for nuclear plants.

- 3 -
4 ● Electric Power Wheeling and Dealing: Technological Considerations for Increasing Competition

In some cases, regulators determined that plants

were unnecessarily expensive or that the generating capacity was not needed and did not allow

the utility to charge customers for the entire cost.

Perhaps the most critical legacy of the 1970s

is uncertainty in electricity demand growth.

After 1972, not only did the average annual

demand growth rate drop to less than a third of

that of the previous decade, but the year-to-year

changes became less predictable as well. Users

of electricity often are able to switch rapidly to

other energy forms or improve the efficiency of

their use. However, rapid demand growth continues in some sectors, such as space conditioning for commercial buildings, industrial process

heat, and electronic office equipment. As

growth has become less predictable, utility

planning has become more complex.

The last 15 years have been difficult for many

utilities, several having come close to bankruptcy, and have greatly raised costs for their

customers. Since about 1983, however, most

problems seemed to have waned. The cost of

producing electricity has leveled out (and even

declined in some areas) as fuel prices dropped

and costly construction programs were phased

out. Demand has risen, and surplus capacity has

been utilized.

Despite a substantial return toward financial

health, some problems have left permanent

changes. The trend toward large, capitalintensive power plants seems to have ended, at

least for the time being, for a variety of reasons

including uncertainty over future demand and

concern over potential cost disallowances by

State regulatory commissions.

The Public Utility Regulatory Policies Act of

1978 (PURPA) has also had a major industry

impact. Among other things, PURPA was intended to encourage construction of nonutility,

generating units by requiring utilities to purchase power produced by qualified facilities

(QFs).l Despite a slow start due to economic

uncertainties and legal challenges, the number

of QFs has grown rapidly. Many cogeneration

and alternative energy facilities appearing since

1978 have been a result of PURPA. The Act has

also inspired a growing interest in independently owned, but otherwise conventional power

stations, which would sell their output to utilities or even directly to other customers, perhaps

using a utility’s transmission system for the

delivery.

Several States have already initiated procedures to further promote nonutility generation,

sometimes with the active encouragement of

their utilities. Utilities in need of new generating

capacity can request proposals in a competitive

bidding process and then contract with other

utilities, cogenerators, or independent power

producers (IPPs). In 1988 the Federal Energy

Regulatory Commission (FERC) proposed

changes to regulations to promote competition

in bidding and independent power production.2

Cost differentials between utilities are also

fostering change. Some utilities are able to sell

excess power at low prices. Other utilities have

taken advantage of such opportunities for many

years. Large industrial consumers and municipal electric distribution agencies in high cost

areas also are seeking to purchase lower cost

electricity directly from distant utilities. Such

efforts often conflict with interests of the local

utility, which doesn’t want to lose customers

lp~pA CnWWages idtemative energy and high efficiency cogeneration through special regulatory treatment. Power from QFs must ~ Pwhti

by the local utility at a price not to exceed the cost that the utility would have incurred to generate the same power. ‘llese limits have been set

administratively by State utility commissions, and there has&n considerable controversy over whether avoided costs have been set at levels too high,

encouraging too many QFs at consumer expense, or too low, discouraging innovative development. FERC has proposed a rule approving the use of

competitive bidding as a means of determining avoided costs under State regulatory programs.

2Notices of ~P~ R~em~ng: Docket No, RM88-4, Regulations Governing Independent Power Rockers; Docket No. RM88-5, Re@ations

Governing Bidding Programs; Docket No. RM88-6, Administrative Determination of Full Avoided Costs, Sales of Power to Quali&ing Facilities, and

Interconnection Facilities; Mar. 16, 1988.
Chapter l-Introduction and Summary ● 5

and may refuse to supply transmission services,

or wheeling, for power produced by other

parties.

Change is also occurring in other countries. In

particular, the British Government is introducing competition into its generation and transmission system through a radical privatization of its

presently government-owned monopoly. This

situation is quite different, but it may well

provide some useful

states.

Future

All these factors

lessons for the United

Concerns

suggest that change is

inevitable for the electric utility industry. However, there are many different views on what the

appropriate changes should be. To a large

extent, partisans of each perspective in the

debate are motivated by self-interest. The stakes

are large for many of the players. From the

perspective of those trying to maximize benefits

for the Nation as a whole, the issues are more

ambiguous.

The primary argument advanced for policymakers to take some action, whether involving

competition or another approach, is that the

present institutional and regulatory structure

seems unlikely to produce the lowest possible

costs for consumers. Some people believe that

the problems are too systemic to be addressed by

adjustments in the existing regulatory approach:

that utilities lack sufficient incentive or ability to

control construction costs and operate as economically as possible. Prior to the disallowances

of recent years, costs and savings generally were

simply passed on to customers, with little

reward to the utility for excellent performance or

penalty for inefficiency. According to these

arguments, competition could help ensure that

the lowest cost facilities are built and operated

efficiently, and that customers would always

have access to the lowest cost power available,

no matter who generated it.

Others believe that the problems of the past

were one-time events, not likely to be repeated,

and that the present regulatory structure can be

adjusted to handle any future problems. In fact,

some holders of this perspective believe that no

competition should be introduced; that unique

characteristics of the electric system mean that

competition is likely to raise costs and lower

reliability.

One of the key elements of the debate is over

new construction to meet future needs. Some

observers are concerned that under the present

regulatory environment utilities will jeopardize

future reliability and cost control by failing to

construct needed facilities or building only

plants with the lowest possible capital cost, such

as oil- or gas-fired turbines, which often have

high operating costs. Others are concerned that

capital minimization is exactly the choice that

most competitive generators would select. If

new generating plants rely primarily on gas-or

oil-fired turbines, and if the prices of those fuels

rise sharply as they have several times in the

past, electricity could become significantly more

expensive. Under some conditions, large coal or

nuclear plants could still produce the lowest cost

power.

3 Policymakers may wish to consider

revisions to regulations so that utilities can

confident] y build whatever facilities are deemed

least expensive overall for their customers, or

encourage competitive entities to build these

facilities. However, the choice of fuels for future

generating stations and their national energy and

environmental policy ramifications are beyond

the scope of this study.

3Nuclear ~d ~o~ ~lant~ have low fuel co5~s c~p~d to gas- ad Oil-fired plats. If their capital costs are not too high, tk fuel cost advantage can

result in lower overatl cost per kilowatthour. At the moment, this is probably genera[ly not the case. Oil and gas prices are not much higher than coal

though gas prices are climbing. Future competitiveness for nuclear and coal will depend on holding capital costs down as well as renewed increases

in oil and gas prices. Despite the spectacular capital cost increases in the seventies, this appears possible. Some of Ihc factors driving those increases were

peculiar to the times (20 percent interest rates and construction delays due to plummeting dcmand). Others were one-time increases that would not continue

pushing prices up (strengthening inadequate safety and environmental controls). Thus it should not be assumed that the experience of the pm is

necessarily indicative of the future.
6 ● Electric Power Wheeling and Dealing: Technological Considerations for Increasing Competition

Another concern is that increased competition will be hindered by existing laws and

regulations. Pressure for more competition is

increasing and some elements are already being

introduced. If Congress chooses to encourage

competition, legislation and oversight of regulation is likely to be necessary to allow full

implementation.

It is also of concern that change could occur

too rapidly. If competition is implemented with

little testing and analysis, the economics and

reliability of the system could be threatened.

Therefore, policymakers may have to guide the

process of change to ensure that it follows

constructive channels.

A MORE COMPETITIVE

ELECTRIC POWER INDUSTRY

Interutility sales have long comprised a form

of competition in generation as utilities with

excess capacity competed to sell power to those

that needed additional power. Typically these

interutility transactions benefited all parties and

encouraged efficient operation.

Measures to increase competition can range

from minor changes in regulatory standards and

bulk power procurement practices to a major

reorganization of the industry: separating generation, transmission, and distribution into separate companies. The efforts by several States to

expand market opportunities for utilities to

procure new supplies of power is one form of

competitive generation.4

Expanded access to the transmission system

would increase competition by permitting (when

possible) generating companies to deliver power

to customers other than the local utility. The

widened market increases opportunities available to independents and also to utilities with

excess power to sell.

Competitive generation and transmission access can be combined. In the extreme, generating companies or any entrepreneur could build

a power plant and sell output to any retail or

wholesale customer at a mutually agreed on

price, much as the natural gas industry operates.

Purchases by a regulated distribution company

might still be subject to regulatory review, but

generating company costs and operations would

be increasingly subject to market discipline.

Under such conditions, transmission companies

could even act as common carriers, available to

any party wishing to arrange delivery of bulk

power.

Increased competition, of whatever form and

degree, is likely to have significant implications

for consumers as well as for existing utilities and

new entities in the industry. The following

sections summarize arguments for and against

competition as it might affect consumers of

electric power. Major uncertainties behind these

arguments are also identified.

Suggested Advantages to Competition

Some proponents of increased competition

in the electric utility industry suggest that it

will ensure the lowest possible costs for

customers. They believe it would provide

incentives for utilities and other generators to

improve the operating efficiency of existing

plants and control capital costs of future plants.

Large differences in construction and operating

costs of similar plants indicate that considerable

savings are possible if competition can motivate

or replace the more poorly performing utilities.

Expanding the ranks of generating companies

could reveal attractive opportunities not available to utilities. Entrepreneurial generators might

also be able to use lower cost financing techniques (e.g., greater use of debt relative to equity

than is normal utility practice). Competitive

generators could prove more innovative be4C~jfo~a, colm~o, ComWticut, M~ne, Mm~hu~(ts, ad New York have forma]ly adopId utility bidding programs for new f.wwer suppties.

Another 17 States are implementing or considering such a step. Virginia has implemented bidding without a formal program.
Chapter I-introduction and Summary ● 7

cause, unlike utilities, they get to keep the

reward if a gamble pays off.

Some risk would also be shifted from utilities

and their rate payers to competitive generators.

For instance, if costs did get out of control on a

construction project, the cost of power could

still be fixed by contract terms.

Transmission access might also reduce regional cost differentials by increasing bulk

purchases by higher cost utilities from lower

cost suppliers with excess capacity. Bulk power

sales over long distances may forestall expensive new construction in regions that are growing rapidly while providing economic benefits

in regions that have considerable excess capacity.

Proponents also point to precedents in the

deregulation of other industries, such as natural

gas pipelines, airlines, trucking, and telecommunications.

Suggested Disadvantages to Competition

In some ways, the present system works well.

Utilities determine the need for power, the most

economical choice to produce and deliver it, and

how to ensure its reliability. This integrated

approach enables utilities to optimize the entire

system. Even if competitive generators can

operate more economically than utilities, longterm system economics also depend on how well

individual components work together. Not only

are many individual utilities vertically integrated, but close coordination among utilities

enables them to share generation and transmission to minimize costs and improve reliability.

While some utility performance has been less

than ideal, separating a system’s mutually

dependent areas of decisionmaking may introduce a different kind of inefficiency that

could be costlier than that intended to be

addressed by competition.

Opponents also note that many problems

(such as overbuilding and construction cost

overruns) that have led to interest in competition

can be (or already have been) addressed within

the present institutional/regulatory structure.

The threat of disallowances for imprudent

investments is a powerful incentive to control

costs, and there is no inherent reason why

utilities could not use the same financing

techniques as nonutility generators. In addition,

risks to consumers are not necessarily lessened

when utilities buy instead of build, because the

utilities will have to sign long-term contracts for

purchased power. If the utility guesses wrong on

its power needs, a contract could, depending on

its terms, prove as inflexible as a construction

program.

The present industry also supports research

and development, for example, at the Electric

Power Research Institute. Further, utilities often

collaborate in demonstrating new technology

and share information on improvements. Competing companies have less incentive to cooperate to this degree, and it is questionable how

much joint R&D will continue. Similarly, utilities have fostered emerging technologies that

they believed to be in the national interest but

that entailed considerable initial economic risk.

Competitive generators may be less likely to

take such a long-term perspective.

Uncertainties

One notable feature of the debate over

competition is the lack of data and analysis.

Experience with competition in the electric

power industry has been limited, and much has

not been relevant to a situation where competitively procured supplies represent more than a

small part of the whole. For the most part, the

advantages and disadvantages discussed above

are speculative.

We do not know how much more efficiently,

if at all, nonutility generators can build and

operate power plants. Nor do we know how

much more difficult it will be to plan and operate

a bulk power system that incorporates increasing competition among generators and expands

access to the transmission system. Thus we
8 ● Electric Power Wheeling and Dealing: Technological Considerations for Increasing Competition

Photo Credit: Casazza, Schultz & Associates. Inc.

Three extra high voltage lines share a single right of way

cannot say whether economic gains induced

by competition outweigh additional costs.

Maintaining reliability under competition

also poses uncertainty. Most of us take the

reliability of electric power for granted, but it

doesn’t happen by accident. It has required

investments in equipment and manpower and

emergency assistance to other utilities that at

times have gone beyond legal requirements.

Utilities have a deeply engrained ethos that

interruption of service should be minimized.

The operating availability of nonutility generators to date is at least comparable to that of

utilities (the owners have incentive to stay on

line because otherwise they don’t get paid), and

appropriate reliability requirements can be built

into contracts. However, system reliability is as

yet untested for a situation where a large

proportion of components are operated under

contract rather than under direct ownership of a

utility committed to meeting demand under all

conditions.

Increased access to transmission should facilitate transfers of bulk power, but the growth

that would result is uncertain. Bulk transfers

have increased as utilities took advantage of the

availability of lower cost power. More such

transfers might be advantageous, but more

analysis is required of where these transfers
Chapter l-introduction and Summary ● 9

would take place, what factors are hindering

them, or what their value would be.

Pricing and equity questions will be crucial to

successful implementation of competition. Pricing policies will guide the operating and planning decisions made by buyers, sellers, and

transporters, which will determine whether increased access to the transmission system actually allows a more efficient pattern of bulk

power transfers. Contentious equity issues will

emerge if some groups seem to benefit at the

expense of others. For instance, large industrial

customers could bargain for low rates, leaving

those who lack that option (e.g., residential

users) with much higher costs. In addition, if

utilities are broken up into generating, transmission, and distribution companies, the transfer of

the value of existing assets (which maybe worth

much more than their depreciated book value)

will be controversial.5

As already noted, future fuel choices have

vital national energy implications, but it is not

clear what technologies or fuels either utilities or

nonutility generators are likely to prefer, in part

because long-term economics are not clear.

National energy choices may require fuel shifts,

for instance to avoid gas and oil shortages or

reduce emissions of carbon dioxide because of

the greenhouse effect. If responsibility for

generation has diffused among a large number

of independent power producers, the effectiveness of policy changes will be less predictable.

Another question is on end-use efficiency

improvements. Many institutional barriers hinder otherwise economic investments to improve

efficiency of end-use. For example, consumers

often lack information on the availability and

advantages of high-efficiency appliances. At

present, utilities have some incentive to help

their customers with these investments in order

to avoid building expensive, new generating

facilities. The impact on efficiency of use

depends largely on how competition is implemented. Increased competition may improve

price signals, which would improve consumer

decisions, and bidding programs can include

demand-side management investments. However, competition could also eliminate utility

interest in overcoming noneconomic barriers to

efficiency gains. A strong emphasis on increasing the efficiency of electricity use could reduce

the need for new construction. A full analysis of

the costs and benefits of a Federal program

focused on efficiency gains as a means of

optimizing the value of electricity to society was

beyond the scope of this project. However, the

report notes the impact on demand management

of policy initiatives for implementing competition.

This assessment has not identified any

specific reason why competition cannot be

made to work well, but insufficient analysis

has been done to determine whether benefits

outweigh costs overall. It is clear that there

are ways of implementing competition that

would work very poorly. There are many

pitfalls that must be avoided.

THE BULK POWER SYSTEM

The production and delivery of electric power

is extremely complex, both physically and

institutionally. This characteristic of the system

will largely determine how competition can be

introduced and its success. Box 1-A presents the

basic concepts of the electric power system. The

bulk power system consists of the generation

and transmission sectors. Distribution networks

receive power from the transmission system for

retail delivery to customers.

The System Today

The industry consists of over 3,200 entities

supplying power to over 100 million residential,

commercial, institutional, and industrial customers. Most electricity (76 percent) is supplied

s~e~tlon~ of fisk ~d equity we cfillc~ly impofi~[ to the acceptance of competition, but they We not ~~Yz~ in his st~Y ~au~ ~eY we not

directly related to the technology.
10 ● Electric Power Wheeling and Dealing: Technological Considerations for Increasing Competition

Box I-A—Electric Power Systems

An electric power system is comprised of: generating units that produce electricity; transmission lines that

transport electricity over long distances; distribution lines that deliver the electricity to customers; substations that

connect the pieces to each other; and energy control centers to coordinate the operation of the components. Figure

1-1 shows a simple electric system with two power plants and three distribution systems connectedly a transmission

network of four transmission lines.

Fossil fuels, nuclear fission, and falling water are commonly used energy sources in the electric generators.

A wide and growing variety of unconventional generation technologies and fuels also have been developed,

including cogeneration, solar energy, wind generators, and waste material.

Generators typically produce 60 cycle/second (Hertz or Hz) alternating-current (AC) electricity with voltages

between 12 and 30 thousand volts (kV). The frequency of all generating units on a system must be precisely

synchronized. Generating units have automatic voltage regulators, which control the unit’s voltage output, and

speed governors, which adjust power output in response to changing system conditions, In addition to the real

power that lights lamps and drives motors, an inescapable companion of alternating current, called reactive power,

or VARs, must be monitored and controlled to maintain voltage.

Transmission lines carry electric energy from the power plants to the distribution systems. Most transmission

in the United States consists of overhead AC lines designed to operate at a specific voltage between 69 and 765 kV.

Power transformers raise the generator voltage to the transmission voltage and back down to the distribution

network level (typically under 35 kV) at the other end. There are some segments of direct current transmission and

underground cables for special applications, but these are less common than overhead AC lines.

An interconnected group of individual transmission lines comprises a transmission system. Virtually all

electric utilities in the continental United States are connected to neighboring utilities through one or more lines of

a transmission system.

Coordinated operation of the power system components is implemented through institution of control areas.

A control area is a geographic region with an energy control center (ECC) responsible for operating the power

system within that area. One or more utilities may make up a control area. The control area in figure 1-1 is

interconnected to two neighboring control areas through transmission lines.

Energy control centers employ a variety of equipment and procedures: monitoring and communication

equipment called telemetry to constantly inform the center of generator output and system conditions;

computer-based analytical and data processing tools which together with engineering expertise specify how to

operate generators and transmission lines; and governors, switches, and other devices that actually control

generators and transmission lines. The control center equipment and procedures are typically organized into three

somewhat overlapping systems which are sometimes integrated in a full energy management system (EMS). They

are the automatic generation control (AGC) system which coordinates the power output of generators; the

supervisory control and data acquisition (SCADA) system which coordinates the transmission line equipment

and generator voltages; and an analytical system to monitor and evaluate system security and performance, and plan

operations.

by the 203 investor-owned utilities that generate area. Publicly owned utilities (Federal, State,

the power they need, deliver it to their load and local) and consumer cooperatives also

centers over high-voltage transmission lines, generate electricity (24 percent).

and distribute it to their customers. Most of

these utilities are vertically integrated, owning Nonutility generators (NUGs, including any

or controlling all the generation, transmission, producer of electricity not functioning as a

and distribution facilities required to meet the public utility) are important in some regions and

needs of the customers in their assigned service are starting to become a significant national
Chapter l-introduction and Summary ● 11

Figure l-l—A Simple Electric System

Energy Interconnect ion

control center

Power PIant/substation

Interconnection

Distribution system

 Distributio n

Distribution system system

SOURCE: Office of Technology Assessment, 1989.

factor. Statistics on NUGs are uncertain, but

they appear to own about 25,000 megawatts

(MW) of capacity out of a total of over 700,000

MW in the Nation.

The transmission system allows a utility to

build a generating station wherever appropriate

and deliver power to the load center, sometimes

hundreds of miles away. In addition, it links

utilities so that they can back each other up

during emergencies and transfer power when it

is economically advantageous to do so. The

latter is normally accomplished by contract

between utilities, specifying the power (megawatts), voltage, and the time period of the

transfer, among other things. Transfers for

economic purposes have become common in

recent years.

The bulk power system is a combination of

generating units and transmission lines that

must be operated as a coordinated system.

This requirement has governed the institutional

evolution of the industry as well as the development of its physical system. The addition of

nonutility generation to the system must be

understood in this context.

In particular, the industry has developed an

unusual level of cooperation among private

companies as well as government agencies. All

large utilities in the 48 contiguous States are

members of one of nine regional reliability

councils that form the North American Electric

Reliability Council (NERC). NERC, through

the utilities, issues standards and operating

guidelines to improve overall coordination of

utility procedures in the United States and
12 ● Electric Power Wheeling and Dealing: Technological Considerations for Increasing Competition

Canada and parts of Mexico. The regional

councils coordinate planning and operations and

exchange information on electricity demand and

reliability. Table 1-1 describes the nine regional

councils.

Some utilities have also formed ‘‘tight”

power pools, which involve a high level of

coordination and a central dispatcher to ensure

the use of the most economic mix of generation

throughout the pool. New England and New

York are each essentially a single “control

area. ” The Mid-Atlantic Area Council coincides with a single pool in addition to being a

regional reliability council. Tight pools maximize the use of low-cost generation and minimize new construction and the cost of maintaining reserve capacity. Other utilities have formed

“loose” pools to coordinate planning but with

no contractual reserve requirements. In addition,

several holding companies (e.g., American Electric Power) coordinate the activities of their

subsidiary utilities as power pools. Utilities also

make bilateral arrangements, and brokers match

buyers and sellers of bulk power, usually for

short periods of time.

In addition to pools, most utilities belong to

an interconnected network, the largest operating

unit. There are three such networks in the United

States: the Eastern Interconnection (which extends nearly to the Rocky Mountains), Texas

Interconnection (only in Texas), and the Western Interconnection. Within each of these three

systems, all connected generators must be synchronized. Connections between two networks

are accomplished through direct current interties

to avoid synchronization problems.

Power System Technology and

Requirements

The bulk power system (described in box

l-A) must be designed and operated according

to certain physical principles of electricity. In

particular, two key technical factors dictate

many features of the bulk power system. First,

electricity flows at nearly the speed of light

with virtually no storage of power in the

system: electricity must be generated as it is

needed.6 Automatic generation control (AGC)

coordinates the operation of generators moment

by moment to balance supply with demand.

Control is maintained by individual utilities or

by pools of interconnected utilities. There is

usually a choice of generators to be turned up or

down to meet changes in demand, each with

individual cost and operating characteristics.

Utilities spend considerable effort implementing “economic dispatch, ” or ensuring that the

mix of units operating at all times represents the

least-cost combination. They also must ensure

that generating units will be ready when needed

to follow the daily load cycle, that the transmission system is capable of carrying the loads, and

that backup generating and transmission capacity is available in case of equipment failure.

Second, every flow of power from a power

plant to a distribution system affects the

entire transmission network, not just the

most direct path. Electricity cannot be simply

loaded onto a convenient transmission line and

delivered, as trucks use the interstate highways

to deliver products. If one utility sells power to

another, they both must ensure that no components are overloaded on any of the paths

available. The network connects many different

utilities, and lines hundreds of miles away carry

part of the load, a phenomenon called parallel

path flow. Such flows can reduce the power that

other utilities can place on their own lines. In

some cases, a line may already be fully loaded,

and the new power flow would overburden it.

Therefore, the overall system’s transfer capacity

is constrained by the single most limiting

transmission line.

Total system capacity is considerably less

than the sum of the capacity of all lines in it. In

bw@ hydroe]ec~c f~i]i(ies SLOE energy but not cled.ricity. In effect, the system sees them as generating StiitiOnS. ~velopment of eCOnOrnlC

battery or magnetic storage tedmology for use within the distribution systcm could have important advantages for the electric power system.
Chapter I----Introduction and Summary ● 13

7

co

0

-
14 ● Electric Power Wheeling and Dealing: Technological Considerations for Increasing Competition

addition to individual line constraints, the system imposes its own limitations because of

reliability and stability concerns. Utilities generally operate the system with reserves sufficient

to handle rapid shifts in power flows that occur

when a transmission line or generating unit fails.

The capacity of the transmission system is not

a fixed, exact limit that balances the utility’s

costs of providing reliability with the consumer’s benefits of uninterrupted service. Rather, capacity is defined by utilities from operating practices and from trade-offs among several

factors, including the operation of generating

units as well as transmission lines. Capacity also

varies over time, depending on factors such as

air temperature. Determining whether an additional transfer can be accommodated often

requires considerable engineering expertise, data,

and analysis, and it is possible for different

analysts to arrive at opposite conclusions.

Determining how to increase capacity is also

complex. The system can be upgraded by

increasing the capacity of individual lines;

improving control of flows on the network; and

adding new circuits. Table 1-2 lists technological options available to overcome specific

limitations. Costs and benefits of implementing

most of these options are highly site specific.

A variety of constraints can account for the

capacity limit for any specific line. Lines can

overheat with too much current, or high voltage

can cause arcing in equipment. The limit also

depends on a line’s specific configuration, its

relation to the rest of the system, and variables

such as air temperature.

Improved control over the flow of power can

increase capacity by bypassing constraints. Adjusting power output of generators on the network

can maximize flow (but this can also result in

noneconomic dispatch) and improving generator response times can reduce transmission

reserves required in case of equipment failures.

Phase shifting transformers, which act as valves

to control individual flow, are gaining popularTable 1-2—Technologies to Increase

Transfer Capability

Remedies to individual line constraints

Voltage uprating

Tower extensions

Upgrading insulators

Upgrading terminal equipment

(circuit breakers, relays, transformers)

Current uprating

Dynamic conductor rating

Sag assessment and monitoring

Restringing (live-line restringing)

Changing operating standards

Tower design and new lines

Conversion to multiple circuit towers

High-voltage direct current lines

Remedies to steady state system operating constraints

Control of load division

Phase angle regulators

Series reactance and capacitance

System reconfiguration

HVDC control features

Redispatch of generation

Reactive power management techniques

Shunt or series capacitors

Shunt reactors

Static VAR compensators

Synchronous condensers

Generators as VAR sources

Remedies to contingency security and stability constraints

Improving generation response controls

Generator tripping and fast runback

Fast valving

Braking resistors and load switching

Advanced excitation systems and stabilizers

Transient excitation boost

Improving transmission response controls

High-speed reclosing and reducing clearing time

Rapid adjustment of network impedance

Fast acting phase angle regulators

Sectionalizina (adding switching stations)

SOURCE: Adapted from “Technical Sackgmund and Considardons in Proposed

Wheeling, Transmission Acuma, and Non-Utility Generation,” contractor

report pmparad for the Oftica of Technology Assessment, by Power

Technologies, Inc., March 1966, p. 6-2.

ity. Transmission limitations can also be alleviated by control of reactive power.

When large increases in capacity are required,

it generally is necessary to add high-voltage

lines. Not only can these lines carry large

amounts of power, but they can raise the

capacity of other lines if they eliminate constraints. The use of high-voltage direct current

(DC) lines is increasing, even though consid-
Chapter l---lntroduction and Summary ● 15

erable investment in conversion facilities is

required at both ends, because control of direct

current is much simpler than alternating current,

and the lines themselves are cheaper.

Three R&D programs have the potential for

significantly changing the electric power system. High-power semiconductors are already

being applied to reactive power control, and

further development may lead to switches for

controlling power flow and to less expensive

AC/DC conversion. Second, developments in

computing and data processing techniques,

including artificial intelligence and supercomputers, should have several applications for

power systems, such as optimization of operations and power plant diagnostics and monitoring. Finally, in the long term, superconducting

materials could improve the economics of the

power system not necessarily in the transmission cables themselves but in generators, line

control devices, and electric storage technology.

Technical Issues in Competition

The greatest challenge to increasing competition in generation and expanding transmission access is maintaining the high degree of

coordinated planning and operation among

bulk power system components. If coordination is not addressed with appropriate care,

the system may experience increasing costs

and decreasing reliability. Coordinated planning and operation of generation and transmission are required in performing three basic

functions: following changing load, maintaining

supply reliability, and transactions among utilities and generators, as described in box 1-B. The

key to coordination will be in defining workable institutional arrangements among participants in the power system. Some new

physical facilities and improved analytical

capabilities may be required, but all these

functions can be provided with familiar

technology.

At present, a single utility or group of

cooperating utilities is responsible for system

planning and operations in a control area. As

nonutility generation and transmission access

increase, responsibility for coordinating the

overall power system is separated from ownership of system components. Functions now

routine to utilities would increasingly have to be

unbundled and established by contract or other

agreements among generators, purchasers, and

carriers.

As in today’s power systems, the arrangements may include formal contracts between

parties as well as less formal agreements on

standards and procedures. As unbundling increases, bilateral and multilateral contracts will

be increasingly important instruments to communicate needs and define obligations of suppliers, transporters, and power purchasers. By

specifying prices and performance, including

penalties for failure to perform, contracts can

help ensure that competitive supplies meet

power system needs and mitigate uncertainty for

all parties. However, contracts may have some

shortcomings when compared to arrangements

within a single organization, as in a vertically

integrated utility. For example, given the overall

uncertainty in the power industry, anticipating

all terms and contingencies that a contract

should cover requires extensive effort. Even

with carefully crafted and flexible contracts,

unexpected events outside the scope of the

contract may occur.

How suppliers, purchasers, and transporters

of power will respond to any competitive

proposal is speculative. It is this individual

behavior and how it is coordinated, however,

that determines the real feasibility, reliability,

and economic impact of increased competition

in the electric utility industry. This study has

identified no insurmountable problems of technical feasibility, although there are some substantial institutional challenges in developing

new planning and operating arrangements. The

ease or difficulty of implementing the institutional changes to meet technical requirements is,

again, necessarily speculative.
14 ● Electric Power Wheeling and Dealing: Technological Considerationsfor Increasing Competition

Box l-B-Coordinated Operations and Planning

An electric power system is composed of many interacting electrical and mechanical parts. Because of the

complex and nearly instantaneous interactions between the components, their operation and planning must be

carefully coordinated. For example, a decrease in output of one generator instantly changes power flows and

voltages across the system, automatically causing other generators to increase their output. This could result in

overloads or unacceptable voltages if not properly coordinated.

Coordinated operation and planning involves several procedures, ranging from moment-to-moment

coordination of generator power and voltage output, to long-term planning and addition of transmission and

generation. Together, these procedures control generation and transmission to perform three basic functions:

following changing loads; maintaining supply reliability: and coordinating transactions between utilities (see

table 1-3). These functions are performed in a way that seeks to minimize cost.

Following Load

Consumer demand for electricity changes continuously and somewhat unpredictably. Some changes tend to

repeat cyclically with the time of day, day of week, and with the season. Others result from the vagaries of weather,

economic conditions, and from the random turning on and off of appliances and industrial equipment.

Following load involves preparing generators for operation (e.g., warming them up) under unit commitment

schedules, which reflect forecasted load changes over daily, weekly, and seasonal cycles plus an allowance for

random variations. Some generators in a unit commitment schedule increase or decrease their power output either

according to a schedule, following predicted loads; others are under automatic generation control (AGC) and

economic dispatch to follow actual loads as required. Voltage control and reactive power devices on the

transmission system and in generating plants are simultaneously coordinated to maintain system voltages as loads

and supplies change.

Maintaining Reliability

From one moment to the next, any generator or transmission line may fail, either on its own or due to external

influences (e.g., lightning strikes). Preparing for continued operation after equipment failure is called maintaining

security. Security is maintained through unit commitment schedules and security constrained dispatch, which

provide reserves of both generation and transmission. Together with the coordinated engineering of relays and

circuit breakers used to isolate failed or overloaded components, they ensure that no single failure will result in

cascading outages.

Ensuring sufficient availability of supplies, called maintaining adequacy, is also essential for reliability. In

addition to unit commitment and economic dispatch for load following and security, maintaining adequacy involves

coordinated maintenance scheduling of individual components and planning new generation and transmission

capacity. Planning new capacity involves selecting the right mix and location of both generation and transmission

to meet the needs of following load and maintaining security.

Coordinating Transactions

Nearly all utilities are interconnected with other systems, allowing for a variety of transactions. Transactions

may take a variety of forms, including purchases and sales with neighboring utilities; purchases from suppliers

within a utility’s service area (e.g., an independent power producer); operation of jointly owned power plants; and

wheeling of power. Except where contrary arrangements are specifically made, it is the responsibility of each utility

to provide the power used by its customers without absorbing power from its neighbors or sending unwanted power

to them. Coordinating transactions involves scheduling and control of generation to implement power transfers, as

well as monitoring and recording transactions for billing or other compensation.

Some believe that in both the short and tion, coordinate planning, and provide backup

long term, competitiveness is likely to be for each other in emergencies. Companies that

detrimental to the cooperation among compa- may be bidding against each other have less

nies that is characteristic of the electrical power incentive to extend this level of cooperation.

industry. Utilities routinely exchange informa- However, it is not clear how valuable this
Chapter I-introduction and Summary ● 17

Table 1-3-Operation and Planning Functions

Function Purpose Procedures involved

Fe//owing load

Frequency regulation Following moment-to-moment load fluctuation

Cycling Following daily, weekly, and seasonal cycles

(within equipment voltage, power limits)

Maintaining reliability

Maintaining security Preparing for unplanned equipment failure

Maintaining adequacy Acquiring adequate supply resources

Coordinating transactions Purchasing, selling, and wheeling power in

interconnected systems

Governor control

Automatic generation control (AGC) and economic

dispatch

AGC/economic dispatch

Unit commitment

Voltage control

Unit commitment (for spinning and ready reserves)

security dispatch

Voltage control

Unit commitment

Maintenance scheduling

Planning capacity expansion

AGC/economic dispatch unit commitment

SOURCE: Adapted from F. Mobosheri, southern California Edison, Iettef to Offkx of Technology Assessment, May 13, 1989.

Photo credit: Cassazza, Schultz & Associates, Inc.

Energy control center
18 ● Electric Power Wheeling and Dealing: Technological Considerations for Increasing Competition

cooperation is or how well contracts could

duplicate actual activities.

Nonutility Generation

Nonutility generators are likely to use familiar equipment and fuels, and suitable controls

for frequency and voltage can maintain output

compatibility. Therefore, the equipment itself

should not create undue problems if planning

and operation are carefully coordinated.

However, it is not certain how difficult it will

be to meet the technical requirements of coordinated planning and operation if competitive

generation becomes widespread. These requirements do not preclude competition, but inattention to them will result in a needlessly unreliable

and high-cost system, and it should be noted that

the costs of meeting several of these requirements are quite uncertain.

Maintaining the efficiency of economic dispatch for load following will be a challenge.

Competitive generating companies may operate

more efficient and lower cost facilities than

regulated utilities, but overall costs could still be

higher if units are not dispatched to minimize

total costs. For example, if generating companies contract directly with customers (retail

competition) for the output of specific machines, then low-cost sources may be idled

while a more expensive but nondispatchable

source operates. Utilities, whether operating

independently or in a pool, try to maximize the

use of the lowest cost units. This interest will not

automatically be duplicated in a system where

many different entities own and operate generating units. To minimize operating costs under

competition, centralized control of dispatch or

other mechanisms to select the lowest cost of

generation must be established. Contracts to

establish control for economic dispatch may

prove to work adequately, but they are likely to

be less flexible than direct control by an

integrated utility.

Maintaining reliability requires nonrevenuegenerating functions such as keeping reserve

units warmed up and immediately available for

emergencies. Downtime for maintenance must

be scheduled to minimize interference with

system operation. Institutional adaptations will

be necessary to perform these functions under

competition. Increased reserve margins may be

necessary to account for the uncertainty in how

well these new institutional relations work. In

addition, new monitoring and communication

equipment may be needed to track and control

the new unbundled transactions.

The costs of unbundling these services under

competition are not yet known. Utilities now can

simply lump the costs of these functions into

their overall operating costs and have no need to

determine exactly what each one entails.

Meeting demand growth with adequate and

appropriate capacity is necessary for long-term

reliability. When utilities are evaluating bids

for new generating capacity, they must not be

forced to accept automatically the lowest

price offered. In the long run, the lowest costs

will result if the bidding process provides an

appropriate mix of operating characteristics. For

instance, power generated to meet peaks usually

costs more per kilowatthour because the plant is

idle much of the time. If bids were to be accepted

purely on price, proposals for nondispatchable

(base load) generators would have a major

advantage, but the bulk power system must have

a large fraction of dispatchable generation to

follow load. Reliability is another key factor

affecting value. A power source that cannot be

counted on because it is intermittent by nature or

unreliable in operation is worth less than a

facility that is almost always available when

needed.

Power system planners are likely to need to

continue specifying the attributes required of

new generating units, including: type of fuel

used; location; and ability to operate for baseload, intermediate, or peak use. Whether a
Chapter 1--Introduction and Summary ● 19

competitive supply market will provide a full

range of desired options and at what cost

remains to be seen. Utilities may remain the

preferred builder or the builder of last resort.

Ensuring that competitive generation will be

completed as planned is another important

challenge. Even with contracts for the right

facilities, there is some uncertainty that the

facilities will actually be completed as required

because the contractor could encounter problems and withdraw. Utilities also can misestimate costs, but they are unlikely to cancel a plant

that is needed to meet their obligation to serve.

Depending on circumstances, either outcome

(cancellation or completion of the plant) could

be correct; institutional arrangements will need

to be designed for flexibility to encourage the

right response. Some possible approaches include specifying liquidated damages for nonperformance and allowing the purchasing utility to

take over an abandoned project. Both reduce the

incentive to abandon a construction project

when faced with some cost overruns, and give

the utility additional resources for acquiring

needed supplies.

One factor that may ease the implementation

of competition is the trend toward smaller

generating facilities close to the load centers.

Small facilities usually entail less uncertainty

over construction leadtime and cost. Not only

are the risks of failure less for small facilities,

but the consequences of individual failures are

minor.

Transmission Access

As the number of players in the electric power

industry increases, demand for wheeling will

increase. Competing generators will want to sell

to whomever will pay the most, whether that is

the local utility or a distant customer, and some

consumers will want to shop for supplies. In

either case, they will require transmission services. Some proposals would require a transmission company to wheel for any and all customers

unless it can show that it would be infeasible, for

instance if their system has” no additional

capacity. There would be established a rebuttable presumption that transmission service could

be provided.

The technical challenges of increased transmission access will be significant. As discussed

above, available capacity on transmission systems is difficult to determine. It depends on the

specific conditions at the time transmission is

desired, the reliability and longevity levels

selected by the utility, and the parallel path

flows that will result. Therefore disputes over

the feasibility and cost of wheeling may be

difficult to resolve. In addition, control of

transmission loading currently is effected

largely through control of generation. As lines

approach full capacity, increased demand is met

by shifting to generating units that do not require

these lines, even if they are more expensive to

operate. If independent generators have access

to the system, such shifts could be more difficult

to manage. Also, if a substantial amount of the

power flow on the transmission network is not

dispatchable, balancing demand with supply for

the remainder of the load will be more difficult.

Finally, long-term planning for transmission

capacity additions would be complicated by the

uncertainty of where new generating units were

going to be located and where their power would

be delivered.

To a large extent, the success of implementing increased transmission access depends on

developing workable definitions of obligations and rights of all parties and the institutions to carry them out. Various wheeling

arrangements are possible, depending on the

types of power suppliers, purchasers, and transporters and the specific agreements between

them. Wheeling agreements must specify the

amount of advance notice and other conditions

under which the transporter can halt a transaction and the amount of advance notice buyers

and sellers must give the transporter before

increasing or decreasing the amount of power to

be wheeled. These rights and obligations, while
20 ● Electric Power Wheeling and Dealing: Technological Considerations for Increasing Competition

critical for determining technical feasibility and

economic impact, also raise fundamental questions of equity and appropriate levels of cooperation.

It should be noted that it is not clear how

much expansion of the transmission system will

be necessary or practical. The decrease in

surplus generating capacity in all parts of the

country will reduce the availability of inexpensive bulk power. The apparent reversal of the

trend toward large, remote generating stations in

favor of smaller generators located close to load

centers, if continued, will also reduce future

needs. In addition, the costs of siting and

constructing transmission lines may exceed

their benefits. Major upgrades and new lines

frequently encounter opposition, as discussed

below. New technology, such as fuel cells or

small photovoltaic systems, could completely

revamp the way we generate and deliver power.

Thus it is not clear that massive upgrades are

inevitable, especially in the long-term, though it

is likely that some continued growth will be

required.

CHANGE AND THE

BULK POWER SYSTEM

A variety of futures has been espoused for the

electric power industry, including different forms

of competition. This assessment presents five

scenarios based on recent proposals representing the major themes in this debate. The

scenarios provide a framework for analyzing

technical considerations. In particular, they

focus on competition in generation and access to

the transmission system. Table 1-4 lists the main

characteristics of the five scenarios.

Scenario 1 assumes that with some modifications to the current regulatory process, the

existing organization for supplying electric power

will be the most effective. Proponents of this

approach believe that the major problem is that

utilities will be reluctant to build adequate new

capacity to meet future growth. Therefore, the

‘‘regulatory bargain” is strengthened by reassuring utilities and their investors that a reasonable return on investment will be allowed. A

potential vehicle for this reassurance would be

‘‘rolling prudence”—prior approval by the

State utility commission of the need for new

facilities and periodic progress reviews during

construction. If there is a problem, adjustments

can be made or the plant canceled before costs

have become too high, but the utility would be

guaranteed recovery of all costs already certified. In addition, minor modifications to PURPA

regulations would be implemented to correct

perceived imbalances in avoided-cost pricing

for QFs. Competition could continue to grow

incrementally as an alternative, but no special

measures would be implemented to promote it.

Transmission access would be voluntary.

Scenario 2 expands the environment for

competition through increased access to the

transmission system for utilities, QFs, and IPPs.

It adopts a broad public interest standard for

issuing wheeling orders, including requests by

large retail customers shopping for the best

price. There would be a presumption that the

capacity to wheel exists, and the utility denying

the services would bear the burden of showing

otherwise. Scenario 2 also broadens the definition of qualifying facilities. Changes to PURPA,

the Public Utility Holding Company Act (PUHCA)

and the Federal Power Act (FPA) would be

required. The industry structure and regulation

would remain much the same. Prime responsibility for operation and development of the bulk

power system would remain with utilities.

Scenario 3 would create a competitive generating sector incrementally. When a need for new

generating capacity is established, a utility

would solicit proposals to supply it. The utility

would select the best bids based on price and

other factors, purchase the power under contract, and distribute it to customers. Participating utilities would have to guarantee transmission access for other generators, but would

not be required to provide wheeling for retail
Table 1-4--Summary of Alternative Scenarios

Scenario 2

Expanding Transmission Access and Scenario 3

Scenario 1

Scenario 4 Scenario 5

Competition in the Existing Regulated Competition for New Bulk Competition for All Bulk Common Carrier Transmission services

Strengthening the Regulatory Bargain Utility Structure Power Supplies Power Supplies in a Disaggregate Industry Structure

●

●

●

●

●

●

Industry consists of a mix of vertically

integrated utilities, IOUs, public power,

cooperates, Federal power authorities, self-generators, QFs, and IPPs.

Existing regulatory structure with State

proapproval of new generating projects and periodic prudence reviews

during planning and construction.

Negotiated transmission access arrangements,

Traditional system coordination and

control by integrated utilities or control centers.

Prices set by regulatory proceedings

and cost of service. Transmission

prices and wholesale rates set by

FERC (including approval of negotiated

IPP power purchases) State oversight of retail rates and PURPA

Implementation.

Federal and public power agencies

and cooperates affected only to the

extent State law provides.

SOURCE Office of Technology Assessment, 1989.

●

●

●

●

●

●

Industry consists of existing mix of

entities.

Existing regulatory structure with wider

QF eligibility under PURPA including

full utility ownership/control of QFs

(may require amendment of PURPA).

New Federal wheeling authority under

a public interest standard for wholesale and retail transmission access

(requires amendment of the Federal

Power Act).

Traditional system coordination and

control by integrated utilities or control centers with contracts for unbundled services.

Prices set by regulatory proceedings

and cost of service. Transmission

prices and wholesale rates set by

FERC (including approval of negotiated

IPP power purchases). State oversight of retail rates and PURPA

implementation.

Federal and public power agencies

and Cooperates affected only to the

extent State law provides.

●

●

●

●

●

●

Existing mix of generating entities

expanded by IPPs and unregulated

utility generating subsidiaries.

Existing regulatory structure with marketbased rates for new competitive generation. Utilities use all source procurement for new bulk power needs.

Contracts awarded to lowest cost

supplier with consideration for nonprice factors.

Transmission access provided by utilities as a bidding condition, or by

privately negotiated arrangements,

or under new Federal public interest

wheeling authority (no retail wheeling).

Traditional system coordination and

control by integrated utilities or control centers. Unbundled bulk power

dispatch, control, and transmission

services provided through contracts.

Retail and transmission prices set by

regulatory proceedings. Wholesale

power prices set through competitive

procurement except for cost-base

plants built by utility as last resort

supplier, State and Federal regulators oversee terms and conditions of

wholesale sales.

Federal and public power agencies,

and cooperates can participate in

competitive generating sector to extent provided by Federal and State

law and policy.

●

●

●

●

●

●

Industry structure: Ownership of competitive generating sector segregated

from transmission and distribution

sectors.

New Federal and State regulatory

systems. Price and entry regulation

of generation sector replaced with

competitive market. Continued regulation of transmission and distribution

utilities and retail sales.

Revised Federal wholesale wheeling

authority. Transmission utility to plan

for and provide nondiscriminatory access for bulk power supplies.

Most of traditional utility system planing and coordination taken over by

transmission and distribution entities.

Competitive generators plan and build

generation. Transmission operator assumes responsibility for bulk power

system control and operation. Distribution utility retains retail obligation to

serve. Unbundled bulk power dispatch, control, and transmission services provided through contracts.

Bulk power prices set by market

through bidding, negotiation. Transmission and retail prices are set by

regulatory proceedings Some State

and Federal oversight of competitiveness of generation markets and prudence of bulk power contracts.

Federal and public power agencies,

cooperatives can participate in competitive generating sector to extent provided by Federal and State law and

policy.

●

●

9

●

●

●

Ownership and control of existing

integrated utility industry is disaggregate into separate generation, transmission, and distribution segments.

New Federal and State regulatory

system. Price and entry regulation of

generation replaced with competitive

markets. Distribution utilities’ services and retail prices remain regulated. Transmission prices and activities are strictly regulated.

Transmission sector operates as a

common carrier providing nondiscriminatory access to all wholesale and retail

customers. Reasonable conditions

on reserving transmission services

may be imposed.

Bulk system planning and coordination is split among generation, transmission, and distribution entities. Generators identify, plan, and build new

generation in response to market

signals. Transmission utility assumes

responsibility for reliability of bulk

system operations. Responsibility for

estimating demand and securing adequate power supplies rests with distribution utilities. Unbundled bulk power

dispatch, control, and transmission

services provided through contracts.

Bulk power prices set by market.

Transmission and retail prices are set

by regulatory proceedings. Some State

and Federal oversight of competitiveness of generation markets and prudence of bulk power contracts.

Federal and public power agencies,

cooperatives can participate in competitive generating sector to extent provided by Federal and State law and

policy.
22 ● Electric Power Wheeling and Dealing: Technological Considerations for Increasing Competition

customers. Some modifications to the FPA,

PURPA, and PUHCA would be required.

A two-tiered pricing system would result:

competitive power under minimal regulation;

and power from existing generation under the

current State-Federal regulation. Transmission

and distribution prices would remain regulated.

Scenario 3 differs from recent proposals by

FERC in that utility participation in bidding

programs would be mandatory, and transmission access is guaranteed.

Scenario 4 would drastically restructure the

industry to create a competitive generating

sector over a short period of time, rather than

incrementally as in scenario 3. Utilities would

spin off their generating facilities and activities

into affiliates or even independent companies.

Transmission and distribution could, but would

not have to, be separated from each other and

would remain heavily regulated. Safeguards

would be needed to prevent self-dealing and

cross subsidization in cases where a generator

was bidding to supply power to a transmission/

distribution affiliate.

Competitive companies would generate the

power and sell it to regulated transmission and

distribution companies (which could be either

combined or separate). Transmission and distribution utilities would be responsible for contracting for adequate power to meet expected

demand at all times. Most of the other coordinating functions that integrated utilities now perform internally, such as dispatch and system

control, would be arranged by contract. The

transmission companies would have an obligation to maintain adequate capacity to wheel

power as required for regional needs, their own

distribution clients, and for generating companies selling directly to retail customers. Wheeling for retail customers would be voluntary.

This scenario would involve a substantial reevaluation and redistribution of rate-base assets in a

transition period, entailing major public policy

issues.

Scenario 5 would completely separate utilities into generation, transmission, and distribution sectors. Entry into the generation sector and

bulk power pricing would be left to market

forces. Electricity would be Supplied under

long-term contracts and spot sales by competitive generators. Retail prices would still be

regulated. Transmission utilities would be converted into common carriers (i.e., providers of a

nondiscriminatory service based on approved

wheeling tariffs for all parties on request). All

customers would have the option of obtaining

their power from any willing supplier with the

assurance that such power would be delivered

under reasonable terms. Transmission and distribution companies would be obligated to plan

for adequate capacity for all anticipated needs,

as in scenario 4.

Technical Implications of the Scenarios

Any proposed change raises uncertainty as to

how well the new system will work, though

competitive changes to date have been assimilated. There is no point at which increased

competition becomes clearly infeasible. Rather, increasing competition expands the

institutional modifications required and

raises the uncertainty of success in maintaining reliability and improving economics. The

feasibility of these scenarios depends largely on

developing new institutional relationships among

suppliers, consumers, and transporters to preserve the coordinated operation and planning of

the power system. Implementing these new

relationships is likely to require some new

physical facilities and improved analytical capabilities. Without careful preparation, changes to

the institutional structure of the industry can

affect the operation of this system in ways that

are not necessarily obvious.

Scenario 1 would produce only evolutionary

changes in competition and industry structure.

Utilities would continue to build most new

capacity and coordinate the power system. Thus
Chapter I---Introduction and Summary ● 23

no major technical challenges are likely to

appear as a result of implementing scenario 1.

The major technical impact of scenario 2 will

bean increase in the required level of analysis of

transmission availability and costs. One difficulty with increasing access to the transmission

system is that transmission capacity is a matter

of trade-offs and assumptions, not an objectively defined limit. Additional information and

analysis of availability, costs, and reliability of

transmission services would be needed by the

operators of the transmission networks, suppliers of power including utilities and nonutility

generators, and regulators. In addition, some

increase in system complexity is expected (with

more actors and more transactions), resulting in

a need to upgrade control centers and AGC

systems. New procedures for dispatch and

scheduling of wheeling would be required.

Additional generation and transmission reserves

might be needed to account for increased

uncertainty or loss of coordinated control.

The technical challenges of scenario 3 would

be similar. Control of generation will be more

complicated if many different entities are responsible for generation. Analysis will be required to

operate the system most efficiently and allocate

costs and benefits. Procedures will need to be

developed to ensure economic dispatch. Regulators and utilities will also have to quantify the

value of supply characteristics such as dispatchability, fuel diversity, location, and risk of

project failure. Reserve margins for both generation and transmission might have to be

increased to allow for uncertainties, though this

might be balanced by a trend toward smaller,

dispersed generating units.

Scenario 4 differs from 3 largely in the rate

and extent of change. Instead of incremental

competition with just new generation (which is

only several percent per year), utilities would

rapidly spin off their generating facilities. Substantially new operating and planning procedures would have to be developed and implemented rapidly. Maintaining coordinated generation and system reliability will present significant challenges. Rapid change is riskier than

gradual change because mistakes can become

widespread before they are recognized. If not

done well, the result could be lower reliability

and higher costs.

Scenario 5’s common carrier wheeling and

complete separation of generation, transmission, and distribution into separate companies

compound the risk and uncertainties of scenario

4. Coordinated operation of the bulk power

system will require careful definition and unbundling of services for wheeling as well as

generation. Transmission companies will have

to be particularly alert to potential problems

since they will have only contractual control

over generation and possibly incomplete control

over the use of the transmission system. As in

scenario 4, the rapidity of change greatly

increases the likelihood of making expensive

mistakes.

Regional Differences

Conditions that will affect the desirability and

feasibility of competition vary widely across the

country. Some impacts will be local and utilityspecific.

Scenario 1 would affect existing State regulatory programs though some States have already

incorporated elements such as prior review and

certification of new capacity needs. Most States

have allowed recovery of prudent investment on

abandoned plants and require utilities to submit

long-range plans for generation and transmission requirements. However, no State has initiated all the provisions of scenario 1. Some

increase in regulatory activity would be required, especially in States with traditional

approaches to ratemaking (primarily in the West

and Southeast). Lowered avoided cost payments

might reduce QF growth, particularly in California, Texas, and Colorado.
24 ● Electric Power Wheeling and Dealing: Technological Considerations for Increasing Competition

Scenario 2 could have significant local

impacts. The encouragement of QFs and greater

access to the transmission system could increase

wheeling, though the degree cannot be predicted

confidently. Power wheeling from low-cost

suppliers to high-cost areas should increase,

possibly reducing rates in those areas, depending on local conditions. If scenario 2 results in

a large net increase in system demand, the

stresses on already heavily loaded systems

would increase and create pressure for new

capacity. The areas most likely to be seriously

affected are the East Central Area Reliability

Coordination Agreement (ECAR), the MidAtlantic Area Council (MAAC), the Northeast

Power Coordinating Council (NPCC), the Electric Reliability Council of Texas (ERCOT), and

the Western Systems Coordinating Council

(WSCC).

The impacts of scenario 3 will depend largely

on how competitive procurement is implemented, and will not be great for at least a

decade, especially in States with little need for

new generating capacity. Specific provisions in

solicitations and nonprice considerations can

determine who is willing to bid. Small generators and renewable energy could be disadvantaged unless protected. Regional price discrepancies should diminish over time as low-cost

power is bid up and wheeled, displacing highcost suppliers. Areas that become heavily dependent on NUGs must be especially careful to

properly integrate these facilities or they risk

lowered reliability. State regulatory activity

could increase significantly.

Scenario 4 would accelerate the impacts of

scenario 3, and introduce questions of equity,

the viability of competition, and the role of State

regulation. Prices to consumers are largely

unpredictable if this scenario is imposed rapidly.

Some regions may not have enough viable

suppliers to sustain a competitive market. In

regions with no surplus generating capacity,

low-cost power from older plants could suddenly increase in price. Newly independent

generators could also flee an existing service

area to sell in a higher price region, creating

instability in the supply. Regions with a strong

transmission network arrangement might have

an advantage in creating the necessary institutional infrastructure for separate transmission

utilities. Thus costs and benefits are likely to

vary widely.

Scenario 5 shares many of the impacts of

scenario 4, but is even more extreme and

unpredictable because there are few precedents

for determining how a common carrier transmission network would work. Multi-State common

carrier companies will require considerable

attention from Federal and State regulators.

Economic and Institutional Impacts

While it can be stated with reasonable confidence that any of the scenarios can be made to

work if carefully defined, increased competition

involves significant economic uncertainties. Success depends on the ability of competitive

suppliers to function more efficiently than

utilities to overcome any additional costs

from increased difficulties of coordination. It

is not clear how extensive the opportunities

for improved efficiency are, how costly maintaining coordination will be, or how much

wheeling would increase if a 66 broad public

interest standard" for transmission access is

implemented. Thus the economic merits of

scenarios 2-5 cannot be predicted accurately.

It is likely that the costs and benefits would be

unevenly distributed, depending on specific

utility and local factors. Scenarios 4 and 5

present the greatest uncertainties, especially

during the transition phase. Balancing the interests of consumers, utility shareholders, and new

entities will be particularly difficult if existing,

rate-based assets are spun-off to competitive

generating companies.

The “rolling prudence” of scenario 1 could

result in greater reassurance to utilities interested in building large coal or nuclear plants, but
Chapter l-introduction and Summary ● 25

a survey of utilities did not provide much

support for the concept. Only a few believed that

rolling prudence would eliminate regulatory

uncertainty, which is only one of several disincentives working against these plants.

Under scenarios 3-5 utilities will have to

unbundle many of the services they now provide

internally-dispatch, maintenance scheduling,

new construction, etc.—and arrange to have

them accomplished under contract with other

companies. If contracts are prepared carefully

they may serve as well as internal control, but

they will require considerable foresight and

analysis, and may be less flexible in meeting

changing needs.

SITING, ENVIRONMENTAL,

AND HEALTH ISSUES

Increasing competition and opening up the

transmission grids raise many public policy

issues beyond the technical and institutional

feasibility of accommodating these changes.

Three of the most significant and potentially

contentious of these issues are: transmission line

siting, environmental impacts, and potential

public health effects of electric and magnetic

fields.

Siting

There is a widespread perception in the

industry that siting new electric transmission

lines has become almost impossible because of

the obstacles encountered in the process of

regulatory review and approval. While there are

a number of well-publicized cases where construction of transmission lines has been delayed

or prevented as a result of public opposition in

the siting process, these cases are the exceptions,

not the rule. The process of gaining approval for

transmission line construction has become more

formalized as opportunities have been provided

for public involvement and greater scrutiny of

potential environmental and social impacts of

proposed projects. Competition for land to route

transmission lines has become more intense and

right-of-way costs are increasing. Nevertheless

the Nation’s transmission networks have continued to grow. According to a survey of State

agencies by the National Governors’ Association and the National Association of Regulatory

Utility Commissioners, more than 515 requests

for transmission lines have been filed with State

agencies in the last 10 years, and all but 18 have

been approved.7 The survey did not distinguish

between major, high power lines and short,

noncontroversial lines, but it shows that the

licensing process generally is still a routine

(though sometimes difficult) process.

Planned investment in new transmission lines

has been declining. At least part of the reduction

in planned new transmission projects reflects

the completion, deferral, or cancellation of

associated generating facilities. Eventually, however, new and expanded transmission systems

will have to be built to provide an adequate and

reliable power supply, whether a competitive

future path is taken or not. The challenge for

industry and regulators is to create a system

which plans for and encourages needed expansion while at the same time accommodating

other competing interests, and resolving or

minimizing conflicts.

Environmental Impacts

Overall, neither expanded competition nor

increased transmission access is inherently incompatible with national environmental objectives.

None of the scenarios is demonstrably preferable on environmental grounds, but uncertainty

over impacts increases with the degree of

change from the status quo.

Decisions over the future structure and composition of the electric power industry in the United

States have direct environmental impacts from

shifts in the choice of fuels used for generation

and in requirements for increased transmission

7~b]ic service Cmrnlkskm of WCSt Vlrglnh, “State Survey of Transmission Ccr_(ification and Siting, and Planning processes, ” unpublished

summary, Nov. 13, 1987. This document provides preliminary results of the NGA-NARUC survey of State utility and siting commissions.

89-137 -89 - 2
26 ● Electric power Wheeling and Dealing: Technological Considerations for increasing Competition

with increased competition. However, it is not

clear at this point what shifts would occur.

One possibility is that competition could

encourage the protracted operation of older,

dirtier generating facilities which otherwise

would have been retired by a utility.8 Competitive generators may not use the same fuels and

generating technologies as traditional utilities,

which would result in a different mix of

pollutants. The first solicitations for competitive

generation in Massachusetts suggested a wide

variety of fuels will be used, including coal and

trash. Alternatively, if competition discourages

the development of environmentally benign but

economically risky alternative energy technologies, the net effect would be negative for the

environment and human health.

However, none of these arguments is conclusive, and competition could prove beneficial for

the environment. Many observers believe that

reliance on competitive bidding for new generation could cause a shift toward natural gas and

oil (though under some schemes the purchasing

utility could express a preference for specific

fuels). Both have been cleaner fuels than coal,

but are not entirely devoid of pollutants. Furthermore, recent technology such as fluidized

bed combustion permits coal to be burned very

cleanly even in small plants, suggesting that air

pollution can be tightly controlled under any

scenario. Thus the environmental impacts are

not a clear function of the competitiveness of the

industry structure, but the possibility exists for

some significant unintended effects.

Transmission line construction, operation,

and maintenance also create direct and indirect

impacts on the environment. Concerns often

center on land use, aesthetics, destruction of

forests and wildlife, corona discharges, and the

biological effects on human health (discussed

below). These are the primary issues affecting

siting disputes. Several of the scenarios are

likely to increase demand for transmission

services. As capacity is expanded (new lines and

greater use in existing corridors) the number of

such disputes and the environmental impacts of

transmission will increase.

Health Effects

Until relatively recently, there was little or no

scientific evidence that power frequency fields

could pose a threat to human health. However,

laboratory studies have now demonstrated that

even relatively weak electric and magnetic

fields have effects on living cells and systems.

Scientists are still investigating whether these

effects have public health implications. In addition, several recent epidemiologic studies have

suggested an association between exposure to

electric and magnetic fields and cancer. While

these epidemiologic studies are controversial

and incomplete, they do provide a basis for

concern about effects from exposure.

The research results to date are complex and

inconclusive. Many experiments have found no

differences in biological systems that have been

exposed to fields and those that have not. It still

is not possible to demonstrate that such risks

exist, and they may not. However, the emerging evidence no longer allows one to conclude

that there are no risks.

If power frequency fields do prove to pose

human health hazards, the implications for the

electric power industry will be great whether

competition is encouraged or not. Already,

health effects are one of the most prominent

concerns raised by people living near existing or

proposed transmission lines. However, it is

important to recognize that exposure from

high-voltage transmission lines is only one,

perhaps minor source. Exposure to local electric

distribution lines, appliances, lighting fixtures,

Eme ~guent is that mmy old, fu]]y dcp~ia~~ pl~~ We no more expsive to ~~ratc ~~ new pl~t.s, t)ut rate regulation provides ]imited

inecntive to keep them on line, If a utility can spin off this asset, as in scenario 4, the value of the plant would rise considerably, and it would be worth

operating longer. A counter argument is that competition will drive down the costs of new plants, making older plants less competitive. Individual cases

are likely to hinge on specific costs as well as on how competition is implemented.
Chapter l-introduction and Summary ● 27

and wall wiring are more common and could

play a more significant role in any public health

risks.

POLICY

Even without legislative action, the competitive generation segment in the electric power

industry is growing. Also FERC and the States

are incorporating a greater reliance on market

forces in existing regulatory standards and

procedures. These trends are likely to continue.

There is no crisis mandating immediate action

by policymakers. However, the structural

changes sought and the way in which they are

effected have major public policy implications

worthy of congressional consideration. If Congress wishes to encourage increased competition and transmission access, several technical

and institutional changes could help ensure that

the electric power system operates reliably and

economically.

The policy options discussed here are not

directed at implementation of the OTA scenarios.9 Rather, the policy discussion focuses on

three areas of potential congressional concern:

the technical and institutional changes that must

occur to assure that the reliability and economy

of operation of the bulk power systems do not

suffer in any competitive transition; the lack of

information, analysis, and experience to support

decisionmaking about electric power industry

structure and regulation; and the broad public

policy questions that will be central to any

debate over fundamental changes in the regulation of electric utilities and bulk power markets.

Maintaining Reliability and Economy

of Operation

The key technical/institutional issue that has

been identified in this analysis is how to

maintain the coordinated planning and operation

of the bulk power systems as competitive trends

result in a growing separation of ownership and

operation of generation and transmission facilities. Responsibility for establishing an adequate

technical framework to support a more competitive generating sector or increased transmission

access will fall largely on the utilities, the

competitive generators, and several voluntary

and professional associations. Federal and State

policymakers can further some of the required

changes and will have a major oversight role in

determining whether the changes are proceeding

in the public interest.

Technical Requirements for Competitive

Generation

Additional information and research are

needed to establish a firm technical foundation

in the key areas of: a) load following and system

support and b) coordinated planning. Unbundling

generation and bulk power system support

functions will require development of new

standards, analytical methods, and data collection and accounting practices that are acceptable

to all or most participants. Additionally, the

extent of system support and reliability services

that integrated utilities now provide internally or

cooperatively will have to be defined and the

costs evaluated so that they can be properly

allocated in an unbundled competitive system.

Appropriate contractual arrangements or regulatory guidelines will need to be devised to assure

compliance with load following and other responsibilities and to require information sharing.

Federal and State regulatory agencies can aid

in the development of adequate technical and

institutional responses to the challenges created

by unbundling through:

1. establishing clear guidelines for determining and allocating the costs of providing

unbundled services and system support;

2. establishing minimum or standard bulk

power contract provisions that provide for

the necessary technical conditions of gen9Scen~o ] Cou]d & imulement~ wi~ Sta[e ~tion ad some Fcdera] regu]alq ch~ges, but Sccmrios 2 through 5 would require Federal legislation .

and corresponding changes in State law and regulation.
28 ● Electric power Wheeling and Dealing: Technological Considerations for Increasing Competition

3.

Photo Credit: Casazza, /scgyktz Assoc&tes, h.

Coal-fired power plant

eration control, coordinated operations,

and system support obligations; and

requiring that competitive supply contracts contain adequate enforcement and

default terms to assure that power supplies

will continue to be available.

In addition, revised planning methods maybe

required to integrate competitive power supplies

into utility resource plans and operating guidelines and to accommodate the new uncertainties

that they may bring. State regulators could

change their utility planning programs to require

more detailed information on resource needs

and technical standards. Regulatory agencies

may have to adopt a systematic process to ensure

that reasonable choices are made for generation

type and location, and transmission capacity,

perhaps requiring expanded State involvement

in planning.

Technical Requirements for

Transmission Access

A greater diversity among generators and

bulk power customers and an increase in wheeling will create a need for new methods of

coordination, capacity evaluation, compensation for unbundled transmission services, and

regulation. The actions that could be taken by

Federal and State governments include:
Chapter l---Introduction and Summary ● 29

1.

2.

3.

4.

5.

funding research needed to resolve common problems in transmission availability

standards, costing and pricing of transmission services, and minimum contract provisions for wheeling services;

reviewing and modifying existing regulatory practices to assure effective oversight

of transmission contracts, pricing, and

impacts on other interconnected systems;

encouraging consideration of overall regional transmission capacity needs in utility transmission planning activities;

requiring FERC to act promptly in setting

guidelines or rules for determining and

allocating the costs of unbundled transmission services, including reliability support; and

requiring FERC or DOE to perform more

detailed study of the technical and institutional changes required to provide transmission access in a more competitive

industry and to report back to Congress on

any desirable legislative changes.

Strengthening the Transmission System

No systematic review of the Nation’s transmission system’s constraints and bottlenecks has

been conducted recently to determine whether

bulk transfers can be increased or how much

additional access could be easily accommodated. Congress could commission a new detailed study of the capability of the transmission

systems to serve projected needs and to respond

to emergency situations. Two earlier federally

sponsored studies of the Nation’s power grid

proved useful for improved system operations,

and an updated study could be essential for

potential industry restructuring, future planning,

and regulatory oversight. New analytical techniques for measuring transmission capacity and

availability are also needed.

Congress could also encourage better information gathering and more frequent assessments of transmission capacity needs by FERC

and DOE in cooperation with State utility

commissions. These efforts could complement

ongoing efforts by industry groups, such as

NERC.

Better Information and Analysis

for Public Decisionmaking

This report has noted a dearth of information,

analysis, and experience to support policy decisions over whether further competitive changes

should be adopted and how they could best be

implemented. Additional research and information are needed on:

. bulk power markets,

. transmission system capabilities,

● nonutility generation,

. potential efficiency gains from expanded

competition,

● alternatives to competition to achieve similar cost savings, and

● impacts of competition on other Federal

energy and environmental goals.

The uncertainty resulting from this lack of

information could seriously hamper Federal and

State regulators’ efforts in: 1 ) assuring the

fairness and competitiveness of the bulk power

market, 2) assuring continued reliability of the

system, 3) protecting the interests of consumers,

and 4) achieving other energy policy goals. The

uncertainties also could hinder efforts of power

buyers and

competitive

transactions

reliability.

Congress

sellers to make arrangements for

bulk power sales and wheeling

that are adequate to protect system

could direct DOE and FERC to

expand their information gathering and analysis

activities to provide more accurate, timely, and

usable information on bulk power transactions

and wheeling. The existing competitive experiments could be more rigorously analyzed to

provide necessary data to proceed to the next

stage of competition. For example, the Southwest experiment was not conducted in a way that

provided this information. The initial efforts by

several States to initiate bidding procedures also
30 ● Electric Power Wheeling and Dealing: Technological Considerations for Increasing Competition

could provide critical information if analyzed

promptly.

Finally, it is important to resolve concerns

over the possibility that exposure to electric and

magnetic fields may pose human health hazards

no matter how the electric power industry

evolves. If such hazards exist, health considerations will likely create additional constraints on

siting of transmission lines. Funding for additional research on health effects and potential

remedial measures could resolve some of the

uncertainties and permit better decisions on

protecting public health and on siting transmission lines.

Expanding Competition—Institutional and

Public Policy Issues

Proposals for changing the regulatory and

institutional structure of the bulk power industry

raise many legislative issues. Most major strategies for significantly expanding competition

will require congressional action to eliminate

institutional and regulatory problems and to

assure orderly development. It is also possible

that growth of a competitive generation sector

may be so rapid that congressional or regulatory

action may be required to allow the regulated

transmission and distribution sectors adequate

time to adjust their own operations and procedures. Among the major public policy issues

likely to arise under alternative paths of industry

change are: encouraging broader market participation, expanding transmission access, and establishing an appropriate balance in Federal and State

regulation of electric power.

Enhancing Bulk Power Competition

Congress can affect the rate of increase of

competitiveness even without legislation by

encouraging or discouraging FERC’s proposed

rulemaking and other regulatory initiatives. In

addition, Congress could direct FERC to prepare a report evaluating the effectiveness of the

existing limited experience with competitive

markets before revising Federal utility regulation on a broad scale.

If Congress chooses to encourage the trend

toward competitiveness, it could remove some

of the constraints imposed by existing law on

potential participants in a competitive generating sector. Modifications to the Federal Power

Act, the Public Utility Regulatory Policies Act,

and the Public Utility Holding Company Act

have been suggested by utility and independent

power groups as a means to attract potential new

competitors in bulk power markets. Generally,

the proponents argue that the amendments

would lessen constraints created by either direct

limitations on participation by utilities and

others in the independent generating sector or by

disincentives associated with the regulatory

requirements imposed on public utilities. It

should also be noted, however, that changes in

these laws would be controversial and could

undercut other important public policy goals.

Expanding Access to Transmission Services

Under existing law, most transmission access

and wheeling arrangements are the result of

voluntary, negotiated agreements. Pressures for

utilities to allow access to their grids will grow

with the competitive bulk power market. But it

is not clear that under existing laws transmission

access will expand rapidly enough so as not to

be a constraint on market participation. FERC

has only limited authority to order utilities to

provide wheeling services. If Congress chooses

to address transmission access problems, there

are several alternative approaches available.

Congress could direct FERC to change administrative processes and transmission pricing policies to encourage access. Congress could amend

the FPA and PURPA to provide more expanded

wheeling authority. One possibility would be to

repeal the more restrictive aspects of the existing

wheeling provisions and allow FERC to order

wheeling in appropriate cases under a broad

public interest standard. Congress might also

consider whether a more direct Federal role is
Chapter I--introduction and Summary ● 31

needed in encouraging expansion of transmission capacity though authorization of more

cooperative State planning efforts and/or expansion of regional transmission services provided

by Federal power agencies.

Striking a Balance Between

State and Federal Jurisdiction

Federal jurisdiction over electric power regulation has been growing at the expense of State

regulation. This trend will accelerate under a

competitive bulk power market structure unless

Congress changes existing laws to limit or

override Federal court and agency decisions.

Examples of possible congressional remedies

include: returning jurisdiction over instate wholesale transactions to State authorities, giving

States jurisdiction over instate wheeling activities, and requiring FERC to defer to State

regulators in matters of prudence and resource

planning.
Chapter 2

An Overview of the Changing

Electric Power Industry
CONTENTS

Page

INTRODUCTION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35

A SNAPSHOT OF THE ELECTRIC POWER INDUSTRY TODAY . . . . . . . . . . . . . . . . . 35

Industry Ownership and Structure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35

Industry Power Operations and Coordination . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36

Electricity Generation, Demand and Supply . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38

TRENDS IN INDUSTRY INVESTMENTS, BUSINESS STRATEGIES,

AND STRUCTURE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 44

Projected Industry Capacity Additions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 44

Capital Spending Patterns . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 45

Growth in Nonutility Generation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 46

Changes in Company Business Strategies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 47

Industry Restructuring Trends . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 48

Measures of Financial Health . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 51

THE EXISTING REGULATORY STRUCTURE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 53

The Concept of a Public Utility . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 53

Federal and State Regulation of Electric Power . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 53

Boxes

Box Page

2-A. Electric Power Imports From Canada . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 43

2-B. Creating a Competitive Generation Industry in Great Britain . . . . . . . . . . . . . . . . . . . . . 50

Figures

Figure Page

2-1. Interconnections of the North American Electric Reliability Council . . . . . . . . . . . . . 37

2-2. Tight Power Pools in the United States . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38

2-3. North American Interconnected Control Areas, 1981 . . . . . . . . . . . . . . . . . . . . . . . . . . . 39

2-4. Electric Power’s Energy Market Share, 1970-87 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 40

2-5. Electric Power Generation by Fuel Source . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41

2-6. Cost of Fuels to End Users in Constant Dollars . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 45

2-7. Average Utility Revenues Per Kilowatthour Sold, 1966-87 . . . . . . . . . . . . . . . . . . . . . 45

2-8. Electric Utility Capital Expenditures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 46

2-9. Implications of Competition for Electric Utilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 47

2-10. Internal Cash Generation and Construction by Investor-Owned

Electric Utilities, 1980-90 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 52

2-11. Electric Utility Allowed and Earned Returns on Equity, 1976-87 . . . . . . . . . . . . . . . . 53

Tables

Table Page

2-1. Electric Utility Industry Installed Generating Capacity and Generation by

Ownership, 1987 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36

2-2. Industry Projections of U.S. Electric Load Growth . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 40

2-3. Total Electric Utility Industry Capability, Peak Loads, and Capacity Margins . . . . . 42

2-4. Generating Unit Additions, 1988-97 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 46

2-5. Electric Utility Projected 5-Year Capital Expenditures by Function . . . . . . . . . . . . . . . 46

2-6. Changing Patterns of Utility Capital Investment, 1988-92 . . . . . . . . . . . . . . . . . . . . . . . . 47

2-7. Capitalization Ratios of Electric Utility Industry, 1965-87 . . . . . . . . . . . . . . . . . . . . . . . 52

2-8. Annual Electric Rate Case Actions, 1983-87 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 54
Chapter 2

An Overview of the Changing Electric Power Industry

INTRODUCTION

This chapter provides an overview of the structure

and regulation of the electric power industry. The

first section provides information on utility ownership, generation and transmission resources, electricity demand growth, and recent financial trends

among private utilities. 1 The second section concludes with a brief introduction to Federal and State

regulation of electric utilities, bulk power markets,

and transmission access.

A SNAPSHOT OF THE ELECTRIC

POWER INDUSTRY TODAY

Industry Ownership and Structure

The electric power industry today is a diverse and

heterogeneous amalgamation of investor and publicly owned utilities, government agencies, cogenerators, and independent power producers. The industry consists of more than 3,200 entities that supply

electricity to more than 100 million households,

commercial establishments, and industrial operations. At present, there are 203 investor-owned

utility operating companies, 1,988 local publicly

owned systems (including municipal, State, county

and regional systems), 994 rural electric cooperatives (including 885 distribution co-ops and 59

generation and transmission co-ops), 59 public

joint-action agencies, 6 Federal power agencies, and

several hundred cogeneration and small power

producers. 2 Table 2-1 shows installed generating

capacity and generation by ownership.

Investor-Owned Utilities

The 203 investor-owned utility operating companies dominate the electric power industry, generating 76 percent of the Nation’s power and serving

about 75 percent of all retail customers.3 These

companies are an assimilation of some 2,000 private

utility systems that were in existence in the 1920s.

Actual control of the industry is somewhat more

centralized because nearly one-quarter of the remaining utility operating companies are subsidiaries

of nine registered electric utility holding companies

regulated under the Public Utility Holding Company

Act of 1935 (PUHCA). The registered utility holding companies are: Allegheny Power System, Inc.,

American Electric Power Co., Central and South

West Corp., Eastern Utilities Associates, General

Public Utilities Corp., Middle South Utilities, New

England Electric System, Northeast Utilities, and

The Southern Company. In addition to the regulated

holding companies, there are “exempt” holding

company systems consisting of affiliated utility

subsidiaries operating intrastate or in contiguous

States.

Federal Systems

The Federal Government is primarily a wholesaler of electric power produced at federally owned

hydroelectric facilities operated by the Bureau of

Reclamation and the U.S. Army Corps of Engineers.

Power is marketed through five Federal marketing

agencies—Bonneville Power Administration, Western Area Power Administration, Southeastern Power

Administration, Southwestern Power Administration, Alaska Power Administration-and through

the independent Tennessee Valley Authority, a

government corporation. Together, Federal systems

had an installed generating capacity of approximately 64,000 megawatts (MW) and accounted for

8.4 percent of the Nation’s power generation in

1987. 4 All Federal power systems are required under

existing legislation to give preference in the sale of

their output to other publicly owned systems and to

rural electric cooperatives.

Local Public Systems

In addition to the Federal systems, there are 1,988

local, municipal, State, and regional public power

systems ranging in size from tiny municipal distribution companies to giant systems like the Power

IMu~h of tie i~oma~ion in this ~tion is draw from ~ ()’I’A contractor report, SCOlt A. Fcnn, ‘‘An Overview of the Changing Electric F’ower

Industry,” December 1988.

24 *U.S. IXXtriC utility Statistics, ” Public Power, January-February 1989, p. 51.

31bid.

41bld$

-35-
36 ● Electric Power Wheeling and Dealing: Technological Considerations for Increasing Competition

Table 2-l-Electric Utility Industry Installed Generating Capacity and

Generation by Ownership, 1987

Nameplate Generation

Type of ownership capacity (MW) (millions of kwh)

Investor-owned . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 552,795 2,022,260

Federal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 64,666 205,363

Municipal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 39,378 86,211

States and power districts . . . . . . . . . . . . . . . . . . . . 34,858 135,786

Cooperatives . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26,359 122,508

Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 718,056 2,572,128

SOURCE: Edson Ektric Insdtu@, %tidcd Yaarbook of tha Ehwtric Uti/ity /rdustr-y/W87 (Waal-ingbn, DC: Dacambar IWS).

Authority of the State of New York. Publicly owned

systems are in operation in every State except

Hawaii. Municipal systems are usually run by the

local city council or an independent board elected by

voters or appointed by city officials. Other public

systems are typically run by public utility districts,

irrigation districts or special State authorities. Together, local public power systems generated 10.2

percent of the Nation’s power in 1987 but accounted

for 14.3 percent of total electricity sales, reflecting

the fact that many public systems are involved only

in retail power distribution.5

Rural Electric Cooperatives

Electric cooperatives, an outgrowth of Federal

Government efforts to bring electricity to rural areas,

now operate in 46 States. Rural co-ops are owned by

their members, each of whom has one vote in the

election of a board of directors. Congress created the

Rural Electrification Administration (REA) in 1935

and subsequently gave it broad lending authority to

stimulate rural electricity use. Cooperatives have

access to low-cost government-sponsored financing

through the REA, the Federal Financing Bank, and

the Bank for Cooperatives. Early REA borrowers

tended to be small cooperatives that purchased

wholesale power for distribution to members. Over

the past 20 years, however, many expanded into

generating and transmission cooperatives in order to

lessen their dependence on outside power sources. In

1987, rural co-ops accounted for 5.2 percent of total

power generation and 6.9 percent of sales to ultimate

customers. b

Industry Power Operations and

Coordination

In most areas of the country, utility systems are

now highly interconnected and operate under a

variety of formal or informal coordination agreements. The level of power transfers and coordination

between utilities is determined largely by physical

interconnections, power pooling arrangements, and

control centers.

Interconnections

North America’s interconnected utilities create

four physically separate, synchronously operated

transmission networks: the Eastern Interconnection

(or Seven Council Interconnection); the Texas

Interconnection; the Western Systems Coordinating

Council (WSCC); and the Hydro Quebec System.

The boundaries for these transmission networks are

shown in figure 2-1. DC and AC transmission

interties between the networks are limited in location and capacity, with the result that the transmission systems in the United States do not form a

single national grid, but rather form three separate

grids. The transmission barriers between the three

grids effectively limit the market areas for electric

power in the United States For instance, there is little

opportunity for long-distance power transfers between relatively low-cost surplus power areas in the

Western Systems network and the higher-cost power

systems in the Midwest or between the Texas

Interconnection, with its abundance of cogeneration

capacity, and utilities in the Southeast. There are

sound technical reasons for maintaining the integrity

5

1bid.

6Ibld.
Chapter 2—An Overview of the Changing Electric Power Industry ● 37

Figure 2-l--Interconnections of the North American

Electric Reliability Council

SOURCE: North American Electric Rdatility Council, 1987 Re/iab4ify Assessmerrt

The Futurw o/Bulh E/ectic System RddrWy in North America, 1987-1996,

September 1997.

of separate synchronous transmission networks.

However, it would be possible to construct AC-DCAC interties to allow greater power flows between

these regional networks without disrupting synchronous operations.

Power Pools

There are two types of power pool arrangements—

tight power pools, which include holding company

power pools, and loose power pools. The nine tight

power pools are highly interconnected, centrally

dispatched, and have established arrangements for

joint planning on a single-system basis. Four of

these tight pools consist of utility holding companies

with operations in more than one State; the others are

mostly multiutility pools. Together, the tight power

pools account for about a quarter of the industry’s

total generating capacity. Figure 2-2 shows the

location of the major tight power pools in the United

States.

In addition to the tight power pools, there are a

number of loose power pools. Arrangements among

utilities in loose power pools are quite varied and

range from generalized agreements that coordinate

generation and transmission planning to accommodate overall needs to more structured arrangements

for interchanges, shared reserve capacity, and transmission services.

Existing interutility obligations and economic

dispatch and transmission arrangements in interconnected and highly coordinated power pools may tend

to limit opportunities for expanded competition in

some areas for several reasons. Among the most

significant are constraints imposed by existing

long-term pooling contracts and the extent of

operating economies already captured by pooling. In

areas without extensive pooling agreements, increases in power pooling, coordination, and/or

power brokering could offer benefits from better

utilization of existing capacity that might be similar

to those claimed for greater competition in bulk

power purchases. One recent study indicates that the

savings to consumers resulting from utility coordination and pooling arrangements total in excess of

$15 billion annually, and that these annual savings

can be expected to increase to more than $20 billion

by the mid- 1990s.7

Control Areas

Responsibility for the operation of the Nation’s

generating facilities and transmission networks is

divided among more than 140 “control areas. ” In an

operational sense, control areas are the smallest units

of the interconnected power system. A control area

can consist of a single utility, or two or more utilities

tied together by contractual arrangements. The key

characteristic is that all generating utilities within

the control area operate and control their combined

resources to meet their loads as if they were one

system. If a single control area is used to dispatch the

generating facilities of several utilities to minimize

overall costs, the process is known as “central

dispatch.” Because most systems are interconnected

with neighboring utilities, each control area must

assure that its load matches its own internal generation plus power exports (or interchanges to other

control areas) less power imports. Because of

interconnection, each control area must satisfy more

stringent requirements for generation control, frequency control, and tie line flows than would be

needed for an isolated system. Control areas coordiTJohn A. Casazza, ‘‘Free Market Electricity: Potential Impacts on Utility Pooling and Coordination, ” Public Utilities Fortnightl), Feb. 18,1988, pp.

16-23.
38 ● Electric Power Wheeling and Dealing: Technological Considerations for Increasing Competition

Figure 2-2—Tight Power Pools in the United States

AEP—American Electric Power Company, Inc.

MSU--Middle South Utilities, Inc.

SOCO-The Southern Company

TUCO-Texas Utilities Company

SOURCE: Fdsral Enargy Regulatory Commission, Office of Electric Power Regulation, Powwr Pooling in fhe Urvtsd Slates (Washington, DC: December 1981).

nate transmission transactions among electric power

systems through neighboring control areas. Control

areas maintain frequent communications about operating conditions, incremental costs, and transmission line loadings.

There are about 99 control areas in the Eastern

Interconnection, about 34 in the Western Interconnected System and 10 in the Texas Interconnected

System. Figure 2-3 shows the North American

interconnected control areas in 1981.

Electricity Generation, Demand and Supply

Major shifts in electric power usage patterns have

bedeviled utility planners and energy forecasters

since the oil embargoes of the 1970s made previous

assumptions about fuel prices, inflation, and economic growth obsolete. Throughout the past decade,

the electric utility industry has faced a situation of

excess capacity as power plants, ordered in the

1970s, came on line and demand growth fell below

the industry’s expectations. As it enters the 1990s,

however, the industry’s problems with excess capacity appear to be receding and, in some regions of the

country, capacity margins are tightening to the point

that utilities are warning of shortages.

Demand and Peak Growth

Before 1970, electricity demand growth was

vigorous and predictable, with power usage growing

at an average annual rate of 7.8 percent and peak

demand growth averaging 8.1 percent a year be-
Chapter 2—An Overview of the Changing Electric Power Industry ● 39

Figure 2-3--North American Interconnected Control Areas, 1981

Synchronous InterconnectIon

Normally open Interconnection

Isolaled—generation and/or load within one

control area can generally be synchronized with

the other control area by way of these

interconnections

SOURCE: Federal Energy Regulatory Commission, Offica of Electric Power Regulation, Power Poohg kr fha United States (Washington, DC: December 1981)

tween 1945 and 1970.s Utilities underestimated the

price elasticity of electricity demand, however. and

as consumers reacted to electricity price increases in

the 1970s, growth in power demand fell sharply.

Since 1973, peak demand growth-the chief determinant of the need for new capacity—and annual

kilowatthour (kWh) sales growth have both averaged about 2.5 percent annually.9 As shown in table

2-2, utility industry expectations of future electricity

demand growth—for both peak demand usage and

net energy usage—have been reduced in every year

during this period and are now below the postembargo average.

The drop in electricity demand growth is largely

a reflection of a stagnation in the average growth of

overall energy demand since the early 1970s. Total

U.S. energy consumption in 1987 was only slightly

higher than it was back in 1973 before the first oil

shock, even though the real gross national product

rose 39 percent, or about 2.4 percent annually,

during this period. Thus, the only source of growth

in electricity demand for 15 years has been an

increase in electricity’s market share relative to other

end-use fuels. Electricity has steadily increased its

share of the total U.S. energy market from 24.4

percent in 1970 to a record 36.2 percent in 1987 (see

figure 2-4).

There are signs that electricity demand growth is

beginning to accelerate again in the late 1980s in

response to vigorous growth in the economy, including the revival of a number of energy-intensive

manufacturing industries and a strong commercial

g~u A. Thompson, ‘The Strategic Dilemma of Electric Utilities-Part I,”Public Utilities Fortnightly, Mar. 18, 1982, p. 20.

9B&~ on fiwres from &jlson Elec~ic ~stitu[e, ~tufi~tica/ Year~oo& ofthe E/e~lric Ufilify industry/1986. Data exclude Alaska ad Hawaii.
40 ● Electric Power Wheeling and Dealing: Technological Considerationsfor Increasing Competition

Table 2-2--Industry Projections of U.S. Electric Load Growth

Forecast Forecast Average annual *Average annual

published period peak demand growth net energy growth

1974 . . . . . . . . . . . . . . . . . . . . . 1974-83 7.6 7.5

1976 . . . . . . . . . . . . . . . . . . . . . 1976-85 6.4 6.3

1978 . . . . . . . . . . . . . . . . . . . . . 1978-87 5.2 5.3

1980 . . . . . . . . . . . . . . . . . . . . . 1980-89 4.0 4.1

1982 . . . . . . . . . . . . . . . . . . . . . 1982-91 3.0 3.3

1964 . . . . . . . . . . . . . . . . . . . . . 1984-93 2.5 2.6

1986 . . . . . . . . . . . . . . . . . . . . . 1986-95 2.2 2.3

1988 . . . . . . . . . . . . . . . . . . . . . 1988-97 1.9 2.0

SOURCE: North Amedcan Eloctdc RaUabMyCounclL /3ecfr&ifySW.@ymdL%rnand, putiiahedeachyear.

Figure 2-4--Electric Power’s Energy MarketShare,

1970-87

% of total domestic energy consumption

“ ~

so-

(

0 1 , 1 r 1 , 1 , , 1 , , , 1 , 4

1970 1972 1974 1976 1978 1980 1982 1984 1986

SOURCE: U.S.DapartmantofEmrgy.

and service sector. Nationwide, summer peak demand growth for the industry reached 3.4 percent in

1986, 4.2 percent in 1987, and 6.1 percent in 1988,

while total electricity kWh sales rose 2.1 percent in

1986, 3.7 percent in 1987, and an estimated 4.6

percent in 1988.10

Growth in electricity demand in recent years is

rekindling debate over whether utilities are building

sufficient capacity to meet future demand and how

they should meet this demand. A number of analysts

contend that the industry is now underestimating

future demand growth in the same way that it

overestimated such growth over the past decade.

Other analysts, however, contend that customer

responses to higher electricity prices-including

efficiency investments, relocation of production

facilities outside the United States, and onsite power

production— will continue to moderate future demand for utility-produced power.

Generating Capacity

Total installed electric utility generating capacity

reached 718,056 MW in 1987, an increase of 1.5

percent over 1986, with investor-owned utilities

accounting for 77 percent of this capacity.l] The

distribution of this installed nameplate capacity by

type of ownership is shown in table 2-1. In addition

to this utility-owned capacity, it is estimated that

nonutility companies had installed approximately

25,000 MW of cogeneration and small power

capacity through 1987.12

Fuel Mix

Coal is the dominant source of U.S. electric

generation, providing 56.9 percent of all electricity

generated in 1987, as shown in figure 2-5. Nuclear

power provided 17.7 percent, hydroelectric facilities

provided 9.7 percent, natural gas accounted for 10.6

percent, fuel oil provided 4.6 percent, and other

sources—including geothermal, wood, waste, wind

and solar-accounted for the remaining 0.5 percent. ]3

IOCW] Tobie, ~n~ commurdcaticm, Ediaon Electric Institute, Feb. 13, 1989.

ll~Wn EIWtic ktiwte, Smtistictaf yearbook of rhe Ekctric Uti/iry /ndKstry/1987 (Washington, DC: December 1988), P. 6.

124 ‘EEI: ~erzs,~ Mwof Non.utili~ cap~i~w~in service As of 1986, ” Efectric Utilify Week, Aug. 5, 1988, p. 13; and “Profileof Cogeneration

and Small Power Generation Markets-1988 Edition,” Energy User News, May 23, 1988, p. 2.

lgEdiWn Electric Institute, supra note 11, p. 32.
Chapter 2-An Overview of the Changing Electric Power Industry ● 41

Figure 2-5--Electric Power Generation by Fuel Source

, Millions of MWh

2,500

2,250

2,000

1,750

1,500

1,250

1,000

750

50C

25[

o

67 6!I 71 73 75 77 79 0~ 83 85 8 7

■ CoaI Gas ❑ Hydro and other ❑ Fuel oil ❑ Nuclear

SOURCE: Edison Electric lnstituW, Statistical Kwvbook of ha Hactric L41My /ndmfry/

lW?7(Washmgton, DC: Dacambar 1988).

Capacity and Reserve Margins

To meet expected load growth and to preserve

system reliability, utilities maintain generating capacity reserves. Reserve margins express the difference between demonstrated capacity and peak demand as a percent of total peak. The traditional

industry target has been to maintain a 20 percent

reserve margin, although individual utilities have

adopted different targets depending on many factors,

including individual plant characteristics (e.g., age,

size, type), access to power from other systems, and

characteristics of customer demand. Actual electric

utility industry reserve margins increased from

around 20 percent in the early 1970s to 30 percent in

the late 1970s and reached 35 percent in the

mid-1 980s before beginning to decline-although

there are significant differences in reserve margins

on a regional basis as discussed in chapter 6. Trends

in annual industry capability, summer peak loads,

and adjusted capacity margins are shown in table

2-3.

Transmission Capacity

Transmission systems have been utilized in the

past for the delivery of both capacity and energy.

Under the first function, the seller provides a fixed

amount of capacity and associated energy to the

buyer for a specified time. Because the provision of

this capacity is contractually guaranteed, the purchasing utility can include it in its reserve margin

and use it as a substitute for additional generating

capacity. In contrast, when energy alone is sold, the

seller provides a given amount of energy over a

specified period of time, but the availability of

energy at any instant is not assured. This type of

arrangement enables the purchasing utility to reduce

its costs by substituting less expensive purchased

power for more expensive electricity from its own

generating stations, but it does not reduce the

amount of generating capacity needed by the purchaser to meet reserve requirements.

In recent years, because of high industry reserve

margins, transmission systems have been used more

for providing energy to reduce fuel costs than for

providing capacity to avoid construction of new

generating facilities. As industry reserve margins

fall, however, the capacity function of transmission

systems is expected to become more significant.14

The pace of new transmission line additions has

been declining in recent years. As of year-end 1987,

the U.S. transmission system consisted of about

616,400 circuit miles of transmission lines of 22

kilovolts (kV) and above. 15 Approximately 79 percent of these circuit miles were owned by investorowned utilities,

Bulk Power Sales and Wheeling

Bulk power sales are defined as the sales of

electricity at wholesale for resale or transmission of

power for other systems (wheeling service). Such

transactions constitute a significant share of total

electricity sales in the United States.lb Wholesale

power sales are generally divided into two categories: requirements sales, in which typically a vertically integrated, investor-owned utility sells power

to meet the demand of a publicly owned utility that

Idsee John A. Cas=za, ‘Free Market Electricity: Potential Impacts on Utility pooling and Coordination. “ Public Utilities Fortrughtly, Feb. 18,1988,

p. 16.

lf~lWn El~Uic Institute, supra IIOtC 11, p. 97.

16L1nda M~lnson ,md Tho~~ ~fia, “The Transitlon~ Bulk power M~ket,” p~/lc (Jtl/l[fes Fortnlgh(ly, NOV. 26, 1987, p. 19.
42 ● Electric Power Wheeling and Dealing: Technological Considerations for Increasing Competition

Photo credit: Casazza, Schultz & As.sock3tes, h.

A modem high voltage tower

owns little or no generating capacity; and coordination sales, typically involving two vertically integrated, investor-owned utilities.

Meanwhile, wheeling transactions, involving the

transmission of power between two utility systems

on a prearranged basis over the lines of one or more

other systems, have become routine in the industry.

Wheeling transactions are arranged on a voluntary

basis and are generally subject to approval by the

Federal Energy Regulatory Commission (FERC),

where there are currently about 1,400 such agreements on file. Cost disparities and the development

of sophisticated communications and control technologies have fostered an increasingly active market

in bulk power transfers between utilities. Canadian

power imports are also increasing. (See box 2-A on

recent trends in bulk power purchases from Canada.)

There are pressures from some sectors of the power

industry to expand the number and the size of these

transactions and to make them a more integral part

of electric system planning. Independent power

producers and cogenerators, in particular, see greater

access to transmission facilities as essential to their

future growth.

Electricity Prices

Prices for electricity, like virtually all energy

supplies, rose substantially in the 1970s and early

1980s in response to higher oil prices and general

inflationary pressures in the economy, Unlike fossil

fuel prices, however, which have retraced much of

their earlier upward climb in recent years due to an

excess of world oil production over demand, electricity prices have moderated only slightly. In large

measure, this is due to the impact of a generation of

very expensive generating plants, particularly nuclear units, that entered service during the 1980s. In

addition, the fact that electricity prices are regulated

Table 2-3-Total Electric Utility Industry Capability, Peak laads, and Capacity Margins

(excluding Alaaka and Hawaii)

Capability at time Noncoincident Capacity margin at

Year of summer peak load summer peak load noncoincident peak

1978 . . . . . . . . . . . . . . . . . . . . . . . .

1979 . . . . . . . . . . . . . . . . . . . . . . . .

1980 . . . . . . . . . . . . . . . . . . . . . . . .

1981 . . . . . . . . . . . . . . . . . . . . . . . .

1982 . . . . . . . . . . . . . . . . . . . . . . . .

1983 . . . . . . . . . . . . . . . . . . . . . . . .

1984, ..., . . . . . . . . . . . . . . . . . ,.

1985 . . . . . . . . . . . . . . . . . . . . . . . .

1986 . . . . . . . . . . . . . . . . . . . . . . . .

1987 a 

. . . . . . . . . . . . . . . . . . . . . . .

545.7

544.5

558.2

572.2

586.1

596.4

604.2

621.6

633.3

647.9

408.1

398.4

427.1

429,3

415.6

447.5

451.2

460.5

476.3

496.2

25.2

26.8

23.5

25.0

29.1

25.0

25.3

25.9

24.7

23.4

‘Prelimmary

SOURCE: Edmon Electric Institute, ArlOutd k@Vt Of th k)wskx-(%ned Electric utikty /f)&Sty, 19/37 FhartcJ ‘d Iksvfew.
Chapter 2--An Overview of the Changing Electric Power Industry • 43

Box 2-A—Electric Power Imports From Canada

As economic, political, and environmental problems have led to a slowing of new power plant construction

in the United States, a number of U.S. utilities have begun to turn to Canadian imports as an attractive option for

meeting future demand. Since the early 1970s, U.S. utilities have steadily increased the amount of power purchased

from Canada-from less than 10 billion kWh in 1970 to an estimated 42 billion kWh in 1987—with roughly

three-quarters of these imports displacing imported oil. The U.S. Department of Energy estimates that since the 1973

oil embargo, Canadian power imports have resulted in savings of more than $7 billion for U.S. consumers compared

to the cost of imported oil.

While still accounting for less than 2 percent of total U.S. electricity demand, Canadian imports are significant

in certain regions. In the State of New York, for instance, Canadian imports have accounted for about 12 to 17

percent of total power supplies in recent years. In addition, electricity imports from Canada are poised for further

growth.

There is widespread agreement among utility industry experts that Canadian power imports will continue to

grow, although there are substantial differences of opinion about the extent of this growth. Most estimates predict

that import levels could range from 52 to 66 billion kwh annually by 1995. Among the factors that are leading to

growth in imports are:]

● Canadian energy reserves: Canada has enormous untapped energy reserves, including economically

attractive undeveloped hydroelectric reserves in northern Canada capable of supplying as much as 60,000

MW of generating capacity for which there is currently no Canadian market.

. Ease of power plant construction: In general, power plant construction appears to be somewhat less

onerous in Canada than in the United States. Construction delays, cost overruns, and prudence reviews by

regulators have made U.S. utilities extremely cautious about new plant construction.

. Canada’s economy and industry structure: General economic conditions in some Canadian provinces,

along with the government-owned structure of the Canadian provincial utilities, are making the construction

of power plants for the export market increasingly attractive. Three provincial utilities are considering

accelerating the construction of hydroelectric facilities for the U.S. export market. British Columbia has also

formed a provincially owned corporation to sell privately produced power exclusively to export markets in

the Western United States.

. The U.S.-Canada Free Trade Agreement: The recently negotiated U.S.-Canada Free Trade Agreement is

expected to enhance the prospects for future electricity trade by increasing the security of Canadian energy

supplies and lowering the cost of imports through the elimination of a discriminatory price test.

As Canadian imports grow, the arrangements under which power is being sold to U.S. utilities are also

changing. To date, most Canadian imports-72 percent in 1986-have been interruptible economy transactions.

Power sales are now shifting from short-term interruptible sales to firm, longer term contracts for energy and

capacity. In 1987 alone, U.S. and Canadian utilities signed three major multi-billion dollar, multiyear power import

deals. As a result, U.S. utilities are increasingly able to use Canadian electricity imports to defer or cancel new

domestic power plant construction.

The most important limitation on future growth of Canadian imports is likely to be a shortage of transmission

capacity. At present, more than 30 high-voltage transmission lines cross the border between the United States and

Canada, with a carrying capacity of more than 10,000 MW. Each region along the northern tier of the United States

has at least several lines. Most of these lines already operate near full capacity, however; so plans to expand

U.S.-Canadian electricity trade further will require construction of additional transmission capacity. The New

England Power Pool, for instance, is building a $570 million, 130-mile transmission line from the endpoint of its

existing interconnection with Hydro-Quebec in New Hampshire to Massachusetts in order to begin importing an

additional 7 billion kWh annually from Canada. Acquiring right-of-way for new transmission lines is difficult

though, and a recent wave of public concern about the possible health effects associated with transmission lines is

likely to intensify opposition to new lines.

Isa Dlm Wa$hm ~gm, P\ugglng IMO cm:ProSPc(s for U S -CanadKVI Electricity Trade (Washington, m: hvestm Rew-ibW Re==h

Center, 198S).

Conthh9d on next page
44 ● Electric Power Wheeling and Dealing: Technological Considerations for Increasing Competition

Continued from previous page

Moreover, technical, economic, and environmental concerns in the United States and Canada may limit further

expansion of electricity trade. Some U.S. utilities are concerned about the reliability of Canadian supplies,

particularly in light of weather-related curtailments by Hydro-Quebec in January and April 1988. Others are

opposed to imports because of the pricing structure used by Canadian utilities, which ties import prices to the

importing utility’s cost of displaced generation. Finally, many Canadians remain opposed to exploiting Canada’s

untapped energy resources for the U.S. market and a growing environmental movement within Canada could

constrain the development of new hydroelectric dams.

These concerns notwithstanding, it appears that over the near term, the powerful forces driving import growth

will overshadow import opponents. Over the longer term, it is also possible that emerging environmental concerns,

such as global warming caused by the burning of fossil fuels, will give new impetus to the development of

noncombustion technologies such as Canada’s hydro resources.

The likely beneficiaries of growing cross-border electricity trade include U.S. consumers, utilities that can limit

their construction programs or that control strategic transmission corridors, and financial institutions that participate

in financing major Canadian construction projects. Opportunities may also arise for U.S. utilities or independent

power producers to participate in Canadian power development through joint ventures with Canadian utilities.

Among those firms that could be adversely impacted by Canadian imports are utilities and independent power

producers attempting to sell excess capacity in the bulk power markets, nuclear and coal plant vendors, and domestic

coat mining companies. Perhaps most importantly, the growth of power imports from Canada is further evidence

of the competitive conditions emerging in domestic bulk power markets.

has tended to make them adjust more slowly than

those of primary fuels to underlying economic

trends. Consequently, the price gap between electricity and primary fuels has widened somewhat

since 1980, as can be seen in figure 2-6. A s

consumers react to these new relative prices, it is

likely that utilities can expect greater interfuel

competition in the coming decade.

As figure 2-7 shows, electricity prices have risen

substantially over the past two decades. The average

revenue per kWh sold by the utility industry rose

from about 1.5 cents per kWh in 1970 to about 6.5

cents per kwh in 1986, in current dollars. Electricity

prices for residential and commercial customers

during this period were, on average, about 50 percent

higher than those for industrial customers, although

price trends for all three major customer classes have

followed very similar patterns.

TRENDS IN INDUSTRY

INVESTMENTS, BUSINESS

STRATEGIES, AND STRUCTURE

Projected Industry Capacity Additions

The generating capability of the of the U.S.

electric utility industry is estimated to have reached

718,056 MW as of year-end 1987.17 Projections of

future electric generation capacity additions are

fraught with uncertainty because of ongoing changes

in industry structure and regulation. In recent years,

few utilities have been willing to commit to construction of new base-load capacity, in spite of the

continued aging of the existing generating plant

stock and predictions from some industry and

government planners that the country faces possible

shortages in the early to mid- 1990s. Meanwhile, the

flow of new plant additions by utilities entering

service as a result of orders placed in the 1970s is

17Edison Ekctric Institute, supra note 11.
Chapter 2—An Overview of the Changing Electric Power Industry ● 45

Figure 2-6-Coat of Fuels to End Users in Constant Dollars (1982 dollars)

2 5 I

c

o.-

a.

—0

20

15

1 0 -

5 -

Residential Electricit y ———. —

Motor Gasolin e /“—-” ,

—-—-~./” 

— .

Residential Heating Oil ----------- -

--- -

--- -

------- -

------------ -

---- -

---------- -

Residential Natural Gas

o

I 1 T 1 1 i 1 1 1973 1974 1975 1976 1977 1978 1979 1980 1981 19821983198419851986 1987 1988

SOURCE: Energy Informatbn Mmlnistmtlon, my Erwgy %~w, Ckfobw 1988 (Washingmn, DC: Jan, 26, 1969).

Figure 2-7—Average Utlllty Revenues Per

Kilowatthour Sold, 1966-87

cents Per kWh

———————L———I

1

o , , , , , r , , , , , , , , , I

19661968197019721974 19761978198019821984 19861988

SOURCE: Edison Electric Institute, Sratktkxd Y&a- of ha Ekctdc wtify hxfusti-y/

f$W7 (Waahmgton, DC: D~mbar 1966).

slowing to a trickle, although capacity additions by

nonutility generators are increasing.

In 1988, only two utility-owned, coal-fired generating units are expected to come on line-marking

a record low for the last two decades—and by 1992

only 13 utility-owned coal units totaling 8,383 MW

of capacity are due to enter service. Nationwide,

utilities are projected to add only 29,700 MW of

capacity from all sources during this period.lg

Through 1997, utilities and nonutility generators are

projected to bring on line about 73,440 MW of

capacity additions, with nuclear units accounting for

about one-fourth of this total as shown in table 2-4.19

Capital Spending Patterns

The U.S. electric utility industry is expected to

spend approximately $27 billion for new facilities in

1988, according to recent industry surveys.20 Industry capital expenditures have been falling in recent

years since peaking in 1982 at more than $40 billion

(see figure 2-8). Annual utility industry capital

spending has already fallen by about one-third (in

constant dollar terms) since 1982.

Capital spending in the electric power industry is

expected to continue to fall for at least several more

years before beginning to rise again sometime in the

1990s. Industry capital spending is projected to fall

‘

a

’’ Coal-Fired Power Plant Construction Hits All-Time Low, UDI Report Says, ” The Energy Report, July 18, 1988, p. 494.

l%Jorth Americ~ ElecUic Reliability Council, 1988 Elecfrici~’ Supply and Demandfor 1988-1997, mtober 1988, P. 48.

Zo’ 1988 Annual Statistical Report, ” E/ecrrical Worfd, April 1988, p. 5 I (estimates $26,6 bilhon); Edison Electric Institute, EE/ Finunciallnjo, May

25, 1988 (estimates $25.3 billion for investor-owned utilities); and Elecrm Lighr & Power, Januaty 1988 (estimates $27.5 billion).
46 ● Electric Power Wheeling and Dealing: Technological Considerations for Increasing Competition

Table 2-Generating Unit Additions, 1988-97

Thousands of Percent

Type megawatts of total

Nuclear . . . . . . . . . . . . . . . . 18.2 24.8

coal . . . . . . . . . . . . . . . . . . 15.4 21.0

Hydro . . . . . . . . . . . . . . . . . 1.7 2.3

Oil/gas . . . . . . . . . . . . . . . . 13.6 18.5

Pumped storage . . . . . . . . 2.1 2,9

Other (utility) . . . . . . . . . . . 2.6

Nonutility . . . . . . . . . . . . . . 19.8 27.0

Total additions . . . . . . . . 73.4 100.0

NOTE: Figures are rounded.

SOURCE: h&xth American Electric Reliability Council, f98S Hectricify St@y arrd

Demand fof 198S- 1997, October 1980, p. 40.

Figure 2-8-Electric Utility Capital Expenditures

Billions of dollars

50

40

19781979198019811982 19831984198519861987 1988

● E811mnted

SOURCE: Eledricd Wrld SWWY8.

steadily through 1992, reaching a level of $22.2

billion, as shown in table 2-5.

The drop in industry capital spending is the result

of a sharp decline in spending for new generating

capacity. Capital spending for utility transmission

and distribution projects has actually been rising in

recent years, although the amounts are small in

comparison to the decline in spending for new

generation projects. The changing composition of

the industry’s future spending is illustrated in table

2-6, which shows different categories of forecasted

capital spending by electric utilities. It is interesting

to note that the 1990 forecast period is the first

period where transmission and distribution spending

is expected to exceed spending on new generation

facilities. This change underlines the growing importance of off-system power sales, wheeling, and

retail marketing to many utilities’ strategic planning.

Growth in Nonutility Generation

The slowing of utility construction of new generating capacity is, to some extent, being offset by

continuing growth in cogeneration and power production facilities built by nonutility entities and by

unregulated utility subsidiaries. Since the passage of

The Public Utility Regulatory Policies Act (PURPA)

in 1978, the amount of electricity received by

utilities from nonutility sources has grown dramatically. Estimates of current and projected nonutility

capacity vary considerably, however, so it is difficult to measure the growth of this industry with

precision. One measure of this growth can be traced

through the marked increase in the number and size

of filings submitted to FERC, which is charged with

administering PURPA and certifying “qualifying

facilities” (QFs) under the law. While these filings

are not a precise indicator of the growth of nonutility

power production—because a substantial number of

projects filed with FERC are never brought to

fruition-the growth in these filings, from 29

projects totaling 704 MW in fiscal 1980 to a

cumulative total of 3,717 projects totaling 61,950

Table 2-5-Electric Utility Projected 5-Year Capital Expenditures by Function (millions of dollars)

Function 1988 1989 1990 1991 1992 5-year total

Generation . . . . . . . . . . . . . . . . . . . 12,296 10,769 9,443 8,199 8,385 49,092

Substations . . . . . . . . . . . . . . . . . . 1,371 1,384 1,225 1,360 1,175 6,515

Transmission . . . . . . . . . . . . . . . . . 2,558 2,376 2,397 2,795 3,092 13,218

Distribution . . . . . . . . . . . . . . . . . . 7,979 7,010 7,929 7,882 6,965 37,765

Other . . . . . . . . . . . . . . . . . . . . . . . 3,281 3,106 3,118 3,054 2,622 15,181

Total . . . . . . . . . . . . . . . . . . . . . . 27,485 24,645 24,112 23,290 22,239 121,771

SOURCE: “Elec81c UUllties WIN Incfaase spending Plarm Throu#I 1992,” Electric Light ~ Powwr, Jarwary 19SS, p. 12.
Chapter 2--A Overview of the Changing Electric Power Industry ● 47

Table 2-6--Changing Patterns of Utility Capital Investment, 1988-92

Function 1988 1989 1990 1991 1992

Generation . . . . . . . . . . . . . . . . . . . 44.7% 43.7°/0 39.20/. 35.2°/0 37.7%

Transmission and distribution . . . 43.4 43.7 47.9 51.7 50.5

Other . . . . . . . . . . . . . . . . . . . . . . . 11.9 12.6 12.9 13.1 11.8

Total . . . . . . . . . . . . . . . . . . . . . . 100.0 100,0 100.0 100.0 100.0

SOURCE: “Electric Utilities Will Increa se Spending Plans Through 1992,” Electric bghf & Potwr, January 1988, p. 11.

MW by the end of 1987, do serve to illustrate the

surge in nonutility generation.21

Although there is no definitive count of nonutility

capacity actually on line, a recent survey by the

Edison Electric Institute found 25,321 MW of

nonutility capacity in operation at the end of 1986

from 2,449 projects. Of this total, 1,647 projects

totaling 16,097 MW were qualifying facilities under

PURPA. Cogeneration facilities accounted for 18,448

MW, or about 73 percent, of the total. Small power

production capacity provided 20 percent, while

other nonutility producers accounted for 8 percent.

Three quarters—18,968 MW-of the total nonutility capacity was interconnected to utility systems. A

second small power database lists 1,808 QF projects,

representing 24,833 MW of capacity, as operational

through 1987.22 Meanwhile, estimates of future

capacity growth vary widely. Several estimates

suggest that roughly 38,000 MW of nonutility

capacity will be on line and selling power to utilities

by 1995.23 By the year 2000, some studies estimate

that nonutility capacity will range from 40,000 to

80,000 MW.

Changes in Company Business Strategies

A number of important trends in the utility

industry operating and regulatory environment have

led many utilities to undertake fundamental reassessments of their corporate strategies in the 1980s.

In general, utilities have begun to function more like

competitive, market-driven businesses in response

to an increasingly competitive and less regulated

operating environment. The new, more competitive

operating environment is the result of a variety of

factors, including dissatisfaction with the results of

traditional rate-of-return regulation, greater interfuel

competition, changes in the industry’s cost structure,

and technological developments. (Some of the

implications of a more competitive industry are

shown in figure 2-9.) In the process of adapting to

this new environment, the utility industry has shifted

from a very homogeneous one—in which virtually

all individual companies were pursuing the same

strategy, namely to build new generating capacity to

satisfy growing customer demand—to one in which

companies are pursuing distinctly different business

Figure 2-9--Implications of Competition

for Electric Utilities

Noncompetitive environment:

● Cost-based pricing

. Supply-oriented

. Regulatory allocation of cost across customer classes

. Obligation to serve all customers

. Service reliability a part of the obligation to serve

. Construction costs included in rate base

● Integrated services from power plant to customer meter

. Resources based on needs of service area

. Cost centers managing to budget

Competitive environment:

. Market-based, more flexible pricing

● Demand-oriented

. Cost management systems allocate cost by market segments

. Ability to “cherry pick” customers

● Reliability negotiated based on customer need

. Construction costs at risk

. Pressure to separate generation, transmission, and distribution

services

. Resources allocated based on profitability

● Profit centers managing performance

SOURCE: Electric Power Research Institute, Competition. Pressures for Uranga

(Washington, DC: Jurm 1967).

z] *IEEI: @er 25,000~of Non-utility Capacity WaS in SeNice ,4s of 1986, ” Electric Ufilily Week, Aug. 5, 1988, p. 13.

LzE~r~ Users News, supra note 12, p. 1.

23sW Dougl~ Cogm and sus~ Wl]ll~s,Ge~r@lngE~erg}~ Aherndves —1987Edition (Washington, DC: Investor Responsibility RcsearchCcnter,

May 1987); and RCG Hagler, Bailly, inc., supra note 12.
48 ● Electric Power Wheeling and Dealing: Technological Considerations for Increasing Competition

strategies. These strategies can be summarized as

follows: 24

Modified Grow and Build

A number of utilities have continued to view the

completion of large nuclear and coal plants, initiated

in the 1970s, as their best option. This strategy is

largely a continuation of that used by virtually the

entire industry since its beginning. In the new utility

environment, however, it typically includes increased emphasis on marketing to both retail and

wholesale customers. Some utilities are also emphasizing growth through mergers or the acquisition of

other utilities.

Capital Minimization

Many utilities are continuing to react to both

overbuilding in the industry and regulatory uncertainty with a strategy of minimizing capital expenditures in order to minimize financial and corporate

risk, Elements of this strategy include canceling

plants both planned and under construction, increasing use of purchased power, participating in joint

ventures if construction is necessary, selling excess

capacity, rehabilitating existing plant, and devoting

increased attention to energy efficiency and loadmanagement programs.

Diversification

A majority of investor-owned utilities have begun

to diversify their business interests by investing

revenues in potentially more profitable business

ventures outside the electric utility business. Salomon Brothers Inc., for instance, found that 58 of the

100 utilities it follows have diversified or indicated

an intention to diversify, including 24 that have

formed holding companies during the past 5 years.25

While the level of these expenditures is still relatively small for most utilities, a number of utilities

now have sizable nonutility interests and the overall

level of diversification activities in the industry is

continuing to increase at a rapid pace. Pacificorp,

one of the most diversified major electric utilities,

obtained nearly half of its total revenues in 1987

from operations outside of the electric utility business, including coal, gold and silver mining, regulated and unregulated telecommunications businesses, and financial services.

Nontraditional Energy Technologies

Some utilities have embarked on a strategy of

significantly increasing reliance on alternative energy sources (including cogeneration, renewable

energy sources, and other power supplies from

nonutility sources) in an effort to reduce construction lead times and other risks from traditional

power plant construction, mitigate public concerns

about the environmental impacts of power generation, and shift supply risks to outside entities. Many

more utilities have initiated increased research and

development programs in new technologies, but

they are adopting a “wait and see” attitude about

major commitments to these sources.

Outlook

At present, the utility operating environment

remains quite uncertain, so it is common to find

utilities pursuing more than one of these strategies

simultaneously. There is a considerable amount of

strategic positioning and experimentation taking

place, but only a few utilities seem confident to make

major strategic bets about the future direction of the

industry. Most utilities seem to be attempting to

hedge their risks by adopting measures to limit

capital expenditures on the utility side of the

business while attempting to gain experience with

diversification into nonutility businesses. As market

forces continue to exert a greater influence over the

bulk power industry, utilities will be pressured to

more clearly define and implement their strategic

plans, and competition and rivalry between utilities

are likely to continue to grow.

Industry Restructuring Trends

As one means of implementing their new business

strategies, utilities are beginning to adopt a variety

of financial restructuring measures designed to

improve their operational and financial flexibility.

Among the most significant types of financial

restructuring evolving are sale-leaseback transactions, joint venture agreements with nonutility

24For fufier d]~ussion of ~e~ s~ate@ and utility implementation of them, see Scott A. Fenn, America’s Electric Ucificies.’ Under Siege and in

Transition (New York, NY: Praeger, 1984).

25Mark Luftig et al., “Electric Utility Diversification, “ Salomon Brothers, k., October 1988.
Chapter 2—An Overview of the Changing Electric Power Industry ● 49

companies, vertical disintegration, negotiated mergers, leveraged buyouts, and hostile takeovers.26

Sale-Leaseback Arrangements

One of the most common forms of restructuring

that utilities are using is sale-leaseback transactions

as an alternative to traditional finance methods.

Utilities have used such transactions in the past for

small facilities. Recently, however, they have begun

utilizing lease financing in the funding or refunding

of major assets. These transactions generally involve

utilities selling generating plants or power lines to

institutional investors and agreeing to lease back

these facilities under a long-term contract, typically

at very attractive rates relative to existing debt. In

1987, for example, Kansas Gas & Electric Co.

arranged the sale and leaseback of the La Cygne 2

coal plant with U.S. West Financial Services for

$400 million. Since the beginning of 1986, 11 power

plants, including 4 nuclear plants, have been sold or

put up for sale under sale-leaseback arrangements .27

Joint Venture Agreements

Another restructuring strategy being adopted by

some utilities is the use of joint venture agreements

with nonutility companies. Utilities have long been

involved in joint venture arrangements among

themselves to construct major generating facilities

and transmission lines. In recent years, however,

some utilities have begun pursuing joint ventures

with nonutility entities as a way to recapitalize

certain assets or to enter new businesses. Perhaps the

best examples of utilities using joint ventures to

enter new business areas are the joint ventures

emerging between utilities and nonutility power

producers in the area of cogeneration and independent power projects. In April 1987, for example,

Dominion Resources Inc., the holding company for

Virginia Power, announced that it was forming a

joint venture with a subsidiary of CSX Corp. to

develop coal- and gas-fired cogeneration projects in

New England and the Middle Atlantic States. In the

past 2 years, a.t least 10 such joint venture arrangements have been announced, suggesting that utilities

see such ventures as an important way to participate

in the evolving market for unregulated generating

projects.

Vertical Disaggregation

Vertical disaggregation, or the “unbundling” of

utility companies based on the functions that they

perform, is another concept that a number of utilities

are actively considering or pursuing. Basically, this

involves the separation of all or portions of a utility’s

generation, transmission, and distribution functions

into two or more entities that are owned and operated

independently of each other. The British Government has also expressed an interest in ‘‘unbundling”

utility functions to promote competition. Information on the British proposal is presented in box 2-B.

Utilities are exploring vertical disaggregation for

various reasons, including:

●

●

●

fears of disallowances by State regulators for

imprudent costs for new power plants entering

service,

a desire to attain greater flexibility in future

pricing (because many disintegration proposals

would allow utilities to fall under Federal

jurisdiction over wholesale power sales), and

as a way for the securities markets to differentiate the individual risk characteristics of the

various components of the electric power

business.

State regulators have expressed considerable opposition to the major vertical disaggregation proposals that have been made to date, which include a

proposal by Commonwealth Edison Co. to put three

of its nearly finished nuclear plants into a separate

but wholly owned generating company subsidiary

that would sell power back to the utility and a

proposal by Public Service Co. of New Mexico to

separate its operations into independent generation

and distribution companies. It should be noted that

the Commonwealth Edison Co. proposal has been

defeated and the Public Service Co. of New Mexico

proposal withdrawn.

~For a detail~ discussion of utility restructuring activities, sw SCOtt A. Fem. “Competition and the Role of the Capital Markets in Restructuring

the Electric Power Industry,” OTA working paper, December 1987; and Scott A. Fenn, Mergers and Financial Restructuring in the Electric Power

Industry (Washington, DC: Investor Responsibility Research Center, May 1988).

ZTBo~ investor-owned utilities and electric cooperatives have used sale-leaseback arrangements.
50 ● Electric Power Wheeling and Dealing: Technological Considerations for Increasing Competition

Box 2-B-Creating a Competitive Generation Industry in Great Britain

In February 1988, Britain’s Department of Energy proposed to privatize its electric utilities in England and

Wales. The proposal is aimed at promoting competition by eliminating the industry’s monopoly on generation.

Current Industry Structure

The Central Electricity Generating Board (CEGB) produces almost all (95 percent) of the power used in

England and Wales today. It also owns and operates the transmission grid, which includes interconnections with

Scotland and France. The CEGB plans capacity additions, specifies plant design and performance requirements, and

supervises construction. The CEGB sells its power to 12 nationalized distribution entities, called area boards, which

distribute the electricity to customers. According to the government, the CEGB is “an effective monopoly in areas

where this is unnecessary and harmful to the interests of customers,’”

Proposed Changes

The government’s proposal separates generation from transmission and distribution. The CEGB will be

divided into two competing generation companies and an independent national grid company. The two generating

companies-National Power and Power-Generation—will own 70 percent and 30 percent of existing plants

respectively, The 12 area boards will be privatized as licensed distribution companies that can purchase power from

a number of sources, including the two newly created generation companies, private generators, or foreign suppliers.

Distributors also may construct their own generating units or enter into joint ventures to produce electricity. The

area distributors will jointly own and control the new National Grid Company. The National Grid Company will

be responsible for coordinating power plant operation and for acquiring new capacity through competitive bidding.2

Contracts will provide the basis for business relationships among generators, distributors, and the grid

company. The distributing companies can contract for power supplies with the generators directly or through the

grid company. In both cases, the Grid Company would have to be involved in order to ensure the reliability of the

entire system. The national government will regulate prices in the retail market but not in the wholesale market.

Adjacent regional distributors will be free to compete for large customers.3

Furthermore, the government proposal specifies that generation, transmission, and distribution companies be

licensed by the Energy Department. The four kinds of licenses proposed cover: 1) companies that control

low-voltage distribution lines, 2) companies that have more than 50 MW generation capacity and sell to the

wholesale market, 3) companies that sell to a specific user or situation, and 4) the National Grid Company.4

R&D facilities will be divided among the three new companies. These labs will conduct research for all three

new companies until the official split in the early 1990s. After that, companies will conduct their own independent

research, although some research may continue to be jointly funded.s

The Department of Energy is seeking approval for its proposal (in the form of a‘ ‘Royal Assent”) by summer

1989,

Ipn”vdislw Electr~l~T~ cover~~s Proposa[sjor tk Privatisation o~the Electricity supply Itrdu.$lry in E@~ ~w~~, w~t~ to ‘arlimm[

by tie Secretary of State for Energy by Cornrrtarxf of Her Majesty, Februaty 1988.

21bid.

31bid.

4$cFsjs p]ay: Britiw Define T- of New L iccnses for Generating Companies,” Energy Daily, Dec. 8, 19S8, p. 3.

51~Bnti~ TU~e Trjc~ T* of ~vi~g El~~ci~ R&D After privatization, ” Energy D~”fy, NOV. 18, 1988, p. 1.

Negotiated Mergers, Acquisitions, and Light Co. has recently been completed and a

Leveraged Buyouts proposal by SCEcorp. to merge with San Diego Gas

& Electric Co. is being pursued by the companies but

Negotiated or “friendly,” mergers between utili- is experiencing opposition. Hostile takeovers and

ties are likely to be one of the most significant types acquisitions are likely to be difficult in the utility

of utility restructuring activity. For example, a industry because of regulatory concerns, but it

merger between the Pacificorp and Utah Power & appears possible that some hostile transactions will
Chapter 2—An Overview of the Changing Electric Power Industry ● 51

succeed, particularly in cases where the strictures of

the Public Utility Holding Company Act of 1935 are

not invoked. Leveraged buyouts (LBO), in which a

small group of investors buy out a company’s public

shareholders at a premium, usually using the target

company’s asset base or cash flow to support a

highly leveraged capital structure, have not been a

factor in the electric power industry to date, although

there have been at least two attempts to take a utility

private in an LBO-type transaction.

Although actual merger and acquisition activity

has not lived up to many people’s expectations, the

pace of such activity has clearly begun to quicken,

with about 10 merger or acquisition proposals

announced in the last 3 years.28

Public and Private Power Takeover Battles

Another type of restructuring activity underway

involves attempts by city or State governments to

gain control of investor-owned utilities, and attempts by investor-owned utilities to gain control of

publicly owned utilities. The catalyst for a number

of these takeover situations of the first type appears

to be the prospect for dramatic rate increases related

to nuclear plant construction or operation. A number

of city governments are looking at the option of

creating municipal utilities to take over investorowned electric distribution systems, although this

option was made considerably less attractive by the

passage of tax legislation late in 1987 that largely

precludes State and local governments from using

tax-exempt financing to acquire private electric

utility assets. Among the large cities studying the

municipal takeover option are Chicago, New Orleans, and Albuquerque. There also appears to be

considerable interest, however, in what are essential] y buyouts of municipally owned and cooperative

electric systems by the investor-owned sector.

Measures of Financial Health

Declines in utility industry capital spending have

had a favorable impact on the industry’s overall

financial performance and health in recent years. In

fact, by some measures, the industry’s financial

position is now stronger than it has been since the

industry’s “golden age” of the 1950s. Among the

indicators commonly used to monitor the industry’s

financial health are internal cash generation, capitalization ratios, bond ratings, and trends in returns

on equity and rate decisions.

Internal Cash Generation

The decline in industry capital spending is particularly significant because it is Occurring at a time

when the power industry’s internal cash generation

capability is climbing—meaning that less and less of

the industry’s capital spending needs to be externally financed.

As shown in figure 2-10, Salomon Brothers Inc.

predicts that the utility industry will finance 77

percent of its construction expenditures from internal funds in 1988, 85 percent in 1989, and 95.5

percent in 1990-up from only about 33 percent in

1980. In addition, Salomon Brothers estimates that

by 1990,40 percent of all electric utilities it monitors

will be generating 100 percent of the capital they

need for construction from internal funds.z9

Capitalization Ratio

The improvement in the industry’s financial

position in recent years can also be seen in the

industry’s capitalization ratios. As shown in table

2-7, the percentage of common equity in the

industry’s capital structure is now at its highest level

in more than 20 years, and is continuing to improve.

In fact by this measure, the industry’s financial

position is now the strongest it has been since the

1940s.

28 A~ong the “Ulitles invo]v~ in merger and acquisition activities in recent years are Cleveland Electric [hrninating CO. and Toledo Edison CO.

(merger announced in June 1985); Public SeMcs Co. of Indiana (informal LBO bid by outside invesment WOUP h October 1986 was spumed by

management); Newport Electric Co. (hostile tender offers in 1986 and 1987 rcsuhing in IWW onership); pacifico~~d Utah power & Light Co. (merger

announced in August 1987 and approved by FERC in October 1988); Pacific Gas & Electric Co. (proposal to buy !krarnemo Municipal Utiljry District

made In September 1987 and later dropped); The Southern Co. (agreed to acquire Savannah Electric & Power in October 1987); Public Service Co. of

Ncw Hampshire (has received overtures from severat New England utilities after filing for bankruptcy in March 1988); SCEcorp and San Diego Gas&

Electric (merger agreement reached in November 1988 ending San Diego Gas & Electric’s previous agreement to merge with Ihcson Electric).

2(? Sa]omon Brolher~ Stwk Rese~ch, Electr~ (Jtlli(y Quall~ Me~uremeti~uarteriy Review, Jan. 26, 1989, p. 11.
52 ● Electric Power Wheeling and Dealing: Technological Considerations for Increasing Competition

Figure 2-10-internal Cash Generation and

Construction by Investor-Owned Electric Utilities,

1980 (billions of dollars)

3 0

20

10

o“

19801981198219831984 198519861987198819891990

- Internally Financed Construction

E = estimate.

SOURCE: Salomon Srothars SWJck %saarch, “Elactrk UUllty Oudty Maasurwnants,

Quarlwiy Raviaw,” Jan. 26, 1969.

Bond Ratings

Although the utility industry’s fundamental financial position has improved substantially over the

past decade and is now quite strong, there are at least

some indications that this improvement may be

offset somewhat by a more risky operating environment. The industry’s average bond ratings, for

instance, have not improved over the past decade,

primarily because ratings agencies believe that

improvements in the industry's fundamental financial condition have been offset by increased business

risk resulting from the growth of competitive forces

and new regulatory approaches. During 1987, all

four major utility bond ratings agencies downgraded

the ratings of more utility debt securities than they

upgraded. The bankruptcy filing by Public Service

Co. of New Hampshire in 1988, the first major

private electric utility bankruptcy in more than 50

years, may further increase perceptions of risk in this

industry by securities ratings agencies. Moreover,

the overall improvement in the utility industry’s

financial position has not been spread evenly throughout the industry. Utilities with nuclear plants still

under construction, in particular, appear to remain

quite vulnerable, as is reflected in the fact that five

such investor-owned utilities carry bond ratings that

are below investment grade.

Allowed and Earned Returns

In addition, allowed and earned rates of return in

the industry are falling as regulators adjust to the

lower interest rate environment of the mid- 1980s. As

figure 2-11 shows, allowed returns on equity for the

industry fell from nearly 16 percent in 1982 to just

below 13 percent in 1988—although the spread

between utility allowed returns and bond yields has

actually widened somewhat during this period.

Earned returns, the amounts actually earned by

utilities, have also been falling since 1984 and

actually exceeded allowed returns in 1987.

Trends in Rate Decisions

Recent trends in electric rate case actions-shown

in table 2-8--confirm that many regulators believe

that the industry’s rate of return is, if anything, more

than adequate. Rate increases granted by regulators

have been dropping sharply in recent years due to

declining interest rates, lower allowed returns on

equity, and decreases in State and Federal income

tax rates. In 1987, in addition to approving $2.3

billion in rate increases, regulators ordered more

than $1.4 billion in annualized electric rate decreasesTable 2-7-Capitalization Ratios of Electric Utility Industry, 1965-87

Capitalization 1965 1970 1975 1980 1985 1987

Common equity . . . . . . . . . . . . . . . 38.3% 34.1 % 34.3% 36.50/o 41.470 41 .5%

Preferred and

preference stock . . . . . . . . . . . . 12.1 11.7 9.5 7,9

Long-term debt . . . . . . . . . . . . . . . 50.6% 53.0 50.8 48.6 48.1 48.2

Short-term debt . . . . . . . . . . . . . . . 1.8 3.4 2.9 3.2 1.0 2.4

SOURCE: lmnard l+yman, Amefica’s Ekctrk UUMaa.’ ~st, %aaant ad Future (Arhngton, M: Publk IMitias Raports, IW adltbn): md Salmon Srolhars ~ Raaaawh,

“Quartariy Raviaw,” Apr. 15, 1966.
Chapter 2—An Overview of the Changing Electric Power Industry ● 53

Figure 2-n-Electric Utility Allowed and Earned

Returns on Equity, 1976-87

I

1 6 ;

14

12

10

8

1976 1978 1980 1982 1984 1986 1988

 Earned retur n Allowed retur n

— Single-A bond rate

SOURCE: Salomon Brothers Stock Reaaarch, “Electric Utility Regulatlon—

Samlannual Raviaw,” Sept. 6, 1986.

the first time ever that rate decrease amounts have

surpassed $1 billion.30

THE EXISTING REGULATORY

STRUCTURE

In the United States, Federal, State, and local

governments exercise jurisdiction over the activities

of the electric power industry. Like other businesses,

the electric power industry is subject to laws and

regulations governing financial transactions, employment practices, health and safety, and environmental impacts. But unlike other businesses, it

(along with segments of the transportation and

telecommunications industries) is subject to the

additional requirements of public utility regulation.

The electric power industry is one of the most

heavily regulated with virtually all aspects of power

generation, transmission, and distribution under the

oversight of State and/or Federal agencies.

The Concept of a Public Utility

Because their activities provide vital services to

businesses and communities, public utilities enjoy a

special status under State and Federal law that

distinguishes them from other enterprises. This

status confers specific rights and obligations. Generally, a public utility has:

●

●

●

●

an obligation to serve all customers in its

service area (within its available capacity

limitations);

an obligation to render safe and adequate

service, including meeting foreseeable increases

in demand;

an obligation to serve all customers within each

service class on equal terms (i.e., with no unjust

or undue discrimination among customers);

and

an obligation to charge only a ‘‘just and

reasonable” price for its services .31

In return for assuming these obligations, the

public utility enjoys certain “rights.” First, the

utility has a right to reasonable compensation for its

services, however recovery of a specific authorized

rate of return is not guaranteed.32 Second, through its

franchise and certificate of public convenience and

necessity, the utility generally is protected from

competition from other enterprises offering the same

service in the same service territory. Third, the

public utility has a right to conduct its operations and

render service subject to reasonable rates and

regulations. Finally, in many States, public utilities

can exercise the right of eminent domain to condemn

and take private property for public use where

necessary to provide adequate service, subject to the

requirement of just compensation to the owner.33

Federal and State Regulation

of Electric Power

Both State and Federal laws define any entity that

sells electricity as a public utility34 thus bringing

SoEdison Electric Institute, “Rate Decrease Amounts Top OrrC Billion Dollars in 1987,” EE1 Finuncia/ /r#o, Apr. 12, 1988.

sl~wles F. phi]]ips, Jr., Th~ ~egu~~on Of f~lic utilities ~ Theory and Practice (Arlington, VA: Public Utilities Reports, Inc., 1984), p. 106.

3zRe@latoV authorities Cmnot force a utili(y to operate at a IOSS. However, irt times, the Utihty may 130t iiClud]y CiiM ilS authorized rate Of return bCCauSC

of adverse economic conditions or poor business judgment. The rate will be upheld by the courts if it is de[crmined to be reasonable.

33phll]lps, supra note 31. P. IW.

34sW, for ex~ple, tie definition of art electric utility in the Federal power ~t m; “any person or State agency which sells electric cncrgy, ” 16 U.S. C.

7%(22), and the definition of “electric utility company” in the Public Utility Holding Company Act as ‘any company which owns or operates facilities

used for the generation, transmission, or distribution of electric energy for sale, ” 15 U.S.C. 79b(a)(3).
54 ● Electric Power Wheeling and Dealing; Technological Considerations for Increasing Competition

Table 2-8 Annual Electric Rate Case Actions, 1983-87

Number of rate actions Total amount (millions of dollars)

Year Increases Decreases Increases Decreases

1983 . . . . . . . . . . . . 241 17 5,373.4 59.1

1984 , . . . . . . . . . . . 186 19 4,745.0 175.0

1985 . . . . . . . . . . . . 127 17 4,989.7 129.7

1986 . . . . . . . . . . . . 104 21 2,880.9 383.0

1987 . . . . . . . . . . . . 86 117 2,304.3 1,441.8

SOURCE: Edism Electric Institum, 1996.

generators and retail distributors of electricity under

regulation. Jurisdiction over the activities of electric

utilities is split between the Federal Government and

State agencies (including local governments). This

division reflects both the historical growth of

electric utility regulation in this country, which

began at the State and local level, and the Federal

Government’s constitutional authority over interstate commerce. Most generators are now subject to

both Federal and State rate regulation.

The split jurisdiction was formalized with passage

of legislation in 1935 that gave the Federal Power

Commission authority over interstate transmission

and sale of electric power at wholesale.35 T h e

creation of a strong Federal role in the regulation of

interstate activities in electric power was prompted

by the 1927 Supreme Court ruling that State

regulatory agencies were constitutionally prohibited

from setting the prices of electricity sold across State

lines because it would violate the Commerce

Clause. 36 This decision created a gap in effective

regulation of electric utilities.

Federal regulation of interstate and wholesale

sales was initially seen as a supplement to State

authority to fill a gap where existing State regulation

had proven ineffective or unconstitutional. But as

interconnections among utilities grew and longdistance transmission increased, virtually all electric

power moving over transmission lines was viewed

as being in interstate commerce and hence subject to

exclusive Federal jurisdiction. Ever more expansive

interpretations of Federal jurisdiction have now

arguably limited State jurisdiction over wholesale

sales and wheeling transactions, even when they

involve instate parties.37

Federal Regulation

The major Federal regulatory agency for electric

utilities is FERC, the successor to the Federal Power

Commission. FERC is a five-member independent

regulatory commission within the Department of

Energy. It derives its primary authority from the

Federal Power Act, as amended.38

FERC has authority over the prices, terms, and

conditions of wholesale power sales involving

privately owned power companies and of transmission of electricity at wholesale.39 Because the power

systems in the ERCOT region of Texas, and in

Alaska and Hawaii are not synchronously connected

to power systems in other States, FERC does not

have jurisdiction over most power transactions in

these States. FERC must approve sales and mergers

of public utilities under section 203 of the Federal

Power Act.40 It has jurisdiction over the issuance of

securities and indebtedness of electric utilities.41

ssTit]e II of he public Utility Act of 1935, known as the Federaf Power Act, 16 U.S.C. 791a.

sbp~lic UtllltiesCow.ssion of Rhode Iskmd v. Attleboro Steam & Electric CO., 273 U.S. 83 (1927).

37s= Feder~lPowerco-~sio~”.so~herncallforn~ E&OnCO,, 3Ttj U.S. ZOS (1968), ~.SO known u Cit’YofCoiton v. Southern Caliform”a Edison

CO. See also Florida Power & LightCo., 29 F.E.R.C. 61,140 ( 1984) in which FERC asserted exclusive Federal jurisdiction over virtually all transmission

setvice in Fforida.

‘1816 U,S,C. 791a.

Wsw W-. 201 ad 205 of (,he F~r~ po~r ~t, 16 U.S.C. tQ4a md 824d, respectively.

4016 U.S.CO g~bt

q] 16 U.S.C. 824c.
Chapter 2—An Overview of the Changing Electric Power Industry ● 55

FERC also oversees power pools and interconnections among utilities.42

As part of the responsibilities inherited from the

Federal Power Commission, FERC oversees and

licenses nonfederal hydroelectric projects on navigable waters under Title I of the Federal Power

Act,43 In addition, FERC approves the rates for

public power sold and transported by the five

Federal Power Marketing Agencies.

The Public Utility Regulatory Policies Act of

1978 (PURPA) amended the Federal Power Act and

gave FERC expanded responsibilities for the encouragement of cogeneration and small power

production using alternative energy technologies.44

The goals of PURPA were to advance: 1) conservation of electric energy, 2) increased efficiency in

electric power production, and 3) achievement of

equitable retail rates for consumers. This was to be

achieved in large part by requiring utilities to

interconnect with and buy power from cogenerators

and small power producers that met standards

established by FERC. This requirement was the first

major Federal move to open up electricity markets to

nonutilities. At the same time, PURPA exempted

these qualifying facilities (QFs) from most of

regulatory burdens applicable to public utilities

under Federal and State law in order to reduce the

institutional barriers to QF development.

PURPA requires that electric utilities must offer

to purchase electricity from QFs at their avoided

costs and to sell electricity to QFs on nondiscriminatory terms and conditions. In addition, utilities must

offer to interconnect and operate in parallel with

QFs. The rates paid for QF power must: 1) be just

and reasonable to electric consumers and in the

public interest, 2) not discriminate against QFs, and

3) not exceed the cost of electric energy that the

utility would generate itself or purchase from

another source.45 The rates charged to QFs for

supplemental or backup power must be just and

reasonable and not discriminate against QFs.

FERC was given the lead responsibility to issue

regulations and guidelines implementing PURPA,

but State regulatory commissions were given the

primary authority for setting avoided cost rates and

conditions for PURPA purchase and sale contracts.

FERC has continuing responsibility for overseeing

PURPA implementation and in March 1988 issued

three notices of proposed rulemaking (NOPRs) that

would alter the original PURPA regulations to

correct perceived shortcomings in State avoided cost

determinations and to allow the use of competitive

bidding in setting QF payments.

In addition to the interconnection and purchase

requirements, PURPA also gave FERC explicit,

though severely limited, authority to order an

electric utility to transmit over its lines power

produced by another generator.46 Whether FERC

has any inherent authority to order wheeling services

under other provisions of law is a matter of some

controversy and debate. Until recently, FERC and

many legal experts concluded that FERC had no

wheeling authority under the Federal Power Act

because Congress had expressly rejected such a

provision in passing the Act.47 Recently, it has been

suggested that FERC has the inherent authority to

require a utility to wheel power for others as a

condition of approving wholesale rates, mergers and

4216 us-c. fJ~b,

4316 U.S.C. 791a to 823.

44~blic Law 95.615,92 st~. 31 ]7, Nov. 9, 1978.

4Spub]ic Law 95-615, sec. 210, 92 Stat. 3144, 16 U.S.C. 824a-3.

46puRpA ~Se Z03 ~ Z04 ~e~~the F~=~ Power Act 10 add new sea. 211 and 212, codified as 16 U.S.C. 8Xj ~d 16 U.S.C. 824k, respectively.

QT~ offer Tall power c. v. fJn[ted st~es, 410 U.S. 366, at 375 (1973), the IJ.S. Supreme COLUI noted in dicta that the Fedcrat power Act did not

grant any authority to order wheeling, but that wheeling could be ordered by the Federal Courts as a rcmedy under the antitrust laws. A similar conclusion

on wheeling authority is reached in National Regulatory Research Institute, Non-Technicul Impediments fO Pmer Transfers. September 1987, pp. 52-68,

although the author notes that FERC may have some as yet untested authority to order wheeling as a remedy for artti-competitwe behavior under sees.

205 and 206 of the Federal Power Act, id. at note 45, p. 64, See also Florida Power& Light Co. v. FERC, 660 F. 2d 668 (5th Cir. 1981), p. 679. The

report of the Conference Committee on PURPA is vague on the extent of any existing wheeling authority FERC might have outside of sees. 211 and

212 and notes that PURPA is not intended to affect existing authority, House Conference Report 95- 17S0. 10 accofnp~y H.R. 4018! 95th Cong.t 2d SCSS.~

Oct. 10, 1978, pp. 91-95, 1978 U.S. Code Congressional and Administrative News 7825-7829.
56 ● Electric Power Wheeling and Dealing: Technological Considerations for Increasing Competition

acquisitions, or participation in competitive generation markets.48

The Public Utility Holding Company Act of 1935

(PUHCA) was passed in conjunction with title II of

the Federal Power Act.49 It gave the Securities and

Exchange Commission (SEC) broad authority over

the structure, finances, and operations of public

utility holding companies. PUHCA was enacted in

response to widespread concern over the influence

of a handful of large interstate utility holding

companies that by 1932 controlled over 75 percent

of the private electric utilities. The holding companies’ complex corporate structures and interlocking

business arrangements had frustrated both State and

Federal oversight of their activities, led to substantial investment fraud, and weakened or bankrupt a

number of local gas and electric utilities.so PUHCA

was intended to limit severely the use of the holding

company structure and to force the regional consolidation of the existing large multi-State holding

companies.

Under PUHCA any company that owns or controls more than 10 percent of the voting securities of

a public utility is considered to be a public utility

holding company. An electric utility company is any

company which owns or operates facilities used for

the generation, transmission, or distribution of

electric energy for sale. The holding companies are

subject to extensive regulation of their financial

activities and operations under PUHCA. Public

utility holding companies can qualify for an exemption from the most stringent regulatory oversight of

PUHCA if they operate wholly within a State, or in

contiguous States, or the company is only incidentally a holding company, is primarily engaged in a

business other than the public utility business, and

does not derive a material part of its income from the

public utility business. 51 Non-exempt entities are

registered holding companies and are limited in their

operations to “a single integrated public-utility

system, and to such other businesses as are reasonably incidental, or economically necessary or appropriate [there]to.” Integration means that the utility

operations are limited to a single area or region of the

country. Registered holding companies must obtain

SEC approval of the sale and issuance of securities;

transactions among their affiliates and subsidiaries;

and services, sales, and construction contracts. In

addition the companies must file extensive financial

reports with the SEC. In contrast, exempt companies

need only file limited annual reports with the SEC.

The REA also exercises some regulatory oversight of cooperatives holding Federal loans. The

extent of this regulation is primarily directed at

assuring the financial viability of the cooperative

entities to repay their Federal loan obligations. At

times the REA has ordered cooperatives to raise

rates to their customers to cover costs.

State Regulation

State regulation of electric power is diverse and

only broad generalizations can be made. State

regulation is conducted by multimember boards or

commissions whose members may be either appointed or elected. The utilities under State jurisdiction vary-some States regulate all utilities, including publicly owned systems and cooperatives, while

others limit jurisdiction to investor-owned systems

and leave regulation of municipal systems to local

dgIn Re Utd power & Ljg~Co., eta/. (C)ct. 26, 1988), FERC approved the merger of Utah Power & Light Co. into Pacific Power & Light CO. Sub@t

to the condition that the merged companies provide firm wholesale transmission services at cost-based rates to any utility that requested such service.

The condition was necessary to prevent the future exercise of market power by the new company to foreclose access by competitors to bulk power markets.

The decision was reached under sec. 203 of the Federal Power Act which requires commission approval of mergers and acquisitions. The extent of any

inherent conditional authority of FERC to order wheeling under other sections of the Federal Power Act is still uncem.in. FERC has solicited comments

on imposing ‘wheeling in” and” wheeling out” conditionson utilities participating in bidding programs. Notice of Proposed Rulemaking on Regulations

Governing Bidding Progrsms (18 CFR Pam 35 and 293), Docket No. RM88-5-000, Mar. 16, 1988, pp. 87-91. “Wheeling in” would require a utility

bidding on the capacity needs of another utility to agree to provide firm transmission services to the purchasing utility for successful bidders that are located

in its service area or that can reach one of its interconnection points. “Wheeling out” would require a utility bidding to supply its own capacity nods

to provide firm transmission services in and through its service area to unsuccessful bidders that wished to sell to another wholesale purchaser. For an

expansive exposition of the argument that FERC has and is required to use conditional wheeling authority to deal with potentially anti-competitive

situations, see the comments of the Electricity Consumers Resource Council ct al. filed in Docket RM88-5-OtXt, July 18, 1988, and Reply Comments

filed Sept. 13, 1988.

dg~t of Aug. 26, 1935, c. 687, Title 1, sec. 33,49 Stat. 438, 15 U.S.C. 79.

SOFor a diwuwion of he s~ctwe~ifiuew of the holding companies, MX ~on~d S. Hym~, America’s Electric Utilities” pat, Present and

Future, 3d ML (Arlington, VA: Public Utilities Reports, Inc., 1988), pp. 71-83.

5115 us-c. 79C+
Chapter 2-An Overview of the Changing Electric Power Industry .57

governments. In addition to control over prices,

States or local governments control market entry and

determine who may operate as an electric utility by

granting certificates of public convenience and

necessity and awarding franchise territories.

All States regulate retail prices of electricity. In

setting retail rates, State regulators must approve a

level that provides a reasonable rate of return to the

utility which will cover its costs of providing service

plus a profit. Under various formulations, many

States require that utility investments be determined

to be prudent and ‘used and useful ” before they can

be recovered through retail rates. Some States allow

recovery for plants under construction, while others

defer recovery until the plant is actually in operation.

Many States also regulate other aspects of utility

operations in some detail including planning and

determination of resource needs including new

generation, bulk power purchases, and construction

of transmission and distribution facilities.52 A number of States regulate the siting of utility facilities

either through the public utility commission or a

separate siting agency .53

Several States have included wheeling provisions

in their competitive bidding programs. However, the

extent to which State regulatory authorities can

require wheeling is uncertain because of the possibility of preemption by FERC under section 201(b)

of the Federal Power Act.54 FERC has asserted

authority over the rates and conditions of transmission in interstate commerce and has argued that this

preempts State regulation of these matters.55 But

FERC has so far declined to resolve the issue of

whether FERC jurisdiction also preempts State

authority to order wheeling.

While States have exclusive retail rate jurisdiction, under the Narragansett doctrine they must

generally pass through wholesale rates approved by

FERC. 56 The extent to which FERC determinations

of the reasonableness of wholesale rates preempts

State consideration of the retail impacts of those

same rates is a matter of some controversy.57 The

strain arises because State regulatory programs and

the considerations used in setting rates are generally

far more extensive than FERC’s. In some cases,

requiring States to adopt without question FERC’S

wholesale rate determinations in setting retail rates

would preclude States from exercising their own

regulatory authority over issues normally within

their jurisdiction.

The major limitation on Federal preemption is

found in the Pike County exception, which affirmed

the right of a State commission to examine the

prudence of a wholesale power purchase contract

and to disallow the pass through of FERC-approved

wholesale costs if lower cost power supplies were

available elsewhere. 58 The issue of whether States

can review the prudence of wholesale power contracts will become especially critical if proposals to

create a competitive generating sector result in

utilities relying more heavily on bulk power purchases that, except for QF transactions, fall within

FERC’s jurisdiction. The vitality of the Pike County

exception has been cast into doubt by the Supreme

Court’s 1988 decision in Mississippi Power& Light

Co. v. Mississippi ex rel. Moore that rejected State

efforts to deny a rate increase based on FERC’s

S2For ~ ~mwof State ~w~remen~ for utili~ planning and f~asting requirements, see Public Utilities &_mtrrtission of the State of ohiO,

Transmission Line Certification and Siting Procedures and Energy Planning Processes: Summary of State Government Responses to a Survey by the

National Governors’ Associatwn Task Force on Electricip Transmission, OTA contractor repott, July 1988.

53sW t~ di~uss]on of Smte siting requirements in ch. 7 of this report.

5416 U,S,C. 8~b. SW di~~ssion of his iss~ in Nati@ Regul~ory Research ImXitutc, supra nOte 4’7, pp. 70-78.

55F/orl~ Pmer & Llgh[co,~ f. fori& pub/lC Servicecommission, et al., 29 F. E.R.C. 61,140 ( 1984). SCX also tie mmarksof FERC Cofnmissimer

Charles Trabandt that FERC may not acquiesce in State efforts to require wheeling under competitive bidding programs, ‘Trabandt: Generic Action by

FERC Unlikely on Transmission Access, ” Electric Utility Week, Feb. 13, 1989, pp. 1-2.

s~~~ ~]e Wm .Wt fofi ~ f)farraga~efl E/ect~c Co. V. flur&e, 119 R.1. 559,381 A.2d 1358 (1977), cert. denied, 435 U.S. 9’72 ( 1978), one of a series

of State court d=isions that recognized Fderal preemption.

sTFor discussion of tiese issues see the following: Ronald D. hmes. ‘‘Regulations of Interstate Electric Power: FERC versus the States,” 2 Natural

Resources & Environment 3, Spring 1987; LYM N. Hargk “The War Between The Rates 1s Over, But Battles Remain,” 2 Natural Resources &

Environment 7, Spring 1987; and Bill Clinton, Robert E. Johnston, Walter W. Nixon, 111, and Sam Bratton, ‘‘FERC, State Regulators and PubIic Utilities:

A Tilted Balance?” 2 Natural Resources& Environment 11, Spring 1987.

58)Jlke como Light & power co, v. Pemlvmla p~llc utili~ co~ission, 77 pa. Comm’w. 268, 465 A. 2d 735 (1983). The po~nt.id eXCt@OI)

WaS apparently accepted by FERC in Pennsylvania Power& Lighf CO., 23 F. E.R.C. b] too5 (1983) and noted b~ U.S. SUPme COW in Na~a~~

Power & Light Co. v. Thornburg, 106 U.S. 2349 (1986).

89-137 - 89 - 3
58 ● Electric Power Wheeling and Dealing: Technological Considerations for Increasing Competition

allocation of the costs of a nuclear unit built to meet sippi Power & Light decision is limited to the

the needs of an integrated interstate holding com- particular situation of interstate holding companies

pany system on the grounds that the local subsidiar- or whether it marks further limitations on the powers

y’s participation in the project was imprudent.59 A

State prudence inquiry was preempted even though

of State regulators is not yet known. Resolution of

this controversy over conflicting Federal and State FERC had not examined the issue during wholesale jurisdictional claims will be one of the major public rate proceedings. The State regulators’ only recourse

is to challenge the prudence of the wholesale policy issues in any transition to a more competitive

arrangements before FERC. Whether the Missis- electric power industry.

sgu~slssippl p~er & L@t CO. v. Mississippi ex rel. h#oore, No. 86-1970, June 24, 1988.
Chapter 3

Alternative Scenarios for

Increasing Competition

in the Electric Power Industry
CONTENTS

INTRODUCTION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

SCENARIO 1: Reaffirming the Regulatory Compact.

Background . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Implementation . . . . . . . . . . . . . . . . . . . . . . . . . . .

System Operations and Planning . . . . . . . . . . .

SCENARIO 2: Expanding Transmission Access

the Existing Institutional Structure . . . . . . .

Background . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Implementation .. .. .. .. .. . .. ... ... ...+....

System Operations and Planning . . . . . . . . . . .

. . . . . .

. . . . . .

. . . . . .

.,....* . . . . . . . . . . . . . . . . . . . . . . . .

. . . . . . . . . . . . . . . ● ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎

✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎

✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎

✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎

and Competition Within

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

SCENARIO3: Competition for New Bulk Power Supplies . . . . . . . . . . . . . . . . . . . . . . . . . .

Background . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Implementation ... ... ... ... ... ... ... +.. ... *.. ... *.$. .*** ... .*. **""$*""""'""""""

Systems Operations and Planning . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

SCENARIO 4: All Source Competition for All Bulk Power Supplies With

Generation Segregated From Transmission and Distribution Services . . . . . . . . . . . . .

Background ... ..*. ... ... ... .. "" "

Implementation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Systems Operations and Planning . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . +

SCENARIO 5: Common Carrier Transmission Services in a Disaggregate,

Market-Oriented, Electric Power Industry . . . . . . . . . . . .

Background . . . . . . . . . . . . . . . . . . . .

Implementation . . . . . . . . . . . . . . . . .

Systems Operations and Planning

ANALYSIS OF THE SCENARIOS

. . . . . . . . . . . . . . . . . . . . .

. . . . . . . . . . . . . . . . . . . . .

. . . . . . . . . . . . . . . . . . . . .

. . . . . . . . . . . . . . . . . . . . .

Tables

Table

3-1. Summary of Alternative Scenarios . . . . . . . . . . . . . . . . . . .

3-2. Alternative Scenarios: Summary of System Operations,

and Development . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

. . . . . . . . . . . . . . . . . . . . . . . . . .

. . . . . . . . . . . . . . . . . . . . . . . . . .

. . . . . . . . . . . . . . . . . . . . . . . . . .

. . . . . . . . . . . . . . . . . . . . . . . . . .

. . . . . . . . . . . . . . . . . . . . . . . . . .

61

63

63

65

67

70

70

72

75

76

77

79

81

81

82

83

84

85

85

86

87

87

Page

. . . . . . . . . . . . . . . . . . . . ......62

Planning,

. . . . . . . . . . . . . . . . . . . . . . . . . . 68
Chapter 3

Alternative Scenarios for Increasing Competition

in the Electric Power Industry

This chapter describes the five alternative institutional and regulatory scenarios for increased competition in the electric power industry that were

developed by OTA and which are used throughout

this report.

INTRODUCTION

There have been many proposals for revamping

the electric power industry through competition,

deregulation, and restructuring, but few have been

sufficiently detailed, particularly in the area of

transmission systems operations, to support the kind

of analysis required for this assessment.l It was

necessary to explore how possible regulatory futures

of the electric power industry might evolve before

examining the technical feasibility of expanded

competition. OTA defined five alternative economic

and regulatory scenarios to capture a reasonable

range of industry futures and to form the basis of our

technical analysis. The major features of the scenarios are summarized in table 3-1.

The scenarios range from scenario 1, which makes

modest changes in the regulatory procedures for

approving new plant construction with no legislative

expansion of transmission access, to scenario 5,

which would separate the industry into generation,

transmission, and distribution sectors and impose

common carrier obligations on transmission companies. Four of the scenarios would expand access to

transmission services; two scenarios would allow

retail customers to seek wheeling orders. The

scenarios pose very different implications for the

future direction of the electric power industry and its

technical and institutional infrastructure. The scenarios derive important elements from some recent

proposals for regulatory reform and structural

change in the electric power industry, but are not

identical with any one of them.2

In discussing scenario implementation, OTA

generalizes about how electric utilities would be

affected and how State regulation might be adapted.

The typical utility structure under the scenarios is the

vertically integrated investor-owned utility. This

model, while applicable to utilities owning over 70

percent of the our generating capacity, does not

cover all of the diverse combinations of utility

structure, ownership, and State regulation characteristic of the Nation’s electric power industry. For

many aspects of the scenarios, the ownership structure of the utility is less important than whether the

utility controls and operates generating, transmission, and distribution facilities. OTA believes that

these generalizations are sufficiently representative

of most of the utilities and State regulatory schemes

to allow us to draw supportable conclusions about

the overall impacts of the scenarios.

The scenarios do not exclude public power

agencies or consumer cooperatives from full participation in the competitive generation sector. Although scenarios 4 and 5 involve significant disintegration and restructuring of the electric power

industry, they do not include provisions for “privatizing” Federal and other publicly owned power

systems. A detailed consideration of the legal,

economic, and political implications of such proposals is beyond the scope of this report.

I For bxkgound infomauon contr~lng pm propos~s for electric power industry reform -:Pti J-. kdCOW ad Richwd Schiden=, Markets

for Power: An Ana/ysIJ of Electrical Utility Deregulation (Cambri@e, MA: The MT %=S. 1$%3); ~eodore BW k Associates, “A Study of

Aggregation Alternatives in the U.S. Electric Utility Industry,” December 1982, prepared for the U.S. Deptmentof Energy, Director, Policy Planning

and Analysis, Division of Electric Utility Policy (available rhrough National lldmica.1 Information Semice). D04RG/10295- 1; U.S. Department of

Energy, Office of Policy Planning and Analysis, “lkregtdationof Electric Power: A Framework for Analysis, A Draft Discussion Paper, Phase z RCpOJI,”

September 1982 (DOE/NBB-(X121), prepared by the Massachusetts Institute of TiXtnology, under contract number Ex-76-A4112295 (available through

National lkchnical Information Service); and Edison Electric Institute, Economics Division, “Alternative Models of Electric Power Deregulation,” May

1982 (prepared by NPS Energy Management, Inc.).

zFor exmple, ~enalo 2 ~mmlsslon ~cess pr~cd~cs we b~ed ~ pm on r~O~cn@tlOnS of ~El~~icity Consumers Resource Council, ~d

scenario 3 includes elements of competitive bidding proposals by FERC Chairman Martha Hesse and the Keystone Elecrncity Forurn, among others.

41–
Table 3-l-Summary of Alternative Scenarios

Scenario 2

Expanding Transmission Access and scenario 3 Scenario 4

Scenario 1

Scenario 5

Competition in the Existing Regulated Competition for New Bulk

Strengthening the Regulatory Bargain

Competition for All Bulk Common Carrier Transmission Services

Utility Structure Power Supplies Power Supplies in a Disaggregate Industry Structure

●

●

●

●

●

●

Industry consists of a mix of vertically

integrated utilities, 10 Us, public power,

cooperatives, Federal power authorities, self-generators, QFs, and IPPs.

Existing regulatory structure with State

proapproval of new generating projects and periodic prudence reviews

during planning and construction.

Negotiated transmission access arrangements

Traditional system coordination and

control by integrated utilities or control centers.

Prices set by regulatory proceedings

and cost of service. Transmission

prices and wholesale rates set by

FERC (including approval of negotiated

IPP power purchases). State oversight of retail rates and PURPA

implementation.

Federal and public power agencies

●

●

●

●

●

and cooperatives affected only to the

extent State law provides.

Industry consists of existing mix of 

entitles.

Existing regulatory structure with wider

QF eligibility under PURPA including 

full utility ownership/control of QFs

(may require amendment of PURPA).

New Federal wheeling authority under

a public interest standard for wholesale and retail transmission access

(requires amendment of the Federal

Power Act). ●

Traditional system coordination and

control by integrated utilities or control centers with contracts for unbundled services.

Prices set by regulatory proceedings .

and cost of service. Transmission

prices and wholesale rates set by

FERC (including approval of negotiated

IPP power purchases). State oversight of retail rates and PURPA

Implementation. ●

Federal and public power agencies

and cooperates affected only to the

extent State law provides.

●

Existing mix of generating entities

expanded by IPPs and unregulated

utility generating subsidiaries.

Existing regulatory structure with marketbased rates for new competitive generation. Utilities use all source procurement for new bulk power needs.

Contracts awarded to lowest cost

supplier with consideration for nonprice factors.

Transmission access provided by utilities as a bidding condition, or by

privately negotiated arrangements,

or under new Federal public interest

wheeling authority (no retail wheeling).

Traditional system coordination and

control by integrated utilities or control centers. Unbundled bulk power

dispatch, control, and transmission

services provided through contracts.

Retail and transmission prices set by

regulatory proceedings. Wholesale

power prices set through competitive

procurement except for cost-base

plants built by utility as last resort

supplier. State and Federal regulators oversee terms and conditions of

wholesale sales.

Federal and public power agencies,

and cooperatives can participate

competitive generating sector to extent provided by Federal and State

law and policy.

Industry structure: Ownership of competitive generating sector segregated

from transmission and distribution

tiers .

New Federal and State regulatory

systems. Price and entry regulation

of generation sector replaced with

competitive market. Continued regulation of transmission and distribution

utilities and retail sales.

Revised Federal wholesale wheeling

authority. Transmission utility to plan

for and provide nondiscriminatory access for bulk power supplies.

Most of traditional utility system planning and coordination taken over by

transmission and distribution entities.

Competitive generators plan and build

generation. Transmission operator assumes responsibility for bulk power

system control and operation. Distribution utility retains retail obligation to

serve. Unbundled bulk power dispatch, control, and transmission services provided through contracts.

Bulk power prices set by market

through bidding, negotiation. Transmission and retail prices are set by

regulatory proceedings. Some State

and Federal oversight of competitiveness of generation markets and prudence of bulk power contracts.

Federal and public power agencies,

cooperatives can participate in competitive generating sector to extent provided by Federal and State law and

policy.

●

●

●

●

●

●

Ownership and control of existing

integrated utility industry is disaggregate into separate generation, transmission, and distribution segments.

New Federal and State regulatory

system. Price and entry regulation of

generation replaced with competitive

markets. Distribution utilities’ services and retail prices remain regulated. Transmission prices and activities are strictly regulated.

Transmission sector operates as a

common carrier providing nondiscriminatory access to all wholesale and retail

customers. Reasonable renditions

on reserving transmission services

may be imposed.

Bulk system planning and coordination is split among generation, transmission, and distribution entities. Generators identify, plan, and build new

generation in response to market

signals. Transmission utility assumes

responsibility for reliability of bulk

system operations. Responsibility for

estimating demand and securing adequate power supplies rests with distribution utilities. Unbundled bulk power

dispatch, control, and transmission

services provided through contracts.

Bulk power prices set by market.

Transmission and retail prices are set

by regulatory proceedings. Some State

and Federal oversight of competitiveness of generation markets and prudence of bulk power contracts.

Federal and public power agencies,

Cooperatives can participate in competitive generating sector to extent provided by Federal and State law and

policy.

SOURCE: OffICS of Tecfmology Asssssrnent, 1989.
Chapter 3-Alternative Scenarios for Increasing Competition in the Electric Power Industry • 63

SCENARIO 1

Reaffirming the Regulatory Compact

Under the traditional “regulatory contract,” a

public utility is guaranteed the opportunity to

recover all prudent investment committed to public

use and to earn a competitive rate of return on its

investment. In exchange, the utility assumes the

legal obligation to provide adequate and reliable

service at reasonable rates to all customers located in

its exclusive franchise territory. Scenario 1 reflects

the view that only modest changes in existing

arrangements and institutions governing the industry are needed to assure continued adequate and

reliable electric power supplies. This scenario differs from the status quo by the adoption of measures

to reaffirm the regulatory compact between utilities

and regulatory authorities (on behalf of utility

customers) through:

1. changes to State ratemaking policies to reduce

the investment risk for new construction and to

allow utilities to attract needed capital;

2. the modification of rules under the Public

Utility Regulatory Policies Act of 1978 (PURPA)

to address perceived imbalances in the implementation of avoided cost pricing for qualifying facility (QF) payments;3 and

3. the adoption of measures to encourage greater

access to transmission services for bulk power

transfers and the construction of additional

transmission capacity.

Proponents believe that a major benefit of regulatory reform for utilities would be the enhanced

expectation that over the long term they will be able

to recover their prudent capital investment and earn

a competitive return for their shareholders. At the

same time, customers would be assured of adequate,

reliable power supplies at reasonable rates. Some

analysts speculate that reduced regulatory risks

might eventually lead to savings for consumers from

a lowering of capital costs of new utility construction.4 Some proponents of this scenario argue that

more drastic reforms of utility regulation are unnecessary because the problems of the 1970s and 1980s

were the result of an unfortunate and unique

convergence of events and trends that are unlikely to

be repeated, and that the regulatory system and

domestic utility industry have largely adjusted to

changed conditions. Furthermore, the flexibility

with which electric utilities and the regulatory

system have responded to recent financial difficulties and competitive pressures attests to the soundness of current institutions.

Transmission access and wheeling arrangements

would be negotiated between the participants on a

voluntary basis. The Federal Energy Regulatory

Commission (FERC) would retain its authority over

transmission rates and interstate and wholesale

power sales. States would exercise jurisdiction over

resource planning, expansion, retail rates, and distribution. Public power agencies and cooperatives

would continue to be regulated as now, subject to

varying degrees of oversight by Federal and State

authorities. These changes may give requirements

customers greater input and oversight of power

supply decisions by wholesale utilities.

Utilities would remain the primary providers of

electric power under scenario 1. Cogenerators,

self-generators, and independent power producers

(IPPs) would continue to exert competitive pressures on utilities, but, except for PURPA qualifying

facilities, alternative generating sources would not

be given any special status or preference under State

or Federal regulation.

Background

Much of the current interest in increasing competition in generation can be attributed to the problems

encountered by the electric power industry over the

past 15 years in dealing with declining growth rates,

excess capacity, rising fuel costs, and steeply

escalating construction costs (especially for nuclear

3]n ~omc ~W~ ~ex ch~ges wouId lower avoid~ cat rates, but in others it is conceivable thaI unrealistically low avoided cost rates would be

increased.

4~b]ic ~tllity ~missionsmi@tIowr heau~ofiz~rate of return for utilities because of he ~UC~ regulatory risk, but some analysts question

whether preapprovals would actually lead to a reduction in the risk component of capital costs m reflected in market rates. See National Regulatory

Research Institute, Commission Preupprovaf of Utifity Investments (Columbus, OH: National Regulatory Research Institute, 1981, reissued 1987),

hereafter referred to as %eapprovals.”
64 ● Electric Power Wheeling and Dealing: Technological Considerations for Increasing Competition

plants).5 Billions of dollars in new, large-baseload

generating plants were canceled or deferred.6 Rising

utility costs and sharp rate hikes in the 1970s

reversed the postwar trend of steadily declining

electricity prices and prompted close regulatory

scrutiny of utility performance and rate requests.

Eventually regulators disallowed recovery of large

amounts of imprudent utility investment in both

cancelled and completed plants.7 The specter of

disallowances through “after-the-fact” prudence reviews contributed to a growing perception among

many in the utility industry and the investment

community that the long-standing regulatory compact had been seriously impaired. Many utilities felt

that they were no longer assured an opportunity to

recover their capital investment and eam a fair return

on investment in exchange for their obligation to

serve. In comparison with other industries, many

utility stocks posted lower returns to investors

during the early 1980s.

Spending on new plant construction has dropped

sharply in recent years. The most obvious causes are

the completion of large construction projects begun

in the 1970s and slow growth in electricity use.

Some, however, see this drop as evidence that the

industry as a whole has become substantially more

risk averse and has adopted a capital minimization

strategy in response to increased uncertainty over

regulatory decisions and greater unpredictability in

future demand growth. Some energy analysts view

this hiatus in new plant construction with alarm

because they fear additional baseload capacity may

be needed as early as the mid-to-late 1990s if

electricity demand growth increases significantly.8

PURPA has increased the amount of nonutility

generation and cogeneration and spurred investment

in and commercialization of alternative energy

technologies. The competitive pressures created by

the growth of PURPA cogeneration have forced

many utilities to engage in aggressive cost-cutting to

lower rates to avoid the loss of industrial customers.

At the same time, PURPA has further compounded

the uncertainties facing utilities. As implemented in

some States, PURPA also has required some utilities

and their ratepayers to pay for unneeded energy or

QF capacity under long-term fixed-price contracts at

avoided cost prices that are higher than the utilities’

current marginal costs of generating electricity.

Moreover, many critics of PURPA argue that it has

disproportionately favored greater reliance on oil

and natural gas as fuels.

Undoubtedly, some of the impacts of PURPA

reflect the initial difficulties and uncertainties in

implementing a complex regulatory scheme. Other

problems, however, are caused by the current

surplus of generating capacity and lower fuel

prices--circumstances that arguably are different

from those envisioned when PURPA was enacted in

1978 in an era of rising fuel costs, projected high

electricity demand growth, and fears of future

energy shortages. Already, many States have initiated changes in their PURPA implementation programs to address these changed circumstances and

reduce avoided costs while at the same time

preserving PURPA’s incentives for alternative generators.

s~~err-n fm tie ~~e~ in expx ~rnptiti~ is the political preference among some economists ttnd pcdicymakers in favor of

market-based institutions and against regulated monopolies. Ixss reliance on regulation and greater reliance on increased competition in power supplies

are seem as mechanisms for attaining the goal of economic efficiency.

6u.s. con-, con~sion~ Budget office, Financial Condition of rhe U.S. EJectric Utility industry (Washington, ~: U.S. ~vernment PrhUing

Office, March 1986).

~Under may Staw ~@am~ ~atutes, a utility investment in a new plant must be prudent and @~d Wfui (put intO SCXViCe) ~fofe it cm b P1~~

in the rate base and costs recovered from ratepayers. Prudence reviews are regulatory examinations of the appropriateness of utility demand projections,

construction practices, and management dwisions and area precondition for adding a new facility to the ratebase. The reviews are typically conducted

after the plant is completed. Prudence reviews have lead regulators to disallow all or part of investments in large coal and nuclear plants because of

mismanagement and uncontrolled costs and, in some cases, because the complettxl plant proved to be excess capacity when projected demand growth

did not materialize. Some industry analysts contend that prudence reviews have shifted the risks from ratepayers to shareholders and utilities and made

it more difficult for utilities to commit capital for construction. Others contend that utilities and shareholders always bore these risks, but that they had

historically been minimal until the highly inflationary and turbulent 1970s,

8Forexmple, ~: J. Steven He~ ad Jeff~y f$k~r, “A ~k at Nation~ ~d Region~ EIw~c supply Nds,” p- presented at the 12th Energy

Technology Conference and Exposition, March 1985; U.S. Department of Energy, Ikputy Assistant Sezretary for Energy Emergencies, Staff Report,

*’Eleetric Power Supply and Demand for the Contiguous United States, 1997 -1996,” DOE/E-(Xlll (Springfield, VA: National lkchnical Information

Service, February 1988); Peter Navarro, The Dimming of America: The Real Costs of Electric Utility Regulatory Failure (Cambridge, MA: Ballinger

Publishing Co., 1985).
Chapter 3--Alternative Scenarios for Increasing Competition in the Electric Power Industry . 65

From the perspective of some utilities, PURPA

contributed to the further impairment of the traditional utility bargain because, while it left utilities

with the obligation to assure adequate, reliable

electricity service, it diminished their control over

the sources and costs of generation.

Time, lower fuel prices, and lower inflation rates

have abated many of the financial threats to the

electric utilities. 9 There remain, however, some

problems of uncertainty and delay attributed to both

the regulatory process and prudence reviews of

generating plant construction costs. There is some

agreement among regulators and utilities that targeted regulatory reforms would help avoid the

conflicts of recent years and restore a balance to the

regulatory bargain by assuring the industry of

recovery of future prudent investments in new

facilities, if needed, while offering similar assurances to consumers and regulators that new capacity

costs will be kept under control.

Implementation

The primary responsibility for implementing scenario 1 would rest with State governments. Few

changes to Federal law and regulation would be

necessary. The major Federal statutory and regulatory structure governing the electric power industry

today would remain essentially unaltered. In particular, PURPA, the Federal Power Act, and the Public

Utility Holding Company Act (PUHCA) would be

untouched and existing statutory standards would

not be loosened or expanded substantially by administrative or judicial interpretations. Scenario 1 would

not, however, preclude certain relatively selective,

but possibly significant, changes in existing administrative rules governing industry structure and

operations. For example, FERC might make minor

changes or clarifications in rules governing utility

avoided costs for purchases from qualifying facilities under PURPA. FERC might impose more

stringent technology or efficiency standards on QFs

to discourage the proliferation of “PURPA machines.” Similarly, FERC could continue its efforts

to encourage greater amounts of voluntary wheeling

by utilities and to provide additional incentives for

expanded intersystem bulk power transactions. Examples include the Western Systems Power Pool

Experiment and approvals of more flexible transmission pricing schemes in individual cases.

Transmission access and wheeling rates for wholesale and retail customers under this scenario would

depend on voluntary agreements negotiated with the

utilities controlling transmission facilities. FERC

would oversee wheeling rates.

Federal authority to issue wheeling orders under

the Federal Power Act and PURPA would remain

limited. The Nuclear Regulatory Commission could

order wheeling as part of licensing of new nuclear

plants, however, it is unlikely that any new orders

will be issued. FERC jurisdiction would largely be

limited to setting wheeling rates and approving

various proposals and experiments among utilities.

Some States would continue to assert authority to

require intrastate wheeling as a condition of State

initiatives.10 Antitrust considerations could provide

some source of mandatory wheeling as part of a

court order or settlement, but such wheeling orders

are expected to be rare.

The current statutory split between Federal and

State jurisdiction over regulation of electric utilities

would remain largely undisturbed. With the existing

trend toward greater use of bulk power sales,

however, it is conceivable that a greater share of

power costs might shift from State to Federal

regulatory jurisdiction, Modified State regulatory

procedures for review and approval of new plant

construction would offer stronger assurances to

utilities of recovery of investment than the current

system. These changes would likely require State

legislation and would probably include a more direct

and active role by utility commissions (and the

public) in the planning and oversight of new

9Mmy ~tjlltle~ have ~egalned ~elr he~~y fm~ci~ s~tus ~d we projected to have favorable CSSh f10w5 in tie l~e 19~@l~s. See ch. 2 of ~s

report.

1OThe sumess of ~e~ eff~s is open to doubt. ~x~ r~u]res Ull]i[les [0 Whee] QF power ~ other utilities, RXM may escape challenge Ixxause k

transmission grid is physically isolated from other interconnected systems and thus arguably cannot be said to affect interstate transmission flows, Other

States are potentially subject to FERC challenges to their authority. New York and Massachusetts require wheeling as a condition of participation in their

bidding programs. Florida’s attempts to require intrastate wheeling, including self-service wheeling, have repeatedly been challenged by FERC and by

several Florida utilities, arguing that Federal law preempts State control over rates, and the terms and conditions of wheeling transactions. Florida Power

& Light, Petition for Declaratory Orderfrom FERC, EL87-19-000, filed Mar. 11, 1987.
66 ● Electric Power Wheeling and Dealing: Technological Considerations for Increasing Competition

generation sources and transmission facilities.11 Some

observers believe, however, that many States would

not significantly alter their existing regulatory procedures because they have already adopted similar

reforms in response to the problems of slow growth

rates, inflation, cost-overruns, soaring fuel prices,

and excess capacity that stressed utilities during the

1970s and early 1980s.

Rolling Prudence Reviews. One regulatory reform that addresses the utilities capital attraction

problem is a proapproval process for construction of

new generating and transmission facilities coupled

with periodic prudence reviews.12 These determinations would be in addition to State least-cost

planning requirements. Regulators and utilities would

agree in advance as to the need, type, cost, and rate

implications of major new projects. These hearings

would allow participation by consumers. Following

initial approval, projects would be subject to regularly scheduled prudence reviews from inception to

completion. Utilities would be assured recovery of

all expenses incurred up to the most recent prudence

determination, except of course for losses due to

reckless, improper, or negligent actions of the utility.

This process has been characterized as a “rolling

prudence review” in contrast to the postconstruction prudence reviews now common under

many State regulatory programs.13 Proapproval is

not equivalent to adoption of a rate scheme that

allows recovery for Construction Work in Progress

(CWIP) in the rate base before the plant actually is

in use. Under the rolling prudence concept, a new

plant would become recoverable as part of the rate

base only after it began operating and was determined to be “used and useful. ”

If the circumstances underlying an initial approval of new capacity changed, periodic regulatory

reviews could allow projects to be canceled or

modified midcourse, but the utility would still be

entitled to recover in the rate base the value of its

prudent investment to date plus a reasonable return

over any recovery period.14 If the utility chose to

continue construction, it would receive no guarantees from that point on that the remaining costs

would be allowed into the rate base. When and if the

facility began operation, the public utility commission would decide whether the expenditures were

prudent. Some utility executives argue that such a

regulatory program would “fairly balance the risk to

consumers and investors alike and give assurance of

adequate and reliable supply of electric power in the

future. ” 15 In effect, the traditional regulatory bargain would be restored and strengthened, but it

would be more comparable to an explicit contract

between the utility and the regulatory commission

on behalf of the customers.

Institution of a rolling prudence review for new

construction projects would reduce the utility’s

management control over major investment decisions. In some States, however, there is already an

extensive degree of regulatory involvement in all

aspects of utility investment decisionmaking and, to

some degree, this scenario would simply constitute

a formal recognition of a regulatory system that

already exists, except perhaps for the guarantees

accorded to the utility.

A system of rolling prudence reviews is consistent

with other current trends in regulatory treatment of

utility resource expansion planning and construction. Other regulatory initiatives have been proposed

or adopted in recent years to restore the utility’s

expectation that it will recover its prudent investments or to enhance its cash flow to fund construction. Examples include automatic fuel adjustment

I lsta~ ~wlatq au~ofities in Massachwm have adopted a proapproval process for new capacity. Massachusetts Department of Public utilities,

“Pricing and Rate-making Treatment ‘lb Be Afforded New Electric Generating Facilities Which Are Not Qualifying Facilities,” D.P.U. 86-36-C, May

12, 1988.

IZSW 6*ReXn@on of Rich~d E. Disbrow at a Semin= for Virginia’s Legislative Leadership and Energy Committee Members, Aug. 10, 1987” for

a discussion of this approach. This strategy is also based in part on the remarks of Richard E. Disbrow at the OTA Workshop on Alternative Scenarios

for Increasing Competition in the Electric Power Industry, Sept. 28, 1987; and on NRRI, “Preapprovals,” supra note 4.

ls~ @me atrwtions of a rolllng p~mce scheme we that it Educes some of t~ risk in utility caplt~ investments, while the expanded role in

planning, approval, and scheduled project reviews offers equivalent protections and controls for regulators and consumers.

lqM~y Sute ~@~~ au~oritieshaveh ist~~]y ~lowed utilities to r~over~e fu]] cossof canceled p]m@ plUS a reasonable retUITIOn hVeSt2Tlent.

Some States may, however, be restricted by State authorizing legislation that limits recovery to capital plant expenditures that are both prudent and used

and usefut, therefore requiring a facility to actually be in operation before any recovery can be placed in the ratebase, &x NRIU, “Preapprovals,” supra

note 4.

lsDisbrow, supra note 12.
Chapter 3-Alternative Scenarios for Increasing Competition in the Electric Power Industry ● 67

clauses, incentive rates, performance bonuses and

penalties, advance caps on construction reimbursement, and inclusion of the value of CWIP in the

ratebase. l6

Regulatory reforms aimed at reducing or shifting

risk in constructing new large baseload plants may

not, however, actually result in the immediate

construction of any such plants. Other considerations such as the extent of existing reserve capacity,

increased uncertainty in future demand growth, and

greater volatility in fuel prices may lead utilities to

conclude it is more prudent and cost-effective to

build smaller increments of new generation and to

buy power from other sources for the foreseeable

future.

Under scenario 1 many ongoing State regulatory

initiatives could be expected to continue. State

commissions would likely continue their efforts to

encourage utilities to expand their bulk power

procurement practices to include consideration of

QFs, other utilities, and independent power suppliers.18 Under the more standard State PURPA programs, the commissions might review previously

established avoided cost rates. In some cases, lower

fuel costs and existing capacity surpluses could yield

lower avoided cost rates. These changes could lead

some higher-cost PURPA projects to drop out. In

other cases, reviews may lead to increases in existing

low avoided cost rates encouraging QF development. The basic PURPA incentive structure would

still remain. Utilities would still be obligated to

purchase power generated by QFs at avoided cost

rates. QFs would retain the protection of existing

long-term capacity contracts at avoided cost pricing

with host utilities,

States could continue to encourage greater coordination of utility planning and operations through

centralized dispatch, power pools, and brokerage

angements. The States would also continue their

efforts to promote workable regional power supply

planning arrangements and new means of developing needed interregional transmission capacity. Preapproval will eventually require most State regulatory agencies to increase their expertise in system

planning and load forecasting.

Industry Structure. Under scenario 1 the electric

power industry would consist of the current mix of

investor-owned utilities, public power agencies,

cooperatives, Federal power authorities, selfgenerators, small power producers, QFs, and IPPs.

As now, vertically integrated, investor-owned utilities will dominate the generation, transmission, and

retail distribution segments of the power industry.

Recent trends toward limited industry restructuring

through mergers, acquisitions, and internal reorganizations can be expected to continue within the

constraints imposed by existing law.

The trend toward greater bulk power competition

would continue as power suppliers, sellers, buyers,

and State regulatory commissions cope with pressures from prices and technology. In some States or

regions a de facto competitive market in bulk power

supplies will continue to evolve if FERC maintains

its “hands off’ approach to reviewing these interutility transfers. Utilities will continue to increase bulk

power transfers.

The role of IPPs, and especially utility-affiliated

IPPs, remains unsettled because, unlike QFs, they

would not be exempt from coverage by the Federal

Power Act or PUHCA. Without PURPA purchase

requirements, IPPs would have to compete on the

underlying economics of their projects. Non-QF

cogenerators and IPPs could continue to contract for

the sale and transmission of power to utilities and

other purchasers, however, provided suitable arrangements can be negotiated.

System Operations and Planning

Scenario 1 would have little or no impact on

system operations and closely resembles the status

quo. Table 3-2 summarizes the system operating

requirements under the scenarios. Responsibility for

16s= Jo=@ p, K~~, Hew be, ad H~~ B. ~n@ “Re-ES~bllShing tie Regulatory Bwgti k tk EIwtric Utility Industry,” Discussion Paper

Series (E-87-02), Energy and Environmentml Policy Center, John F. Kennedy School of Government, Harvard University, Cambridge, MA, March 1987;

bland L. Johnson, Incentives To improve Electric Utiliry Perjonrtance ” Opporrum”ties and Problems (Santa Monica, CA: Rand Corp., March 1985>;

and NRRI, “Preapprovals,” supra note 4.

17Th1s “Ulity ~ve~ent ~eferenW w= Pmviouly noted by OTA, U.S. Conwss, office of TixhnoIogy ~~ssment, New Elecrric power

Technologies: Probkms and Prospects for the 1990s, OTA-E-246 (Washington, DC: U.S. Government Printing Office, July 1985), ch. 3.

18Thi5 ~ppro~h is different from ~e~o 3 which would rquire (he w of comp[itive pr~~crnent procedures for dl new bulk POwer Stlp@.
Table 3-2-Alternative Scenarios: Summary of System Operations, Planning, and Developrnent

System operation

Reliability, dispatch System planning and development

scenario and coordination Generation Transmission Distribution

1. Strengthening the

regulatory bargain.

2. Expanding transmission access

and competition in the existing

regulated industry structure.

3. Competition for new bulk

power supplies.

4. Competition for all bulk

power supplies.

5. Common carrier transmission

services in a disaggregate

industry structure.

Utility controloanter.

Control of nonutility generation

set by contract.

Similar to 1 with greater

reliance on contractual

provisions for nonutility

generation control and

wheeling.

same as 2.

Transmission utility assumes

bulk system control.

Operational responsibilities of

generators and distribution

utilities set by contracts with

customers and transmission

utilities.

same as 4.

Utility obligation to

plan, build, and purchase.

QFs market under PURPA.

IPPs negotiate contracts.

Similar to 1 with expanded

OF and IPP participation.

Utility obligation to plan

and secure adequate new

supplies through competitive

means.

Generators, QFs ,

IPPs, and host utility affiliates.

Generators pfan and build

in response to perceived

market needs and solicitations

by transmissiondistnbution

utilities.

Generators plan and build

in response to perceived

market needs and solicitations

by local distribution utilities

and transmission companies

as brokers.

Utility responsibility.

Same as 1, but States may

require utilities to plan and

build adequate transmission

capacity for regional needs

including retail wheeling.

Same as 2, but no retail

wheeling obligation.

Transmission utility obligation

to plan and build adequate

capacity for instate/regional

wholesale needs.

Transmission utility obligation

to plan and build adequate

capacity for foreseeable needs

as common carrier for regional

wholesale and retail customers.

local utility responsibility.

same as 1.

same as 1.

local retail utility

obligation to plan and contract

for adequate supplies.

Utility may participate in load

management and conservation.

Transmission utility may

provide brokering services.

Same as 4.

SOURCE: Offica of Techrto)qy Assassman~ _ from Powar Tachnologias, inc., Tbchmca‘ ISac@ouml& Cansidwations in Ropwadlncraassd Whaaling, Transrnissionkcass, and Nonutikfy Gsmtmtion, OTAcontractot

report, Mar. 30, 1988.

I
Chapter 3--Alternative Scenarios for Increasing Competition in the Electric Power Industry ● 69

maintaining day-to-day system reliability and coordination of generation and transmission resources

would rest with the local utility or centralized

control center (under a coordination or power pool

agreement). 19 InterUtility agreements and operating

practices, as well as NERC regional protocols,

would continue to govern cooperative activities

among utilities. Operational responsibilities and

technical standards for nonutility or third-party

power suppliers would be based on contract terms

with the local utility. As under existing law, State

regulators would have the authority to rule on the

reasonableness of utility technical specifications in

cases of disputes between utilities and third-party

generators .20

The local utility or regional control center would

determine the order of dispatch, maintenance scheduling, and unit loading of utility owned or leased

units. For QFs and IPP units, dispatch and scheduling would depend on contract terms with the local

utility. Dispatchable third-party generators would

likely be treated the same as utility sources if they

demonstrate adequate reliability and availability and

if unit dispatch is technically feasible. Nondispatchable third-party generators would not be subject to

utility control, except as needed to preserve the

stability and reliability of the system. Under this

scenario, it is likely that IPPs will be dispatchable

under contracts, because their options to sell power

to other customers is limited. Emergency curtailments of backup service for third-party generators

would be allocated according to State regulated

curtailment policies.

Under scenario 1 local utilities would have the

responsibility for planning and developing overall

generation, transmission, and distribution requirements for the system based on their projections of

future electricity supply and demand. These planning efforts most likely would be coordinated with

other regional utilities and overseen by State regulatory agencies as part of the proapproval process for

new plants. Regulated utilities would retain the

obligation to provide adequate and reliable service

for current and future needs under this and other

scenarios.

In preparing generating capacity expansion plans,

utilities will consider various options for securing

power supplies, including potential QF sources, and

bulk power purchases from other utilities and IPPs,

as well as conservation and load management

strategies. 21 State authorities would generally approve utilities’ generation expansion plans through

the certification and proapproval process. QFs, IPPs,

and self-generators would plan and build capacity

based on their own perceptions of need and profitability. As eligibility requirements are tightened and

avoided cost prices are lowered, sponsors might tend

to abandon some of the more expensive QF projects

currently planned. It is unlikely that any IPP project

would go forward without a firm contract with a

utility for its power output. Third-party power

producers will likely be more successful in areas

with low reserve generating capacity margins than in

those areas with substantial amounts of existing

utility generating reserves or low production costs.

Local and regional utilities would plan and

develop transmission system additions subject to

regulatory approval. The pressures for increased

access to transmission services to accommodate

bulk power sales can be expected to continue. State

and Federal initiatives toward more flexible transmission pricing may encourage some additional

upgrading and expansion of transmission systems.

The potential for delays and controversy attendant

witb proposals for the siting and construction of new

transmission lines can be expected to continue.

Planning and building distribution system additions

would remain the responsibility of the local utility

with regulatory approval.

I Where we abut 150 utility con~o] centers~ tie United States. Some centers oversee the operations of individual utilities, others govern the operations

of participating utilities over a region established through coorcilm~im iw=nents or power POOIS. see chs. d ands Of this report for more on control

area responsibilities.

2~nder puRpA, utlllties we ~wulr~ ~ ~~rcomwt wl~ Srndl power ~oducers ~d QFs, ~(j c~not impose unreasonable technical requirements

to discourage access.

210vcr h~f of ~ StakS el~er rqu~ ~illties t. engage in ]e~t-c~( pl~ing for futwe electricity ntxxk or are developing Such requirements, David

Berry, “bast-cos( Planning and Utility Regulation’’l%ldic Utilities Fortnight/y, Mar. 17, 1988, pp. 9-15.
7(I ● Electric Power Wheeling and Dealing: Technological Considerations for Increasing Competition

SCENARIO 2

Expanding Transmission Access and Competition

Within the Existing Institutional Structure

Scenario 2 would preserve most of the electric

power industry’s existing structure and regulatory

framework, but would expand competition in the

generation sector more than scenario 1 or the status

quo. Scenario 2 would increase the number of

potential bulk power sellers by modifying some of

the size, technology, fuel, and ownership limitations

for QFs under PURPA. This could largely be

accomplished by changes in regulations, but eliminating all restrictions on utility ownership would

likely require legislation.22 At the same time, the

ranks of prospective buyers would be enlarged by

amending the transmission access provisions of the

Federal Power Act to authorize FERC to issue

transmission access orders under a broad public

interest standard.23 These legislative changes would

increase opportunities for both wholesale and retail

wheeling. Utilities and large industrial retail customers could purchase electricity “off system” from

traditional and nontraditional power suppliers and

have it delivered to them over a more open

transmission system.

The principal mechanism for achieving increased

competition in scenario 2 is the provision for both

wholesale and retail

voluntary wheeling

wheeling. If efforts to negotiate

arrangements failed, any utility

(including QFs and IPPs) or a very large retail

customer would have legal standing to seek a

wheeling order from FERC. 24 There would be a

rebuttable assumption that the capacity to wheel

exists. The utility denying the wheeling services

would bear the burden of proving either a lack of

available capacity or that accommodating a proposed wheeling transaction would result in a degradation of service.25 The utility would be entitled to a

reasonable compensation for its transmission services.

In addition to new wheeling authority, Federal

and State administrative policies intended to encourage greater competition in bulk power sales within

the existing institutional structure and increased

access to transmission services would be continued

and expanded,

Background

Many industry analysts have argued that the

regulated electric power industry would be more

economically efficient if more competition were

22puRpA provides tit a q~ifying f~i]i~ must be “owned by a person not primarily engaged in the generation or saie of t?leCtrlC power (Other thtin

electric power solely from cogeneration and small power production facilities).” 16 U.S.C. 7%(17)(C) and (18)(B). FERC has solicited public comment

on several potential changes to its rules on utility equity ownership of QFs. U.S. Federal Energy Regulatory Commission, Notice of Proposed Rulemaking

on Regulations Governing the Public Utility Regulatory Policies Act of 1978, Docket No. RM88-17-(K)O, July 19, 1988, pp. 32-57.

zgFor exmples of his ~~h, see Electiici~’s Fu~re; A Special Report by the Electricity Consumers Resource Council, JUIY 1987. killSO, the

ProPos~ “El~rnC Utility Tr~~ission Reform Act of 1985” in~oduc~ by Rep. peter H. Kostmayer in the 99th Congrws, H.R. 2231. The bill would

have amended sees. 211 and 212 of the Federal Power Act to provide that FERC could issue an order requiring an electric utility to provide transmission

services for another electric utility whenever it was found necessary or appropriate in order to: 1 ) consetve energy, 2) promote the efficient use of facilities

and resources, 3) increase competition in the bulk power supply market, or 4) otherwise serve the public interest. The order could be granted on the

application of any State commission, or public utility, or by FERC acting on its own motion following notice to affected utilities and an opportunity for

a hearing. FERC could order a utility to expand transmission facilities to provide the needed transmission services, but the wheeling party would pay

the capital and operating costs involved. The bill used a broad definition of a public utility as “any person, State agency, or Federal agency that sells electric

energy” for its new wheeling authority, but otherwise would not expand FERC jurisdiction over these entities. H.R. 2231 expressly banned orders to

deliver power to “ultimate” or retail customers. OTA’S scenario 2 would extend eligibility for wheeling setvices to “qualified” power purchasers to allow

very large retail customers to obtain wheeling. FERC or the States would establish standards for determining which retail customers would qualify for

wheeling.

zd~e issue of what Constitute a ve~ IMge retail cu~omer would be left to the States. h is assumed that States would limit access to facilities tht

require 20 to 50 MW or more. For example, a pulp and paper mill might qualify at 20 MW in some States, but in others, facilities might require at least

200 MW (e.g., the power requirements of a large aluminum reduction plant),

2sIn d~iding whe~er to ~~t a ~uest~ wh~ling order, FERC could consider all relevant issues including the potential impacts On IJtl]itleS, CaptiVt!

customers, and system reliability. Thus, it is possible that, if granting a wheeling order to an industrial customer to purchase off system would impose

a substantial economic hardship on the utility’s remaining customers, FERC could deny the request for transmission access under its “public interest”

standard.
Chapter 3--Alternative Scenarios for Increasing Competition in the Electric Power Industry ● 71

allowed in certain segments of the industry.26 Among

the benefits of competition they cite are: better use

of generation and transmission resources, a more

flexible and secure power supply, increased efficiencies in utility operations, and lower prices to

consumers over the long-term. In addition, utility

ratepayers would have less exposure to the risks of

construction cost overruns and poor plant performance as these risks would be shifted more explicitly

to the shareholders of nonutility generators. A

further benefit of allowing limited competition and

more wheeling would be a growth in the information

and experience available to assist policy makers in

evaluating the technical and institutional feasibility

of proposals for broader competition and economic

deregulation of electric power.

Proponents note that changes in generation and

transmission technologies have diminished some of

the so-called natural monopoly characteristics of the

electric power industry allowing workable competition to exist as a supplement to regulation. Smaller

generating units are now in many cases costcompetitive with large baseload plants and have

shorter lead-times. Increased interconnections and

higher voltage transmission lines have made regional coordination of utility operations more feasible. With these developments, some analysts see the

subregional, insulated, vertically integrated utility as

fast becoming an outmoded and economically inefficient entity. In their view, an industry structure

dominated by such entities: inhibits cost-savings

that could be achieved with greater coordination and

bulk power trades between interconnected systems;

makes cooperative agreements and power pooling

arrangements difficult to establish; provides unequal

access to the benefits of coordination and power

pools among buyers and sellers; and allows the

owners of transmission lines to exercise monopoly

power over their sections of the interconnected

systems .27

The entrance of small power producers and

cogenerators into the generation market under the

aegis of PURPA has yielded some benefits, but it

also has imposed additional operating uncertainties

and costs on electric utilities.28 Expanding the

PURPA model is one mechanism for introducing

limited competition into the regulated generating

sector. A major advantage of this approach is that

“smaller increments of increased competition can

yield efficiency gains and resolve uncertainties

without radically altering present institutional arrangements and risking a costly mistake. ”29 At the

same time, changes in the criteria for QFs would

reduce what some view as inherent market distortions created by PURPA’s limitation to small power

producers and nonutility firms.

Federal authority to issue wheeling orders rests

primarily on three sources:

1.

2.

3.

antitrust law (as a remedy for anti-competitive

or monopolistic behavior),

the licensing power under the Atomic Energy

Act, and

sections 211 and 212 of the Federal Power Act,

as amended by PURPA.30

Wheeling orders under antitrust law are rare, and

even if a plaintiff is successful, it may take years to

work out acceptable arrangements. Wheeling conditions imposed on licensees of nuclear power plants

by the Nuclear Regulatory Commission (NRC) and

its predecessor, the Atomic Energy Commission

have been a major source for guaranteeing transmission access for requirements customers. With no

new nuclear power plants on order, additional NRC

wheeling orders as part of licensing conditions will

be rare. It is possible that NRC might modify some

MS= EL(X)N, Electricity’s Future, supra note 23; WiUiam A. BrownelL “Electric Utility Deregulation: Analyzing the Prospects for Competitive

Generation,” Annual Review of Energy f984, pp. 229-262; and F. Paul Bland, “Problems of Price and Transportation: TWO Proposals To Encourage

Competition From Alternative Energy Sources,” 10 Harvard Environmentuf Luw Review 345 (1986).

Z7Wi]11m A. B~~el], cc~a~c utili~ ~@~on: Analyzing the Prospects for Competitive Generation,” Annuul Review of Energy f 984, pp.

229-262.

zSId., pp. 254-255,

291d., p. 253.

SO16 u.S.C. g24j and 824k. See discussion in ch. 2 of thiS mw.
72 ● Electric Power Wheeling and Dealing: Technological Considerations for increasing Competition

existing licensing obligations, however.31 Section

211 wheeling orders have been effectively precluded

by the heavy burden of proof placed on applicants

and the restrictive findings that must be made before

an order can be issued. For example, among other

things, section 211 requires a finding that existing

competitive relationships, such as existing power

sales arrangements, not be disturbed.32 Other difficulties with existing FERC wheeling authority

include: the fact that each wheeling application is

considered separately; uncertainty over whether QFs

and IPPs are included under the broad definition of

a utility as any entity that generates power for sale;

prohibition on retail wheeling; and Federal court

decisions and FERC informal opinions that the 1978

ml rD ~A ... L--1:- - ---..:.: --- - -—-.. .-2 . . .L ------- r unrm wucxung p uvnlum marruwtxl wmiusvcr

inherent authority may have existed under the

Federal Power Act to order wheeling to promote

competition. 33

A fourth possible source of wheeling authority is

FERC’s ability to “condition” its approval of some

desired action on the petitioner’s acceptance of

certain specified requirements. This conditional

authority is inherent in FERC’s regulatory and

policy responsibilities under the Federal Power Act

and other laws.34

Implementation

Scenario 2 would be implemented through combined Federal and State efforts. Federal legislation

would be required to amend PURPA, the Federal

Power Act, and PUHCA. State legislation or regulatory action would be needed to implement the

changes in Federal PURPA rules.

Changes in PURPA Requirements. Selected

changes in the PURPA eligibility standards for

qualifying cogenerators and small power producers

would increase the ranks of potential competitors in

bulk power markets.35 PURPA vests with FERC the

responsibility for establishing technical requirements for qualifying facility status, and most of these

initiatives could be accomplished through changes

in FERC regulations. Modifications have been

suggested to the standards on the unit size, technologies, fuel types, and utility equity participation.

Size: FERC rules limit small power producers to

no more than 80MW for PURPA eligibility. There is

a statutory limit of 30MW for exemption from State

and Federal utility regulation (including regulation

under PUHCA). Under scenario 2, the size cap for

small power producers would be raised, for example,

to 165 MW as proposed by a former FERC

chairman. 36 There are no size or fuel limits on

31C)M0 ~i~ IMS ask~ NRc @ mvi~ the whcxling obligations included in the license for its Perry Nuclear plant. The license requires ~io Edison

to wheel cheaper coal-fired power from southern Ohio to 21 municipal distributors in northeast Ohio. Ohio Edison has argued that the whcAng

requirements should be dropped because themunicipalsno longer want to purchase the more expensive Perry nuclear power. ‘ ‘Metzenbaum, public Power

Fight Ohio Edison wheeling Request to NRC,” Energy Dai”ty, Apr. 4, 1988, pp. 1-2. Wheeling issues could also be raised before NRC in reviews of

license assignments in mergers and acquisitions,

3216 U.S.C. g~j(c)(i). SeC andysis of Federal wheeling authority in Alvin Kaufman, Carl Behrens, Donald Dulchinos, LarIY B. Parker, idR*

D, Poling, Wheeling in the E/ectric Utifitylndustry, Repcxt No. 87-289 ENR (Washington, DC: Congressional Research Service, Feb. 12, 1987).

33s= Kaufm~ et A, id. !jimil~ conchaims were reached in Harvey L. Reiter, “Competition and Access to the Bottleneck: The SCOPC of contract

Camier Regulation Under the Federal Power and Natural Gas Acts,” 18 Land and Waferfuw Review 1-80, 1983; National Regulatory Research Institute,

Non-Technical l~ediments to Power Tramrfers (Columbus, OH: National Regulatory Research Institute, September 1987); and Bland, supra note 26.

qq~ *ow~l~g in” ~“wh~l~g at” p-sin the notices of proposed ndemaking would be based on FERC’S conditional authority. S= note

57 infra. See also the discussion of FERC’S authority in ch. 2.

35WRC ~wlatims~fima SrIMU Pmverprod=m a facility that produces less than 80 MW ofelectnc power at the same site through usc of biomass;

waste materials; geothermal energy; or renewable resources such as wind, solar and hydroelectric resources (up to 25 percent of total energy input to QF

may be oil, natural gas, or coal). 18 CFR 292.204(1988). FERC defines a cogeneration facility as “equipment used to produce ekxtric energy and forms

of usefitl thetmal energy (such as heat or steam) used for industrial, commercial, heating, or cooling purposes, through the sequential use of energy.” 18

CFR 292.202(c) (1988). Tb be a qualified fdlity, the small power production facility or cogeneration facility cannot be owned by a person or entity

“primarily engaged in the generation or sale of electric power” (other than the power produced from the qualifying facility). 18 CFR 292.206 (1988).

36sW HefingsBefo~ tie Hou~ Suxitti~ ~r~ ConXmation & power. on H.R. 2992 ~d H.R. 2876 ( 1981). H.R. 2876 wotdd have

increased QF size cap htn 80 to 165 MW and eliminated 30MW limit exemptions from Federal and State utility regulation. Legislation in the Semte

was introduced in 1982 (S, 1885) and hearings were held. Hearings on S. 1885 before the Senate Committee on Energy and Natural Resources, Apr. 19,

1982. The rationale for this size limit is that it would allow larger QF plants but would be less than some larger utility or IPP planned modular power

plants. Legislation in 1981 would have lifted overall size limits to 165 MW.
Chapter 3-Alternative Scenarios for Increasing Competition in the Electric Power Industry ● 73

cogenerators, because they are not primarily in the

business of generating and selling electricity.

Utility Equity Participation: Legislation would

probably be required to allow fill equity participation in QFs by utilities and would be controversial.37

FERC rules interpreting PURPA have allowed

utility equity participation of less than 50 percent.38

Many utility subsidiaries are active in building QF

plants, but they must do so as part of a joint venture

with another nonutility firm. Under this scenario,

unregulated utility subsidiaries would be able to

build and own generating units outside their own

service territories and sell power at PURPA avoided

cost rates. FERC has solicited comments on how

they might amend the existing equity ownership

rules to expand utility participation in QFs.39

Fuel: Qualifying small power producers are

limited to those that produce electricity through use

of biomass, waste materials, geothermal energy, or

renewable resources such as wind, solar, and hydroelectric resources. They may use oil, natural gas, or

coal for up to 25 percent of their total energy input.

Technology: FERC rules require that to qualify,

energy use by a cogenerator must be sequential and

must meet minimum efficiency standards in thermal

output. Sequential use means that the rejected heat

from a power production or heating process is used

in another power production or heating process. This

cascading use of energy in sequential processes

gives rise to the energy conserving characteristics of

cogeneration. 40 Some new technologies, such as

extraction turbines, do not use sequential steam to

generate large amounts of power. Modifications to

the technology requirements might allow additional

facilities to qualify.

Operating and Eficiency Standards: FERC regulations impose different efficiency and operating

standards on QF units depending on the type of fuel

used. New cogeneration facilities using natural gas

or oil must satisfy minimum efficiency levels

intended to ensure efficiency superior to conventional utility facilities.41 No such restrictions ar e

imposed on waste plants or coal plants.

Easing of the above PURPA standards for QF

eligibility would increase both the number and

diversity of participants in bulk power markets and,

combined with increased access to transmission

service, would broaden the range of purchase

options available to utilities and large retail customers. For those customers either unable or unwilling

to assume the risks of purchasing power off system,

the local utility would maintain a service obligation

to either construct or acquire needed capacity to

serve their power supply needs.

Revised PURPA eligibility standards could bring

some IPP projects under the QF purchase obligations of utilities. At the same time, with greater

variety and more competition among alternative

sources, the purchasing utility’s avoided costs might

be driven down, thus lowering required QF payments. IPP and QF projects could use their access to

the transmission system to contract with more

distant utilities offering more attractive avoided cost

payments. IPPs not meeting QF status requirements

would still be able to seek mandatory transmission

access to move their power.

Transmission Access and Wheeling—Scenario 2

involves two distinct kinds of wheeling to promote

greater competition:

37H,R. 2g7G ~ou]d ~W have e]im~at~ tie utili~ owne~ip ~s~c[ion from tie &fini[ion of qu~ifying Cogenerators ~d Sma]l power producem.

Lifting the utility ownership cap was strongly opposd by State regulators and QF developers. See Hearings on H.R. 2992 and H.R. 2876, supra note

36.

38]8~z97.zfj(j (1988)0

39s=Notice of~-Rulem&~g~Regu]atio~ ~vefing he ~b]ic utility Regultiory Policies ACI of 1978, Docket No. RM88- 17-, July

29, 1988.

~he requirementofsequential use of energy was added by FERC in its twhnicaldefinitionof cogeneration and is not found in PURPA. The sequential

use requirement was viewed as critical even though not statutory. See discussion in Pfeffer, Lindsay & Associates, Inc., Emerging Policy issues in PURPA

Implementation: An Exuninatwn of Policy Issues Related to Federal and State Efforts to Encourage Development of Cogeneration and Sma[l Power

Productwn Under Title II of PURPA, March 1986, pre~ for the U.S. Department of Energy, Office of Coal & Electricity Policy, ch. 11.

41 Under [~po~er p]~t ~Indu~alF~l u= &t of 1978, u[ilities were l~ge]y pr~luded from building new p]mts burning oil Or IX3tlld @S WkhOUt

a special exemption, because these were believd at the time to be scarce fuels. In 1987 Congress repealed the act fuel restrictions for new utility baseload

pkmL\.
74 ● Electric Power Wheeling and Dealing: Technological Considerations for Increasing Competition

1.

2.

wholesale wheeling—providing transmission

services to utilities and nonutility generators

for the sale of power for resale (mostly

involving sales to utilities); and

retail wheeling-transmitting power from other

generators (utilities, QFs, IPPs) to ultimate

consumers, which would also allow “selfservice” wheeling among facilities owned by

a QF or a self-generator.

Expanded transmission access under scenario 2

would increase the market access of both potential

buyers and sellers of electric power and lessen the

dominance of the utilities controlling the transmission grids.

Scenario 2 would amend the Federal Power Act to

change the definition of those eligible to seek

wheeling orders and modify the process through

which FERC can order wheeling.42 The restrictive

findings required by existing law, which effectively

preclude issuance of wheeling orders in most cases,

would be replaced by a more flexible “public interest

standard. ” If efforts to negotiate voluntary wheeling

arrangements failed, any utility (including QFs and

IPPs) or large retail customer would have legal

standing to seek a wheeling order from FERC. There

would be a rebuttable assumption that the capacity

to wheel exists and any utility denying wheeling

services would bear the burden of proof of showing

that there is either a lack of capacity or a degradation

of service that would result from the proposed

wheeling transaction. The wheeling utility would be

entitled to a reasonable compensation for its transmission services.

In deciding whether to grant a requested wheeling

order, FERC could consider all relevant issues

including potential impacts on utilities, captive

customers, and system reliability. Thus, it is possible

that, if a wheeling order allowing an industrial

customer to purchase off-system43 would impose a

substantial economic hardship on the utility’s remaining customers, FERC could deny the request

for transmission access under a public interest

standard. (The customer, of course, would always

retain the option of self-generation, which would

still leave the utility with the same problem of

recovering its investment from a smaller pool of

ratepayers.) Providing retail customers with access

to transmission would provide them with a bargaining tool in seeking to negotiate rate concessions

from their retail supplier.

The principal constraints on a customer purchasing off-system under scenario 2 would be the

availability of transmission capacity, and any specific contractual provisions with the existing utility

supplier on minimum take and termination notice

conditions. Arrangements for backup or standby

power supplies would have to be negotiated with the

host utility, perhaps with review by appropriate

regulatory authorities.44 In some cases the customer

would have to negotiate contracts for provision of

unbundled control area services provided by the

local utility.

Industrial customers going off-system for their

power needs would have to negotiate some stand-by

or maintenance service arrangement with their

native utilities if they were to expect any sort of

service obligation. They may also have to negotiate

some provisions for later reconnection to local

utility service if State regulations do not already

provide for this. The contracts between large retail

customers and alternative suppliers would likely be

more detailed and complex than their previous

agreements with a host utility. Many of the services

that had been supplied as part of traditional electric

power service would now have to be contracted for

specifically. Contracts that involve wheeling agreements with third parties will also require more

stringent delineations of technical and operating

specifications and responsibilities.

Scenario 2 also would encourage the development

of new initiatives to provide greater economic

incentives to utilities to wheel voluntarily. FERC

could, for example, establish affirmative guidelines

for the approval of transmission agreements that

4ZS= ~e ELCON p-~and K~ayer bill, supra note 23. The Federal Power Act defines an electric utility as any entity that generates electric

power for resale-some have questioned whether that ckfinition brings QFs and IPPs within the class of parties with standing to seek mandatory

transmission orders under existing law. The proposals would also extend standing to FERC, State agencies, Federat power agencies, and large power

consumers/purchasers.

@Off sys~$$ ~fa t. p~h~ b a pOWW supplier other than the native or host utility cumently serving the industrial customer.

dqsome sta~s ~dy require utilities to provide backup services at nondiscriminatory rates.
Chapter 3-Alternative Scenarios for Increasing Competition in the Electric Power Industry ● 75

might encourage wheeling, such as allowing more

flexible pricing of transmission services, requiring

compensation of other affected parties (such as other

utilities experiencing unintended flows or parallel

path problems), permitting auctioning of transmission services, establishing strict timetables for

negotiating transmission agreements, and expediting their own review of transmission rates and

agreements. 45 FERC might also cooperate in providing guidance and technical assistance to State

regulators in pricing and contracting procedures for

unbundled transmission and control services.

State Initiatives. Because States have the primary responsibility for implementing PURPA under

guidelines established by FERC, the States would

have to revise their rules and procedures to accommodate the expanded eligibility for QF status. States

would have the lead role in implementing changes

that permit large retail customers to purchase off

system in intrastate transactions. Federal law would

not preempt any State laws that characterize an IPP,

self-generator, or QF engaged in retail sales as a

public utility subject to regulation. States might

require instate utilities to wheel power from other

instate utilities and nonutility generators to large

retail customers.

It is possible that the existing balance between

State and Federal regulation could be maintained

somewhat if Federal legislation expressly allowed

delegation to the States of the authority to implement

intrastate retail wheeling under FERC guidelines.

State involvement might also be the most politically

effective means of implementing retail wheeling

because of the substantial equity and fairness

considerations involved in weighing the interests of

large customers in wheeling power against both the

economic impacts on the local utility and the

interests of other customers. Placing the decisionmaking responsibility in State hands would move

the process closer to the parties that potentially

would be most affected by the order.

System Operations and Planning

System reliability and coordination remains the

responsibility of the local control center as in

scenario 1. Operating requirements for QFs and IPPs

would be specified in contracts. System operations

would likely be affected more than in scenario 1 as

there would be a need to accommodate a greater

diversity of generating sources and delivery points.

Dispatch, maintenance, and unit loading operations and procedures would be similar to scenario 1,

except that loading and dispatch of transmission

accessors not subject to direct utility control would

be determined by contracts among the generator, its

customers, and the wheeling utility. The wheeling

utility would have to adjust its operations to counter

any increased uncertainty created by having nondispatchable generators on the system. (Of course, the

wheeling utility could impose reasonable technical

conditions and charges on the nondispatchable

generators and their customers to provide this

service.)

Emergency curtailments of service would be

allocated according to State-regulated curtailment

policies and contracts (same as in scenario 1). For

outages of nonutility wheeled power, curtailment

and backup power would be based on standby

service contracts with the local utility.

Planning and developing generating capacity

would be very similar to scenario 1. Under revised

PURPA standards, a broader range of facilities

would be eligible for QF status, and State law might

require utilities to consider QFs as potential components of their capacity expansion plans. It is likely

that much more QF and IPP capacity would be built

under scenario 2 than under scenario 1. As the

amount of nonutility generation grows, States or

regional utility groups may wish to provide for direct

participation by nonutility generators in the planning

process.

Planning for transmission additions would be

similar to scenario 1 except that State regulators may

require utilities to include provisions for adequate

transmission capacity for wheeling services in

45 RWen( ~xmp]es ~ft~W j~tla(jve~ jwlu~ tie wes~m State5 power pool ex~rjment, ~RC au~orjzation for Baltimore (3M & Ekttk to auction

off its unneded capacity on the PJM power pool, and approval of a flexible transmission pricing arrangement between Pacific Gas & Electric and the

‘Ibloek Irrigation District, see “PG&E Offers ‘New Approach’ To Pricing Transmission Services.” The Energy Daiiy. Apr. 5, 1988, p. 1.
76 ● Electric Power Wheeling and Dealing: Technological Considerations for Increasing Competition

Photo credit: Dominion Resources, Inc.

Operator at the controls of a power plant

system planning. There is a possibility that some

nonutility entities might build private transmission

lines, but they would have no eminent domain

authority and an uncertain regulatory status. FERC

might order a utility to upgrade or expand its

transmission facilities to implement a public interest

wheeling order. States might also require utilities to

expand transmission capacity to accommodate competitive sources.

Distribution additions would be the responsibility of the local utility (same as in scenario 1).

Conservation and load management plans would

be developed by the local utility with oversight by

State authorities. State regulators may require utilities to include consideration of savings from conservation and load management strategies as part of

their least-cost planning efforts as in scenario 1.

SCENARIO 3

Competition for New Bulk Power Supplies

Scenario 3 would create an institutional and

regulatory structure to support all source competition for new electricity supplies. Bulk power prices

would be established through reliance on competitive market forces rather than cost-based regulation.

The overall structure of regulated utilities would be

maintained, but limited competition for new capacity needs would be introduced in the generation

sector. The present electric power industry structure

would be expanded by the entry of IPPs and
Chapter .3-Alternative Scenarios for Increasing Competition in the Electric Power Industry ● 77

unregulated utility subsidiaries, divisions, and/or

spinoffs created to build and operate new generating

facilities and to sell power in competitive markets.

The numbers of competing buyers and sellers of

electricity would greatly increase, as would the

number of entities seeking access to the transmission

grid.46

Under scenario 3, once a need for new power

supplies has been certified by the appropriate

regulatory authorities, an electric utility would

solicit offers for new power supplies from other

utilities, nonutility generators, QFs, and its own

unregulated generating subsidiaries.47 Conservation

and load management strategies might also be

included as competitive options in some State

programs.

48 With appropriate safeguards to limit

problems of self-dealing and conflict of interest, the

unregulated utility subsidiaries could bid for new

capacity within their own service territories.49 Contracts for new electricity supplies would be awarded

based on consideration of both price and nonprice

factors (e.g., dispatchability, fuel and technology

preferences, location, and relative environmental

impacts).

Three mechanisms would exist for securing transmission services: 1) voluntary transmission arrangements with wheeling utilities for utilities and

retail customers; 2) transmission access preconditions imposed on utility participants in bidding for

competitively awarded bulk power contracts; and 3)

public interest transmission orders issued by FERC

which would be available only to utilities and

wholesale power suppliers.

Scenario 3 would effectively create a two-tiered

bulk power supply system: new power supplies

under a minimally regulated, “workably competitive” market;50 and existing generation under the

current State-Federal scheme of regulated entry and

pricing. Existing generating facilities, and transmission and distribution systems would remain regulated. Gradually, however, as old generation plants

are replaced, the system would move toward an

unregulated market in electric power generation and

supply.

Background

Scenario 3 is loosely based on recent suggestions

for allowing competition for new electricity sources.

These proposals include those of FERC Chairman

Martha Hesse5l the Keystone Electricity Working

Group,52 and three notices of proposed rulemaking

*Although t~c n~~ of Cmpetirtg supp]jc~ ancl potential customers are likely to increase as a resuh of changes ifl thlS SCeIISJiO, it is not at all clear

whether the number of generators that win competitive supply contracts will increase significantly. It is conceivable that traditional utilities and large

independent power producers would win many of the solicitations and that the need to integrate many new entrants into the bulk power network would

be much less than if a large number of small entities won contracts to supply an quivalent quantity of bulk power. We have assumed for purposes of

this analysis that competitive solicitations will yield a larger and more diverse mix of generation than under traditional regulation because that result would

pose the greatest challenges for bulk power system operation and control.

qTAs u~ ~m, Cmwtitlve “bidding” i~l~es not o~y a s~ctured auction wi~ SCdd or firm bids, but dso less structural competitive negotiations

where participating vendors might be selected basal on an initial solicitation of proposats, such as, for example, the process used by Virginia Power Co.

in seeking alternative power supplies described in ch. 5.

48 AmOng the mwh~ms for ~ciuding~~ dem~d sik ~tematives ~e: 1) to quirc utilities to consider demand side options ~ pm of a least-cost

planning before reaching a determinationof new supply needs, 2) to allow demand side options to compete directly with supply options in the competitive

solicitation, and 3) to hold a separate solicitation for a desired increment of demand side options.

491f a utility c~=not t.p~iciped~~y in the bidd~g, it might c~~&indirec~y by setting a benchmark b- on its own estimate Of the COStS

of building the plant itself and recovering the costs under the base as the supplier of last resort.

30As yet,-c~not offe~ a c]- ~d obj~tive ~finition of what would constitute a “workably competitive market” under the Federal power

Act. Development of appropriate findings or guidelines for determining whether a workably competitive market existed would be left to FERC under

scenario 3 and would be a prerequisite for implementation. A more detailed definition of the term is not needed for purposes of OTA’S technical analysis,

however.

Sls=, forex~ple, *’Talk~gpoints fmthe ch~~,’’~e~i~Electic Institute, Cincinnati, OH, June 10, 1987; ad “Remarks by FERC Chtirm~

Martha O. Hesse,” Energy Daily’s Annual Utility conference, Washington, DC, Nov. 6, 1987.

52The Keystorte Ener~ Fo_ is ~ ~fom~ discussion ~oup with mcm~rs from ~dustry, government, acdemia, trade associations, ~d public

interest groups. The working group meets periodically on subjects of current interest. The draft proposal (“Keystone Electricity Draft,” 1/27/88) was

prepared to merge concepts brought out in diacusahm of the electricity working group of the Keystone Energy Futures Project. Although the group

discussions are largely off the record, reports about the draft appeared in the trade press. The electricity working group never reached a conwws on final

conclusions or recommendations on transmission access issues. They are currently considering issues related to transmission pricing.
78 ● Electric Power Wheeling and Dealing: Technological Considerations for Increasing Competition

(NOPRs) issued by FERC in March 1988.53 Scenario

3 is not identical with any of the proposals, however.

Chairman Hesse initially proposed the use of

competitive bidding as an alternative to administrative determinations to set QF avoided cost capacity

payments under PURPA. According to Chairman

Hesse, modifications of existing PURPA rules to

allow States to implement all-source competitive

bidding on an optional basis and to use these results

to establish avoided cost rates would also “fit

PURPA into an overall electric strategy which will

move us toward a more economically efficient

industry.” 54

As a further initiative to expand competition, she

suggested, some of the regulatory requirements on

IPPs could be reduced for any IPP that is not a QF

and that sells electric power in areas where it has no

service franchises and otherwise lacks significant

market power.55 Eligible IPPs would receive the

maximum pricing flexibility under the Federal

Power Act’s “just and reasonable” standard and

would be relieved of certain reporting and accounting obligations because of their lack of market

power. Chairman Hesse deferred discussion of

transmission access and pricing issues for future

FERC action.

The Keystone Group considered, but did not

adopt, a draft proposal opening a utility’s future bulk

power needs to competition among all potential

suppliers with the economic and technical capability

to develop needed generating capacity. The proposal

suggested that existing regulatory and statutory

constraints in PURPA and PUHCA on utility

ownership of new power supply projects eligible to

participate in this new competitive market would be

relaxed or eliminated. The existing PURPA administratively determined avoided cost pricing scheme

would be replaced; competitive bidding would allow

the prices to be paid by distribution utilities for new

generation to be set in the marketplace. If independent generators were unable to meet a utility’s need

for new generating capacity, the utility would

function as a “backstop” or a supplier of last resort

for whatever remaining need there was for new

power supplies. The utility’s cost of providing such

last-resort capacity would also set an upper limit on

what might be paid to independent power suppliers.

Under the Keystone approach, all independent

third-party suppliers would have guaranteed access

to transmission service on reasonable terms (subject

to availability). The draft did not provide much

detail on how the access guarantees would work.

Transmission access would not be available for

retail customers.

In March 1988 FERC formally advanced Chairman Hesse’s suggestions for greater reliance on

“workably competitive markets” by issuing NOPRs

that would:

1.

2.

3.

impose additional procedural requirements for

determination of avoided costs by State regulators and unregulated utilities,

specify acceptable forms of competitive bidding for new power supplies that could be used

by States or unregulated utilities in setting

avoided costs under PURPA, and

establish IPPs as a new category of power

suppliers without market power that would be

exempted from many of FERC’s reporting and

regulatory requirements otherwise imposed on

electric utilities.

The NOPRs invited comment on two changes

involving transmission. The avoided cost NOPR

asked whether QFs should be allowed to construct

and own transmission lines and interconnection

facilities to transport their own power to purchasing

53u,jI.~pmatof~ro,F~a~ ~raRegulatory Commission, Notice of Proposed Rulemaking on Re@tiionsGoveming Bidding fiogr~s

(18 CFR Parts 35 and 293), Docket No, RM88-54XX), Mar. 16, 1988, very brief summary published at 53 Fed. Reg. 9324, Mar. 22, 1988; Notice of

Reposed Rulemaking on Regulations Governing Independent Power Producers (18 CFR Parts 38 and 382), Docket No. RM884000, Mar. 16, 1988,

ve~ brief summary published at 53 Fed. Reg. 9327, Mar. 22, 1988; and Notice of Proposed Rulemakingon Administrative Determination of Full Avoided

Costs, Sales of Power to Qualifying Facilities, and Interconnection Facilities (18 CFR Part 292), Docket No. RM88-6-O(M, Mar. 16, 1988, very brief

summary published at 53 Fed. Reg. 9331, Mar, 22, 1988.

sqHe~, .sUva ~otc 51, p. 3, @e of ~~ic ov~~l principles cit~ in supw of her propos~ ww ‘m degree of reguiationshould mflwt the (kof market power. Workably competitive markets should be allowed to operate with as little regulatory interference as possible.” Id., at p. 4,

SS~e ration~e for swl~ trea~ent f~ ~is c]~s of ~ps is p~~nt~ in a FERC d~ument, “Summary of Current Stif Propod Ofl PURPA-Related

Issues,” Sept. 11, 1987, pp. 16-19,
Chapter .3--Alternative Scenarios for Increasing Competition in the Electric Power Industry ● 79

utilities without losing their QF exemption from

Federal and State regulation as a public utility.

FERC also requested comments on how to deal with

situations where a QF wishes to provide wheeling

services for others over its transmission lines.56 The

competitive bidding NOPR asked for comments on

imposing “wheeling in” and “wheeling out” conditions on utilities participating in bidding programs.57

OTA’s scenario 3, like the previous proposals,

would open up competition for new bulk power

supplies. Unlike the Hesse proposals and the FERC

NOPRs, the use of competitive procurement methods would not be optional. Scenario 3 also does not

require creation of special regulatory exemptions for

IPPs. Scenario 3 would condition participation in

competitive bidding on agreements to provide transmission access to other bidders—somewhat similar

to the wheeling mechanisms described by FERC.

Unlike the other proposals however, Scenario 3

would include mandatory transmission access for

wholesale bulk power sales under a public interest

standard similar to that in Scenario 2 and would

clearly require congressional action.58

Implementation

Conceivably, scenario 3 could be partially accomplished through administrative actions by FERC.

New rules could require States and utilities to use

competitive procedures for establishing avoided

cost prices for qualifying facilities under PURPA,

although this may require a strained interpretation of

PURPA and the Federal Power Act. (FERC proposed making competitive bidding optional for State

PURPA implementation.) FERC might also formally accept market-based pricing for bulk power

sales under its jurisdiction in regions where it found

at least a presumption of a workably competitive

market. Some observers have concluded that FERC

has effectively deregulated many bulk power wales

by accepting negotiated arrangements without much

inquiry.

Under scenario 3, legislation would be required to

expand FERC authority to order wheeling for

wholesale transactions among utilities and to assure

transmission access for new bulk power contracts.

Changes would probably be needed in PUHCA to

allow utility subsidiaries and other companies to

compete as unregulated entities without coming

under the more restrictive provisions of that act.

Many States would require legislation to authorize reliance on market-based mechanisms to set

prices for new power sources. Legislation may be

needed to vest adequate authority in public utility

commissions to oversee and enforce competitive

solicitations for new power supplies. A number of

States including Connecticut, Massachusetts, Maine,

New York, and Virginia, have already sanctioned

competitive solicitations as a means of obtaining

alternative electricity supplies at the lowest competitive costs. These competitive bidding processes do

not, however, necessarily reflect an explicit State

policy shift in favor of creating a fully competitive

generating sector to replace traditional utility price

regulation. Utilities can still build and receive cost

of service treatment for new capacity in these States.

Regulators would become more extensively involved in approving determinations of need and in

resolving disputes over contract awards under this

scenario. The analytical capabilities of State commissions may need to be enhanced and expanded

with additional funding and staff. It is presumed that

under State competitive bidding programs, considerations of competitiveness and prudence would be

addressed before the contracts were approved. Competitively established wholesale power prices would

then be passed through to retail customers of the

distribution utilities with only limited opportunity

sb~ket No. RM88-6-(KKI, supra note 53, pp. 85-95.

sTDocket No, RM88-5~, su~a now 53, pp. 87-9], “w~ling in” would require a utility wishing to bid on the capacity needs of another Uti]lty to

agree to provide fm transmission services to the purchasing utility for successful bidders thai are kcatd within the bidding utilities service territory

or that can reach one of its interconnection points. ‘Wheeling out” would require a utility wishing to bid to supply its own capacity needs to provide firm

transmission services to the border of its -ice area to unsuccessful bidders that wished to sell to another wholesale purchaser. Both forms of wheehrtg

would be subject to “reliability and economic dispatch considerations”.

513Some Cntlcs of tie ~RC Cmwtitive bidding ~~p NOpRs ~ve ~g~hat ~ese ~tions ~SO should be @Iced before (bIgress either kFERC lacks the explicit authority to ru@re them and/or bezause they raise such significant national policy issues that they are more appropriate for

legislative action. FERC Commissioner Charles A. Trabandt is one of the most vocal proponents of the latter view.
80 ● Electric Power Wheeling and Dealing: Technological Considerations for Increasing Competition

for change by State regulators.59 In some instances

regulators may reassert some control over bulk

power costs by reexamining the prudence of contract

rates and conditions in the context of retail ratesetting and other proceedings. State regulators might

disallow full recovery of the purchased power costs

if the utility’s actions in selecting or negotiating the

contract were found to be imprudent (e.g., if cheaper

power were available elsewhere). The extent of State

agency jurisdiction to review the retail impacts of

wholesale contracts has been cast into doubt by a

recent U.S. Supreme Court decision.

The ability of State regulators to examine the

prudence of wholesale supply contracts in setting

retail rates and approving supply plans was assumed

in the development of this scenario. This assumption

of effective State review of competitive contracts

has been undercut by the U.S. Supreme Court’s

decision in Mississippi Power & Light Co. v.

Mississippi ex. rel. Moore, Attorney General of

Mississippi involving the dispute over the Grand

Gulf nuclear plant.60 The Court held that FERC

authority over wholesale sales preempted any State

commission inquiry into the prudence of the management decisions concerning the underlying power

supply contract between Mississippi Power & Light,

a subsidiary of Middle South Utilities, a public

utility holding company, and another of the holding

company’s subsidiaries. Because of this preemption,

the States were required to pass through the wholesale rates to their customers; all prudence issues

would have to be raised by States and consumers in

hearings before FERC. If extended beyond the facts

of the Grand Gulf case, the Court’s decision could

require Federal legislation to implement scenario 3

in a form that assured effective State oversight of a

utility’s competitive supply arrangements.6l Alternatively, new procedures and authority and expanded resources would be needed at FERC to

provide an equivalent Federal role.

In scenario 3, State and Federal authorities would

no longer directly control entrance into the generation sector (through certification of capacity need),

nor would they set wholesale prices for power from

new generating facilities. Instead, a system of

competitive-bidding or negotiated contracts would

establish competitive market-based rates. These

competitively established bulk power prices would

then be passed through to retail customers of the

distribution utilities. This approach may require a

preliminary finding that a workably competitive

situation exists for new power transactions and

continuing market oversight by State and or Federal

regulators. Most probably, regulators would be more

extensively involved in approving a utility’s assessment of capacity needs and in resolving disputes

over contract awards.

Prices for “old” power supplies would remain

under existing cost-based regulation. New competitive power supply prices could reflect levels of

service and other non-price factors. Prices for

transmission services would continue to be regulated by FERC. Greater reliance on transmission

services may increase pressure for transmission

pricing based on actual measured cost of service

with allowances for non-price factors62 Alternatively, there will also be pressure from transmission

owners and others to allow more flexible and

value-based transmission pricing.

Under scenario 3 QFs and IPPs would be able to

compete to sell wholesale power to utilities. They

would not have access to the transmission system to

sell power directly to retail purchasers, however,

5glJnder exlstlng law, FERC has jurisdiction over the prices for most wholesale power sates. PURPA exempted purchases of QF power from ~RC

price regulation, States have jurisdiction over utilities resouree planning and construction and retail rates. States are generally required to pass through

purchased power costs at FERC approved prices under the “filed rate doctrine.” Without a change in PURPA or the Federal Power Act, FERC would

have to approve contract prices for purchases from utilities and IPPs under a State com~titive procurement program. See discussions in ch. 2.

60N0.86.1970, June 24, 1988.

61@stimsa~tthe pm~m of u~l~ ~islons in aw~ding bulk power Contrwts Could wise later if a utility overestimated future demand ad was

left with a take or pay contract for unneded electric power. The central issue would not be the contract price, but whether the utility’s initial decision

to purchase additional supplies was prudent and whether the full costs should be passed through to ratepayers, Another possible subsequent retail rate

issue might arise over a utility prudenee in signing a contract with price escalation clauses that resulted in actual contract prices that exceeded those

on which the initial bid was awarded.

GZTr~smission @ces ~ now corrtntonIy set in several ways, postage stamp rates, split the difference in savings rate, md others. StX Ntiond

Regulatory Researeh Institute, Some Prineiplesfor Pricing Whee/ed Power (Columbus, OH: August 1987). Edison Electric Institute, Rate Regulation

~p~ent, Te~ and Conditions of Existing Trmwnission Service Agreements, 04-85-05, 1985.
Chapter 3-Alternative Scenarios for increasing Competition in the Electric Power Industry ● 81

except to the extent that utilities controlling the grid

voluntarily agreed to provide wheeling services.

Systems Operations and Planning

System reliability and coordination would be

maintained as in scenarios 1 and 2 with primary

responsibility resting with the local utility and/or

control center. Operational requirements for nonutility generators (e.g., QFs and IPPs) would be based

on contract terms with the local utility (or wheeling

utilities). More formalized agreements would be

needed to replace many of the current informal

operating arrangements of integrated utilities and

power pools as electric power supply functions are

increasingly “unbundled.”

Dispatch, maintenance, and unit loading schedules for the system would largely be handled by the

local utility or control center. Specific dispatch and

scheduling responsibilities of nonutility generators

and transmission accessors would be negotiated by

contracts among the generators, power purchasers,

and wheeling utilities as in scenario 2.

Emergency curtailments of generation and transmission services would be dealt with as in scenario

2.

Planning and developing generating capacity

additions would primarily be the responsibility of

the local utility as in scenario 2. Because the States

would require utilities to use a competitive selection

process (including consideration of non-price factors) for new power supplies, State regulators would

be more heavily involved in overseeing utility

demand forecasts and determinations of capacity

needs. Independent generators would be free to

make their own plans for new construction based in

part upon the utilities’ needs and in part on their own

expectations of profit.

Transmission additions would be planned and

built by the public utility transmission company or

division with review and approval by regulatory

authorities. State rules may require utilities to plan

for adequate capacity for instate wheeling of new

power supplies and to consider regional transmission needs. As in scenario 2, FERC may order a

utility to expand its transmission capacity to provide

mandatory wheeling services.

Planning and building additions to the distribution system would remain the responsibility of the

local utility.

Conservation and load management planning

and implementation would be the responsibility of

local utilities as in scenarios 1 and 2. State authorities may require consideration of potential contributions of conservation and load management strategies as part of utilities’ least-cost planning and in

approving retail rates. State regulators might also

allow demand side options to compete directly in the

bidding process for capacity additions.63

SCENARIO 4

All Source Competition for All Bulk Power Supplies

With Generation Segregated From Transmission and

Distribution Services

Scenario 4 would restructure the U.S. electric

power industry and its regulatory institutions and

create a competitive, unregulated generating sector

and a structurally separate regulated transmission

and distribution sector. Integrated utilities would be

required to segregate generation activities, both

institutionally and operationally, from transmission

and distribution to limit the potential for self-dealing

and cross-subsidization. Owners of existing and new

generation sources would compete to sell power to

regulated transmission and distribution companies.

Some transmission companies could also act as

power brokers or wholesalers providing bulk power

supply planning, purchasing, and delivery services

to distribution utilities. Purchasing utilities would be

assured access to transmission services for their bulk

power needs (capacity permitting).

The scenario would entail substantial rewriting of

Federal and State laws governing utility regulation

with greater emphasis on authority for overseeing

the competitiveness of bulk power markets and

regulating transmission services and power brokers.

Modifications of the public utility ownership restrictions in the Federal Power Act, PURPA, and

63~egu]alors in Maine have a]]ow~ dem~d.sjde rn~agement options to compete [o provide needed dccrerncnts of power caP~itY. In bidding

conduclcd by Central Maine Power for 100 NIV/ of capacity, 13 of 37 total bids were for dcmand-side managemcn[ projects, however these projects

rcpresen[cd only 35.6 MW out of more than 1,145 MW offered. On a price basis, the dcmand side projccls averaged 75 pcrccnt of the utility’s avoided

costs, while the supply side offers averaged 97 percent of avoided costs. Issues Review and Tracking, Aug. 4, 1988, p. 1.
82 ● Electric Power Wheeling and Dealing: Technological Considerations for Increasing Competition

PUHCA would allow broader participation in generation markets. State regulatory schemes would

also have to be overhauled to accommodate this

scenario. The scenario could shift the primary locus

of utility regulation from States to the Federal

Government, but implementing legislation could

maintain a balance by giving greater wholesale

authority to State regulators. States would regulate

the prices, operations, and quality of service of retail

distribution companies. Transmission capacity, services, and rates would be subject to mixed Federal and

State regulation.

Background

Scenario 4 is derived from proposals that would

structurally disaggregate the electric power industry

to allow the generating sector to become both more

dependent on the discipline of competitive market

forces and free from many of the pricing and entry

restraints of the existing regulatory system.* Under

scenario 4, the organizational structure of the

electric power industry would begin to resemble that

of the natural gas industry where production, interstate transmission, and local distribution are generally under separate ownership (although there are

numerous cases of “upstream” and “downstream”

integration).

Scenario 4 would open all power supply contracts

to competition, unlike Scenario 3, which is limited

to new bulk power sources. Because Scenario 4

would be applied industry wide, it would probably

involve a transition period of many years to allow a

gradual phase-out of rate-of-return regulation, orderly restructuring and divestiture of assets, and

renegotiation of existing arrangements.65

Radical industry restructuring has some precedent

in the recent experience in breaking up AT&T and

deregulating much of the telephone industry. On a

much smaller scale, several utilities have sought to

revamp their internal structures to set up holding

companies, split power system functions into separate subsidiaries, and create unregulated competitive

generating subsidiaries.66 But, there is no precedent

for radical restructuring and deregulation of an

industry similar to electric power that is characterized by long-term investment, heavy fixed costs, an

obligation to serve, and which is in a period of excess

capacity. The restructuring under scenario 4 raises

major questions of public policy and equitable

treatment of stockholders and ratepayers in allocating any increased value for existing assets.

As one benefit of removing most price and entry

restrictions from the generating sector and replacing

them with open competition, “there would be strong,

direct incentives for efficiency in construction, and

new units would be built by companies that could

offer capacity at the lowest life cycle costs. ’*7 The

principal risk would be threats to the reliability and

stability of the overall integrated systems arising

from lack of or reduced coordination among competing entities. Proponents believe there would also be

substantial efficiency gains in the use of all available

generating units to meet regional electricity demands. In their view, these efficiency gains would

not likely be achieved under the existing structure

because of the disincentives to increased bulk power

transfers among utility control areas, difficulties in

forming power pools, and transmission capacity

constraints.

64s= faexmple, Ric~d J. pieu, Jr., “A ROpOSaI to Deregulate the Market for Bulk Power,” 72 Virginia Luw Rev. 1183 ( 1986); Aspen Institute,

“Electric Utilities: Structure and Regulation,” Energy Policy Forum, 1986; and William W. Berry, ‘“llte Case for Competition in the Electric Utility

Industry,” 110 Public Utilities Fortnightly 13 (1982).

6SAI lemt one ~P=nt of a simil~ approach argues that mandatory divestiture and reorganization of the industry by courts and legislatures would

not be needed because competitive pmsures would fom.e fms to restructure vokntarily through spinoffs, mergers, and acquisitions eventually producing

the desired efficient industry structure. This process could, however, take as long as 20 or 30 years. Pierce, supra note 64, p. 1214.

66For exmple, ~blic Sewice c~p~y of New Mexico pre a significant corporate restructuring that would form a holding comP~Y, sP1it most

generation and transmission assets into a separate competitive subsidiary, and sell power under long-term contracts to a distribution subsidiary and its

wholesale customers. The company dropped its proposal in mid- 1988 because of the criticisms raised by some State agencies and the City of Albuquerque,

its largest wholesale customer.

67wllljm W, Mw, c’~e Implicatiomof ~~~mf~ ~ec~c IJtilities,’’Cotrtment for the Reason Foundation Conference on Deregulating Public

Utilities, 1987.
Chapter 3-Alternative Scenarios for increasing Competition in the Electric Power Industry ● 83

Implementation

Scenario 4 would require substantial changes in

both Federal and State laws governing the electric

power industry. The Federal Power Act’s jurisdictional and procedural requirements would be substantially revised to reflect the new institutional

structures with greater emphasis on creating effective mechanisms for overseeing the competitiveness

of bulk power markets and regulating transmission

services and power brokers. PURPA and PUHCA

would also require amendment to remove statutory

barriers to full participation in the competitive

generating sector. This would allow utilities’ generating companies to compete outside of their regional

territories without coming under the full financial

and operational restrictions imposed on regulated

utility holding companies. Continuation of PURPA’s

purchase and sale obligations for alternative energy

sources might also require reexamination to determine if they still were effective and/or appropriate

under a changed industry structure.

The transmission and distribution segments of the

industry would continue to be regulated heavily

while generation would be subject only to competitive market forces, regulatory oversight, and antitrust laws. Price and entry regulation for the

generation sector would be replaced with competitive markets. Generators would still be subject to

environmental, siting, financial, and antitrust requirements imposed by other State and Federal laws

under scenario 4 and all others. The States would

regulate the prices, operations, and quality of service

of retail distribution companies. State regulators

would review the power purchase contracts of

distribution utilities, but the effectiveness of State

programs would be hindered without some mechanism to review the adequacy of competitive market

transactions. Transmission capacity, services, and

rates would be subject to mixed Federal and State

regulation. Under this scenario there is the potential

for increased Federal regulation and oversight of

bulk power supplies and what were formerly intrasystem transmission arrangements. Implementing

legislation could, however, provide for a more

balanced Federal-State division of regulatory authority to give States greater control over intrastate

activities.

Vertical integration of the electric power industry

would be reduced by the separation of utility

generating segments from transmission and distribution segments.68 This could be accomplished by

creating new subsidiaries or divisions, or by spinning off a new company and then “selling” the

required physical plant and other assets to the new

entity. 69 Segregated utility generators, QFs, and

IPPs could compete to provide power supplies to

transmission-distribution and local distribution companies. Age, performance, and fuels of existing units

will affect the competitive strengths of the new

generating companies. These competitive differences could eventually lead to a consolidation of the

industry .70

Under scenario 4 local distribution companies

would be primarily responsible for securing adequate power supplies from competing suppliers

through contract solicitations and negotiations. Regulated transmission companies would own and operate the transmission facilities and be responsible for

planning and building networks with adequate

capacity to serve buyers and sellers in a competitive

market. Transmission companies would function as

regional controllers and dispatchers of generation

and provide wheeling services for utilities under

regulated rate schedules. They could also act as

power brokers or as wholesalers linking independent

generators and local distribution utilities.

~under ~en~os A ~d 5, he pl@C~ ~ViSiOn of integrated utility facilities among the newly disaggregate entities would probably not KfhXt a

clearcut allocation of generation, transmission, and distribution facilities. It is likely that at least a portion of the transmission facilities associated with

individual generating stations might be retained by the generating subsidiary. Generators might have to construct their own transmission facilities to move

power to the point of delivery to the transmission or distribution companies. Similarly, trmrnission and distribution utilities would bc able to retain or

acquire smatl scattered generating units that provide essential system support or backup services.

@This financial restructuring and redistribution of assets will be a complex and controversial aspect of this scenario for utilities, shareholders,

regulators, and ratepayers alike. If not handled with caution, the transactions could result in a sizable transfer of wealth and assets from the regulated sectors

to the unregulated generators. There could be a tremendous incentive for owners of low cost older plains to move them as quickly as possible into the

unregulated market so as to capture a greater profit than would be allowed under regulated historic embedded cost pricing. This could leave a utility’s

high cost plants in the regulated sector.

70SW, for exmp]c, Joskow and Schmatensee, Supra note I t PP. 212-21s.
84 ● Electric Power Wheeling and Dealing: Technological Considerations for Increasing Competition

Generators and distribution companies could seek

transmission orders from FERC based on a public

interest standard similar to that in scenarios 2 and 3.

Unlike scenario 2 there would be no mandatory

wheeling for retail customers. It is expected, however, that many generators and transmission companies would sell directly to large retail customers

under arrangements for bypass or standby payments

to local distribution companies.

Distribution companies under scenario 4 would

retain an obligation to serve, that is, to plan for and

secure adequate electricity supplies for the needs of

their franchise customers. But with little or no

generating resources of their own, they would be

highly dependent on the willingness of independent

suppliers to construct needed capacity and the

availability of adequate transmission capacity to

move the power. Competing generating companies

would be under no legal obligation to build new

capacity, but would commit to do so if and when the

market price was sufficient to assure them an

attractive return. Thus, in the generating sector

market price signals would displace the utility’s

traditional service obligation as the principal mechanism for assuring the availability of adequate and

reliable power supplies. The experiences of the

numerous independent distribution companies that

currently obtain their electricity supplies and transmission services from larger integrated utilities

could provide helpful precedents.

Transmission under scenario 4 would begin to

assume some of the characteristics of a common

carrier, but the transmission entity would retain

some discretion over who was eligible to obtain

service and would not be required to provide

wheeling to retail customers. The transmission

company could not impose unreasonable or discriminatory conditions on transmission access. It

could, for example, specify minimum operating

standards to preserve system reliability and require

advance notice and financial commitments to reserve firm transmission capacity.

Independent generating companies and local distribution entities would be linked by these newly

created transmission entities, which would serve as

regional controllers and dispatchers of generating

capacity. In addition to this primary role, transmission utilities could also serve as regional power

brokers which would make the market for, and be

party to, contracts negotiated between independent

generating companies and distribution entities. Transmission companies might also assist in the creation

of secondary futures markets as a means of hedging

against the added uncertainty associated with a

vertically segregated industry.

Under scenario 4, transmission access would be

achieved primarily through voluntary negotiations;

however, the separate transmission entities would

have an obligation to provide adequate transmission

capacity to support the industry’s new competitive

structure. FERC would also have the authority to

order wheeling for customer utilities on a public

interest standard if satisfactory voluntary arrangements could not be reached through negotiation.

With FERC’S endorsement, States might require

nondiscriminatory access to transmission services as

a precondition for allowing existing regulated generation, transmission, and distribution companies to

participate in the new competitive system. Transmission access for retail customers would be kept on

a voluntary basis.

Systems Operations and Planning

System reliability and coordination would be

the responsibility of the regulated transmission

company or transmission-distribution company. The

transmission company would take over many of the

day-to-day functions of system coordination that are

now the responsibility of local utilities and control

centers. Operational responsibilities of power suppliers and local distribution companies would be

specified in contracts with State and Federal oversight.

Dispatch, unit loading, and maintenance schedules would be administered by the transmission

utility under various contracts between power suppliers and: 1) regulated transmission companies, 2)

regulated distribution companies, and/or 3) retail

customers. Dispatchable generators would be controlled by the transmission company and compensated for their services according to contract terms.

Emergency curtailments for retail customers

served by local distribution companies would be

allocated according to State-regulated curtailment

policies. For other customers, curtailments would be

specified in contracts with the transmission and
Chapter 3-Alternative Scenarios for Increasing Competition in the Electric Power Industry ● 85

generation suppliers. Curtailment of transmission

services will be based on contractual terms, State

and Federal regulation, and system reliability considerations.

Generating Capacity Additions: Future electric

supply requirements would be determined by the

local distribution company through its planning

processes with State oversight. Competition for

supply contracts would be open to all generating

sources, as in scenario 3. Independent generators

would plan and build new plants based on utilities’

indications of need and their own strategic plans and

profit expectations. Transmission utilities could also

contract for generating capacity to aid in preserving

system reliability and to allow them to serve as power

brokers subject to State and Federal regulation.

Transmission Additions: The regulated transmission or transmission-distribution companies would

have the obligation to provide transmission capacity

necessary to support wheeling needs for instate

utilities. (This assumes of course that wheeling is

economical and that wheeling customers are willing

to pay for the additional capacity needs.) States

could require transmission capacity planning to

include consideration and coordination of regional

transmission system needs.

Distribution additions would be the responsibility

of the locally regulated distribution utility, with oversight by State authorities-same as in scenario 3.

Conservation and load management programs

would be provided by local distribution companies,

possibly in conjunction with transmission companies. State regulators could require consideration of

potential contributions from load management and

conservation strategies as part of the distribution

utility’s least-cost planning processes in this and

other scenarios.

SCENARIO 5

Common Carrier Transmission Services in a Disaggregate,

Market-Oriented, Electric Power Industry

Scenario 5 would break up the vertically integrated electric power industry by divesting generation, transmission, and retail distribution segments

into separate entities. All customers (both wholesale

and retail) would have the option of purchasing

power from any willing supplier with the assurance

that such power could be delivered under reasonable

terms and conditions. Distribution and transmission

services would remain tightly regulated, but entry

and bulk power pricing in the electric generation

segment would primarily be left to market forces.

The competitive generation segment would include formerly regulated utility generation operations, QFs, and IPPs (although such distinctions

among power producers would no longer be relevant). Unlike scenario 4, ownership of generating

companies would be completely severed from ownership of transmission and distribution companies.

The regulated transmission companies would explicitly be required to provide transmission services

as a common carrier (i.e., nondiscriminatory service

based on approved wheeling tariffs to all parties

requesting service) and to provide adequate transmission capacity. Wheeling to retail customers

would be available, although as a practical matter it

would likely be limited to very large industrial

consumers. Federal and State policies might encourage greater aggregation in transmission services to

create coordinated large regional transmission

systems-either through mergers and acquisitions

or through operational agreements among neighboring systems.

Background

Scenario 5 includes many of the key elements of

the preceding scenarios including vertical disintegration of industry structure, market-based pricing

of generation, and transmission access. Under scenario 5, any generator could sell to any buyer, any

buyer could purchase from any seller, and the

transmission company would have to wheel the

power. Proponents of this radical restructuring of the

industry cite a number of technological and public

policy reasons for adopting this approach.71 Chief

among them are: the decline of the natural monopoly

characteristics of the generating sector; the excess

generating capacity in many regions; and the presumably higher social and economic costs to society

7 Is= forexmple, phlllp R. O’CoMor, RO&II G, Bu~a, and Wayne P. OIson, “Competition, Financial Imovation, and Diversity in tie EIwtric power

Industry,” Public Ufilifies For?nighdy, Feb. 20, 1986, pp. 17-21; Philip R. O’Connor, “The Transition to Competition in the Electric Power Industxy,”

Illinois Commerce Commission (presen!ed at the American Power Conference, Chicago, IL, Apr. 22, 1985); and Matthew Cohen, Essay: “Efficiency

and Competition in the Electric Power Indusq,” 88 Yule Luw Journul 1511-1549, June 1979.
86 ● Electric Power Wheeling and Dealing: Technological Considerations for Increasing Competition

of “imperfect regulation” compared with “imperfect

competition.”

The key to having a vigorously competitive and

economically efficient electric power industry lies in

the evolution of new institutions and arrangements.72 This is unlikely to be accomplished merely

by allowing distribution utilities and others to shop

around for the best bulk power deal without first

establishing the necessary competitive market environment. Among the changes in industry regulation,

operations and structure that would lead to achievement of this scenario are:

●

●

●

●

●

encouraging the regionalization of utility regulation and operations by expanding the use of

centralized dispatch of generating capacity

within States or regions;

creating power brokerage and auction markets;

realigning Federal and State regulatory authority to allow States clear authority in intrastate

bulk power and wheeling markets;

creating federally approved interstate regulatory compacts for governance of central dispatch, auction, and brokerage systems; and

assuring open and fair access to transmission

systems either through mandatory wheeling or

through creation of new regional transmission

entities.

Implementation

Scenario 5 would require rewriting of existing

State and Federal laws and regulations governing

electric power generation, transmission, and distribution. Although “deregulated,” the competitive

generating sector would need continuing oversight

to assure the existence of workably competitive

markets. In addition, new contractual arrangements

and industry practices would have to evolve to

assure effective operations under a new disintegrated, market-based industry structure, and to

preserve reliability and stability of interconnected

electric power systems.

Regulators would approve the transmission company’s wheeling tariffs for both utility and nonutility

generators. FERC (or perhaps a regional authority)

would have the power to issue wheeling orders to

facilitate bulk power transfers if satisfactory arrangements could not be made with the transmission

company. Wheeling rates would be designed to

include adequate signals to assure construction of

new transmission facilities. The transmission utility

also would have an obligation to plan for and build

adequate and reliable transmission capacity to serve

regional needs and to accommodate interregional

transfers. Wheeling customers could contract for

different levels of service (e.g., firm, interruptible).

Bulk power prices would be set through competitive markets and passed through to ratepayers.

Power purchases by distribution companies and

retail rates would be regulated by State authorities.

Retail rates and the need for and prudence of bulk

power purchases by distribution companies would

be regulated as now by State authorities. Rates

charged by transmission companies acting as power

brokers and reselling to distribution companies

would also be subject to regulatory oversight to

assure that there was no cross-subsidization of

operations or anticompetitive practices.

This scenario would involve the mobilization and

transfer of billions of dollars in utility assets to

newly established entities. Because of the complexity of the transactions, it is likely that many years

would be required to complete an orderly transition. 73 The essential step in achieving this scenario

would be the establishment of a separate and

functional common carrier transmission entity. This

could be accomplished simply by spinning off the

transmission assets and operations of a vertically

integrated utility to a new private entity. It could also

be accomplished through legislation to create federally chartered and publicly held regional transmission (and dispatch) corporations to acquire all

transmission lines and facilities within a designated

region.

72s= JO*OW ~d sc~~m=, suPam~e I, tipp. 104-1 (M, for their “scenario4” which adopts a similar approach. See also Edison Electric kstitute,

“Deregulation Issues and Concepts,” 1981. The industry structure of scenario 5 resembles that proposed for the utility industry in the United Kingdom

after privatization. See ch. 2 box 2-B. The U.S. industry and regulation structure are far more complex than the present government-run British system,

so that direct comparisons with the U.K. proposal are of limited value.

73A det~]~ trwition plm for ~hiev~g ~s ~~ of indus~ h~ been outlined conceptu~]y by fiillip O’Connor, fo~er Chairman Of the I]linOiS

Commerce Commission. O’Comor’s lo-step process would gradually transform the industry into a vertically disintegrated structure with market-based

pricing of generation evolving in conjunction with regulated transmission and distribution entities. O’Comor, supra note71.
Chapter 3--Alternative Scenarios for Increasing Competition in the Electric Power Industry ● 87

Systems Operations and Planning

System reliability and coordination would be

maintained by the separate, regulated transmission

company. The operational responsibilities of power

suppliers and local distribution companies would be

specified in contracts with the transmission company.

Dispatch, unit loading, and maintenance schedules would be determined by the transmission

company in negotiation with generators and governed by contracts as in scenario 4.

Emergency curtailments of electric power and

transmission services would be allocated according

to contractual arrangements and/or State regulations.

Generating capacity additions would be

planned and built by independent generating companies based on their strategic plans, profit expectations, and transmission and distribution utilities’

indications of need, Distribution and transmission

companies (jointly or separately) would project

future demand and determine the desired mix of

generating resources to meet those needs before

soliciting contract bids from power suppliers.

Transmission additions would be planned and

built by the transmission utility which would have

an obligation to provide adequate and reliable

transmission capacity necessary to supply the wheeling needs of anticipated customers. Regulatory

authorities may require consideration and coordination of regional transmission capacity needs in

planning.

Distribution additions would be planned and

built by the local distribution utility as in scenario 4.

Conservation and load management strategies

would be developed by local distribution companies

in cooperation with transmission companies and

regulatory authorities.

ANALYSIS OF THE SCENARIOS

These scenarios were used by OTA and its

contractors in its assessment of the technical and

institutional feasibility of expanding competition

and opening up transmission access. Chapter 5 looks

at the technical aspects of changing the electric

power infrastructure to accommodate the scenarios

and some cost and performance implications. Chapter 6 examines the regional characteristics of the

electric power industry and how they might affect

the successful implementation of the scenarios.

Finally, chapter 8 examines policy options for

resolving some of the technical and institutional

problems identified in OTA’S analysis.

There are many other possible scenarios that

could be used. Selection of these five reflect the best

judgment of OTA staff and others about the range of

possible future industry structures that may be most

useful in testing the technical feasibility of adapting

existing bulk power systems to change.

The five OTA scenarios were developed and

analyzed for the limited purposes of this assessment.

These scenarios are not intended as legislative

policy options. They may not be, in some respects,

the optimal or most probable policy choices in

considering the creation of a new regulatory and

institutional framework for the U.S. electric utility

industry as a whole.

Many difficult and controversial aspects of making the electric power industry more competitive are

not included in OTA’s review of the technological

feasibility of expanded competition and increased

transmission access. We did not conduct an extensive analysis of all the legislative and regulatory

changes that would be needed to implement each of

the scenarios. For example, we did not analyze in

detail the considerations to be addressed in deciding

on whether to grant a petition for mandatory

transmission access under a revised public interest

standard. Nor did we address the very thorny

problems of how to divide the assets and liabilities

of existing utilities among ratepayers, shareholders,

and regulated and unregulated subsidiaries. Issues of

national energy policy were also beyond the scope of

this study. Therefore, we did not examine in any

detail the possible implications of changing PURPA’s

preference for certain classes of cogenerators and

small power producers. OTA’s study may, of course,

help to identify many of these issues for Congress.

The scenarios may also prove a useful tool for

analyzing these policy options and responses.
Chapter 4

Power System Technology
CONTENTS

INTRODUCTION *.. **. .. ... *.. .*. ... ... ... ... ... ... *.** *.*.*

OVERVIEW OF POWER SYSTEM EQUIPMENT . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

COORDINATED OPERATIONS AND PLANNING . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Performance Standards . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Operating and Planning Requirements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Implementing Coordinated Operations and Planning . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

INCREASING TRANSMISSION CAPABILITY

Limits to Transfer Capability . . . . . . . . . . . . . . . .

Constraints on Individual Components . . . . . . . .

System Operating Constraints . . . . . . . . . . . . . . . .

System Stability . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Prospects for Increasing Capability . . . . . . . . . . .

Increasing the Capacity of an Existing Line . . .

Controlling Real Power Flows . . .

Stability Response . . . . . . . . . . . . . .

Future Trends . . . . . . . . . . . . . . . . . .

High-Power Semiconductors . . . . .

Improving Computer Capabilities

Superconductivity . . . . . . . . . . . . . . .

Box

4-A.

4-B.

4-c.

4-D.

. . . . . . . . . . . .

. . . . . . . . . . . .

. . . . . . . . . . . .

. . . . . . . . . . . .

. . . . . . . . . . . .

. . . . . . . . . . . .

Boxes

Three Common Reliability Standards . . . . . .

Real and Reactive Power . . . . . . . . . . . . . . . . . .

Example of Transmission Constraints . . . . . .

,.. .

. . . .

. . . .

.*. .

... ,

. . . .

. . . .

● ✎✎☛

✎ ✎ ✎ ✎

✎ ✎ ✎ ✎

✎ ✎ ✎ ✎

✎ ✎ ✎ ✎

✎ ✎ ✎ ✎

✎ ✎ ✎ ✎

✎ ✎ ✎ ✎

✎ ✎ ✎ ✎

● ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎

✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎

✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎

✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎

✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎

✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎

✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎

✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎

✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎

✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎

✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎

✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎

✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎ ✎

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Loop Flows in the Western System Coordinating Council (WSCC) . . . . . . . . . . . . .

4-1. A Simple Electric System . . . . . . . . . . . . . . . . . .

4-2. Transmission Line . . . . . . . . . . . . . . . . ... . . .

4-3. Weekly Load Curve . . . . . . . . . . . . . . . . . . . . . . .

4-4. Transmission System Limitations . . . . . . . . . .

4-5. Western Interconnected System . . . . . . . . . . . .

Tables

Table

4-1. ANSI Standard Voltage Limits . . . . . . . . . . . . .

4-2. Operation and Planning Functions . . . . . . . . . .

4-3. Typical Generator Response Rates . . . . . . . . . .

Figures

Figure

. . . .

. . . .

. . . .

. . . .

. . . .

. . . .

. . . .

. . . .

91

91

94

94

97

100

107

107

108

110

111

113

115

116

117

117

117

119

120

Page

98

104

112

114

Page

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 92

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 93

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 99

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 113

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 114

Page

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

4-4. Key Physical Characteristics of Generating Plants . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

4-5. Key Transmission Planning Characteristics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

4-6. Transmission Capability Constraints . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ~... . . . . . . .

4-7. Technologies To Increase Transfer Capability . . . . . . . . . . +... . . . . . . . . . . . . . . . . . . .

96

101

102

109

109

109

115
Chapter 4

Power System Technology

INTRODUCTION

An electric power system is a vast, complex

machine composed of a large number of generators,

transmission lines, distribution systems, and substations. Although less physically obvious than generators and transmission lines, systems to coordinate

the operation and planning are also vital components

without which power systems could not function.

Coordination systems include monitoring and communication equipment, devices that actually control

generators and transmission lines, and engineering

models and expertise which specify how to operate

generators and transmission lines as well as plan

equipment additions.

As discussed in chapter 1, the demands on power

systems are changing. Electricity generation is

becoming increasingly competitive, with new forms

of ownership and control, and some new technologies are being introduced. Both generators and

purchasers of power are seeking greater access to

transmission. Utilities are pursuing new methods to

reduce costs by improving operating efficiency.

Improving operating efficiency, integrating competitive power supplies, and wheeling power require

modifications of uncertain technical feasibility and

economic merit. Can a power system operate with

many separately owned generating companies and

power purchasers demanding access? Is there sufficient transfer capacity to accommodate the changes?

What will be the impact on reliability and efficiency?

The physical principles of electricity greatly

complicate answering the technical questions. Because power flows at nearly the speed of light with

virtually no storage of electricity in a system, the

supply of power must balance customer demand at

every instant. Also, the flow of power on individual

transmission lines is difficult to control. Consequently, the performance of all components is highly

interrelated. For example, a generator failure instantly alters the power flows on transmission lines,

perhaps beyond safe physical limits, while requiring

that other generators immediately increase output to

meet demand. Due to the highly integrated nature of

power systems, answering the technical questions

requires examining the overall power system and the

role played by each of the major components.

Chapter 4 examines current and future power

system technology, and the opportunities to increase

transfer capabilities and operating efficiencies of

existing systems. The first section discusses the

fundamentals of power systems—the equipment

that composes the system and their performance

requirements. The second section examines the

functions involved in coordinating all the individual

generators and transmission components into an

integrated bulk power system. The last section

examines the physics of power transfers, and opportunities to increase transfer capability.

OVERVIEW OF POWER

SYSTEM EQUIPMENT

An electric power system is comprised of the

major pieces of equipment we commonly associate

with the utility industry. This equipment includes

generating units that produce electricity, transmission lines that transport electricity over long

distances, distribution lines that deliver the electricity to customers, and substations that connect the

pieces to each other. The bulk power system includes

the generating plants, transmission lines, and their

associated equipment. Energy control centers coordinate the operation of the bulk power system

components from moment to moment and prepare

for the near future. A wide variety of other planning

and engineering systems coordinate operating and

capacity expansion plans for the longer term. Figure

4-1 shows a simple electric system with two power

plants and three distribution systems connected by a

transmission network of four transmission lines.

The U.S. power industry uses a variety of fuels

and technologies to generate electricity. Nuclear

fission, fossil fuels, and falling water are all commonly used to drive electric generators which

convert mechanical energy into electricity. Conventional generators typically produce 60 cycle/second

(Hertz or Hz) alternating-current (AC) electricity

with voltages between 12 and 30 kilovolts (kV). The

60 Hz power is generated in three time-varying

-91 -
92 ● Electric Power Wheeling and Dealing: Technological Considerationsfor Increasing Competition

.

Power plant/subs tat I n

Figure 4-l-A Simple Electric System

Energy Interconnection

control center

I

Power PI ant/substation

Interconnection I I

Distribution system

SOURCE: Offices of Technology Assessment, 1989.

sinusoidal patterns, called phases. Generating units

have automatic voltage regulators which control the

unit’s voltage output and speed governors which

adjust power output and frequency in response to

demand and changing system conditions.

A wide and growing variety of unconventional

generation technologies have been developed, too.

These include cogeneration, conversion of solar

energy to electricity, wind-driven generators, and

unconventional fuels such as waste material. The

mix of fuels and technologies changes from year to

year as new units are built and old units are retired.]

A generation substation connects generators to

transmission lines. To minimize losses over long

distances, transmission lines require high voltages,

typically between 69 and 765 kV. Power transformers at the substations raise the voltage to these high

levels for efficient transmission. Substations also

house a variety of equipment for monitoring and

communication and for controlling and protecting

both the transmission and generation facilities. A

power plant consists of one or more generating units

on a site together with a substation.

Transmission lines carry electric energy from the

power plants to the distribution systems. Most

transmission in the United States consists of overhead AC lines operated at 69 kV or above. Often,

lower voltage transmission lines operating at between 23 and 138 kV are termed sub transmission,

although the distinction depends on the characteristics of the individual utility system and is not

uniformly applied.

ISCC ch. 6 for a brc~down of the mix of generating CaPaC@.
Chapter 4--Power System Technology ● 93

Power actually flows along bundled strands of

wire called conductors. Conductors are bare metal

cables, typically aluminum strands around a steel

core. AC transmission lines typically have three

individual or paired conductors to carry three-phase

power. There are some segments of direct current

transmission and underground cables for special

applications, although these are less common than

overhead AC lines. Figure 4-2 shows a typical

transmission line, consisting of a right-of-way,

towers to support the conductors, the conductors

themselves attached to the towers by insulators, and

additional shield wires to protect the conductors

from lightning.

The width of the right of way and the tower design

are determined by the voltage of the line and the

Figure 4-2-Transmission Line

Photo credit: Cassaza, Schultz & Associates, Inc

need for air insulation to prevent electricity from

flashing over (i.e., arcing between a conductor and

the ground or the tower). Towers may be made of

wood, concrete, steel, or aluminum depending on the

number and weight of conductors, the terrain, and

the distance between towers. In addition to the

weight of the conductors, the towers must be able to

support any ice which forms on the lines and the

force of wind. Typically, high-voltage lines have

numerous heavy conductors, requiring use of metal

towers for strength.

In addition to the conductors and towers themselves, transmission systems have monitoring, control, and protective devices much like those found in

power plant substations. Transmission substations

house this equipment together with devices used to

regulate voltage and power flow on the lines.

An interconnected group of individual transmission lines comprises a transmission system. A

transmission line connected at both ends to other

transmission lines is part of the grid or network.

Transmission lines connected to the grid at only one

end, with the other end connected either to a

generating plant or customer loads, are called radial

or feeder lines. The transmission system shown in

figure 4-1 allows each distribution system to receive

power from either of the power plants. Even if one

network line is disconnected, each distribution

system can still receive power from both generators.

Some very large electric consumers, such as

major industrial plants take their power directly

from the transmission system, typically at subtransmission voltage levels between 23 and 138 kV. A

substation containing metering, protective, and switching apparatus connect these large customers to a

transmission line. Most customers, however, receive

their electricity from a distribution system.

Distribution systems operate at lower voltages

than the transmission system, typically under 35 kV,

to transport smaller amounts of electricity relatively

short distances. Power transformers reduce the

high-voltage electricity from the transmission system to the lower distribution system level. The

power transformers are housed together with control

and protection devices in distribution substations.

The distribution system is divided into primary

and secondary systems. The primary distribution
94 ● Electric Power Wheeling and Dealing: Technological Considerations for Increasing Competition

system operates at between 2.4 and 35 kV. Some

moderately large customers, typically industrial or

large commercial, take their electric service from the

primary system directly. Most customers receive

their electricity from the secondary distribution

system at voltages between 110 and 600 volts. The

primary distribution system delivers power to distribution transformers which reduce voltage to the

secondary system voltage levels. Secondary distribution systems typically serve groups of customers in neighborhoods. Unlike transmission lines,

secondary distribution systems typically carry single

phase rather than three phase power. Primary

distribution may be either single or three phase.

Protective apparatus in the distribution system

include circuit breakers in distribution substations

that open automatically when a protective relay

detects a fault (or short circuit) and fuses on the

secondary systems that open when overloads occur.

Many of the circuit breakers and switches in

distribution circuits are manually operated devices,

so restoring service after outages occur is usually

done manually.

Nearly all electric utilities in the United States are

connected to neighboring utilities through one or

more transmission links, or tie lines. Each utility is

responsible for providing the power used by its

customers without taking power from neighbors

unless alternate arrangements have specifically been

made. Coordinated operation of interconnected systems is implemented through the institution of

control areas. A control area is a geographic region

with an energy control center (ECC) responsible for

operating the power system within that area. The

control area is defined electrically by telemetering

equipment on all transmission paths into and out of

the area. One or more utilities may makeup a control

area. The control area in figure 4-1 is interconnected

to two neighboring control areas through transmission lines.

Energy control centers employ a variety of

equipment and procedures: monitoring and communication equipment called telemetry to constantly

inform the center of generator output and system

conditions; computer-based analytical and data

processing tools which together with engineering

expertise specify how to operate generators and

transmission lines; and governors, switches, and

other devices which actually control generators and

transmission lines. The control center equipment

and procedures are typically organized into three

somewhat overlapping systems which are sometimes integrated in a full energy management system

(EMS). They are the automatic generation control

(AGC) system which coordinates the power output

of generators; the supervisory control and data

acquisition (SCADA) system which coordinates

transmission line equipment and generator voltages;

and advanced applications, such as analytical systems to monitor and evaluate system security and

performance, and plan operations.

COORDINATED OPERATIONS

AND PLANNING

The electric power system is a complex entity

comprised of many interacting electrical and mechanical parts. Utilities may have a dozen or more

generating units and transmission lines, and hundreds of distribution systems serving hundreds of

thousands of customers each with a variety of energy

using devices. Coordinating the operation and planning of a utility’s equipment to meet the demand for

electricity is the responsibility of operating and

planning systems. The integrated operation and

planning of modem power systems represents decades of evolution and development.

Performance Standards

One underlying goal in planning and operating a

power system is to provide electricity that meets

customer requirements safely and reliably. This

entails:

. providing electricity with the correct voltage

and frequency to operate consuming equipment; and

. providing that power with an acceptable level

of outages or service interruptions.

In practice voltage, frequency, and reliability maybe

viewed as constraints or standards which must be

met.

Frequency Standards

A relatively constant frequency of 60 Hz is taken

for granted in the design of customers’ equipment

such as motors, clocks, and electronics. Actual

frequencies in U.S. power systems rarely deviate
Chapter 4--Power System Technology ● 95

beyond 59.9 and 60.1 Hz, well within the tolerance

of consumers’ electronic equipment and motors.2

Some clocks work by actually counting the

number of cycles (i.e., every 60 cycles is 1 second).

Keeping correct time requires that total deviation

from 60 Hz over time is small and balanced. For

example, when frequency fluctuates, clocks slow

down or speed up accordingly. Later, the frequency

must be adjusted to correct the time. The total

deviation, called time error, is very small and

insignificant.

Power system equipment itself is more sensitive

to frequency deviations than consumer equipment.

In particular, the control systems of modem power

systems are designed to be extremely sensitive to

frequency deviations. To function, the control systems actually require very slight deviations and must

closely monitor time error. (The slight frequency

deviations are essentially used for communication

between generators and the control system, as

discussed later.) For this reason, standards for

frequency are set by the utilities in designing their

controls, and frequency fluctuations have virtually

no consumer impact. Standards for frequency and

time error are set by the Operating Committee of the

North American Electric Reliability Council.

Besides maintaining a relatively constant system

frequency around 60 Hz, another frequency requirement is to avoid nonsystem frequencies. Some

electrical equipment creates nonsystem frequencies

besides the normal 60 Hz power, which may

propagate through a transmission or distribution

system and damage other equipment.3

For example, harmonic frequencies, i.e., integral

multiples of 60 Hz such as 120 or 180 Hz,

superimposed on the desired frequency may cause

communication equipment malfunctions. Standards

for nonsystem frequencies have not been uniformly

established, partly because severe problems have

been limited.

Voltage Standards

Unlike frequency, which

locations in a power system

point to point. The voltages

is the same at all

voltage varies from

throughout a power

system depend on the voltage output of individual

generators and voltage control devices and the flows

of power through the transmission system.

Some voltage standards for power delivered to

customers are widely accepted and published by the

American National Standards Institute (ANSI) (see

table 4-1).A These standards are given both for

normal, sustained conditions and for emergency

conditions lasting a few hours. The less stringent

shorter term standards allow system operators greater freedom in responding to emergencies. The

selection of voltage standards for delivered electricity reflects an implicit balance between the cost

of maintaining the standard and consumers’ benefits.

The ANSI voltage standards have been developed

because many types of customer equipment require

certain minimum standards to function properly. For

example, with excessively low voltage, electric

motors function poorly and may overheat and lights

dim. Overly high voltages, on the other hand,

shorten the lives of lamps substantially and increase

motor power which may damage attached equipment.5

Not all equipment has narrow voltage tolerances,

however. Electric resistance space and water heaters

work well over a wider range of voltages and are

insensitive to fluctuations, for example.

The ANSI voltage standards do not apply for

short-term voltage fluctuations lasting a few seconds

or less. Switching transmission lines and generators

on or off and turning on major appliances may create

voltage spikes or drops. Voltage fluctuations may

damage computers and other electronic equipment

or cause lights to flicker. However, standards for

short-term fluctuations are far less uniformly established than those for longer term voltage variations.

ISra~Wd ~~~&ook of Electrica/Engi~ering, Donald Fink (cd.) (New York, Ny: McGraw ~iill~ 1978)! PP. 20~6.

3Ha~ook of Modern Electronics ~Electrical Engineering, ch~]es Be]ove (cd. ) ( New York, NY: John Wiley & Sons, 1986), pp. 2318-2319.

E.F. Fuchs, D.J. Roesler, and F.S. Alashhab, Sensitivity ofEleclriculApphances to Harmonics and Fractional Harmonics of the Power System’s Voltuge,

Parts 1 and 2, IEEE Transactions of Power Deliver, vol. PWRD-2, No. 2, April 1987.

qAmeri~~ Na[ional st~d~ds Institute, Naziomz/ Electrical Saj?ty Code—1987 Edition, ANSI ~‘19~7.

SD. Fink, op. C1l., foo~otC 2.
96 ● Electric Power Wheeling and Dealing: Technological Considerations for Increasing Competition

Table 4-1-ANSI Standard Voltage Limits

Voltage limits (in percent of nominal)

Normal operating Emergency

conditions conditions

Nominal voltage Minimum Maximum Minimum Maximum

120-600 . . . . . . . . . . . . . . . 95 105 91.7 105.8

600-34,500 . . . . . . . . . . , . . 97.5 105 95 105.8

SOURCE: Power Technologies, Inc., “Technical Background and Conwterations m Proposed Irwreasad Wheeling, Transmission Access,

and Non-Utility Generation, ” contractor repon prepared for the Offrca of Technology Assessment, March 1986, pp. 1 14.

Some industrial customers have installed their own

protective gear to guard equipment against out of

range voltages. With the proliferation of computers

and other sensitive electronics, an increasing number of customers are purchasing protective devices

which filter out voltage fluctuations.

Reliability Standards

Reliability is a measure of the ongoing ability of

a power system to avoid outages and continue to

supply electricity with the appropriate frequency

and voltage to customers. In contrast to the standards

for voltage and frequency, reliability goals reflect

customer preferences for the trade-off between

electricity prices and outages rather than the actual

design and operating requirements of customer

equipment.

Establishing objective, quantitatively derived standards that accurately reflect the value of service

reliability has proven difficult. Ideally, standards

should balance the customers’ value placed on

reliability with the costs of providing it. However,

determining the value of reliability to customers has

proven challenging because of the wide variance in

customers’ costs from an outage. Customer outage

costs depend on a host of diverse factors including:

the magnitude of the outage (the total amount

of energy or power not supplied);

how often outages occur, and the duration of the

outage;

how prepared the customer is;

the type of customer (e.g., industrial or residential); and

. the time of day, day of week, and season of the

outage.

Determining the cost to a utility of providing

increased reliability is similarly challenging. Bulk

system outages occur when generation and transmission are insufficient to meet total customer demand

at any instant. However, neither loads nor the

availability of generation and transmission can be

forecast with great accuracy. In particular, relatively

infrequent and unpredictable events (e.g., a lightning

strike on a transmission line or sudden equipment

failure) may suddenly reduce the availability of a

critical generator or transmission line. Also, analyzing the joint reliability impacts of transmission

and generation is challenging. Thorough examination of the complex interactions between individual

power system components under the nearly endless

array of possible conditions is analytically intractable. As a result, it is difficult to calculate the

improved reliability resulting from adding new

generation or transmission equipments

Further, even with high bulk system reliability, a

large number of outages may occur. In fact, bulk

system failures account for a relatively small portion

of customer service outages, around 20 percent by

one estimate.7 The remainder is caused by distribution system problems, often the result of storm

damage to distribution lines.

In lieu of more quantitatively derived and defined

standards for reliability, engineering planners as6For ~ comprehensive disc~sion of tie cha,tlenges of cvalua(ing reliability impacts focusing on the chalknges of integrating generation and

transmission effects, see Public Service Electric & Gas Co., Composite System Reliability Evaluation: Phase 1, Scoping Study, Electric Power Research

Institute, EPRI EL-529(I, Deccmbcr 1987.

IJ.S. Departmcntof Energy, ‘‘The National Electric Reliability Study: Exccuiivc Summary,” DOE/EP-0003, April 1981, as cited in: Power Sysfem

Reliability Evahuuion, Institute of Elcctricat and Electronics Engineers, 1982, p. 42,
Chapter 4----Power System Technology . 97

sume a variety of rules of thumb or de facto

standards. Three of the most common reliabilityrelated goals are:

● loss of load probability (LOLP) of 1 day in 10

years,

● first (or second) contingency security, and

● reserve margins of 15 to 20 percent. (See box

4-A.)

These reliability standards specify the amount of

capacity to be installed (e.g., reserve margins and

LOLP), and how that capacity must be operated

(contingency security). Thus, they play a central role

in determining the constraints and capabilities of

modem power system operations and planning.

While these indices are all commonly used, there

are no uniform definitions of how they are calculated, in part due to the variety of conditions

important to different utilities. For example, in

calculating LOLP or reserve margins, a utility

relying heavily on power imports may include the

impact of transmission while other utilities do not.

The choice of standard to attain is a matter of

experience and engineering judgment as well as

system specific characteristics and is not uniform

across the country.8

Many parts of the country currently have higher

bulk system reliability than that prescribed by the

standards. The exceeded standards result from the

current surplus capacity planned and built to meet

high-load forecasts of the past two decades that did

not materialize.

Whether current standards could be strengthened

or weakened to the benefit of customers is speculative. Certainly, some customers may benefit from

reduced reliability if accompanied by reduced electric prices, just as others may prefer higher reliability

even with higher prices.

Operating and Planning Requirements

Given the performance standards for delivering

electricity, there are three general functions for

coordinated operating and planning, They reflect the

dynamic and complex nature of power systems and

their customers. The functions are:

1. following changing loads;

2. maintaining supply reliability; and

3. coordinating transactions of power.

In practice, operating and planning systems seek

to perform these functions at minimum cost. This

requires a tremendous amount of information, computing power, and communication capability, as

well as extensive coordination within and among the

various organizations involved.

Following Load

At each moment the supply of power must equal

the demand of consumers. However, demand

changes continuously and occasionally unpredictably. Some load patterns tend to repeat approximately with the time of day, day of week, and with

the season. Figure 4-3 shows a weekly pattern of

demand for a U.S. utility. The vagaries of weather,

economic conditions, consumer behavior, and in the

longer term, technological change all impede the

ability to forecast accurately. The continual and

sometimes unpredictable changes in demand require

coordination systems to be able to follow loads from

moment to moment (called regulation) and from

hour to hour (called ramping) as well as plan

supplies flexibly for the longer term.

A fundamental constraint in following loads

involves ensuring that generating units and transmission equipment operate within design tolerances.

For example, power system equipment used for

generation, transmission, and distribution has certain voltage requirements, much like consumer

equipment. Standards for power system voltages are

set by system engineers based on site-specific

equipment design and operating requirements. Some

power system equipment requires voltages within

fairly narrow tolerances to operate properly. Other

power system equipment particularly some transformers, are designed to function over a wide range of

voltages. Similar constraints apply to the ability of

transmission equipment to accommodate power

flows. The capabilities and constraints of power

system equipment are discussed in greater detail

later in this chapter.

%= ch. 6 for a discussion of standards in different regions.
98 ● Electric Power Wheeling and Dealing: Technological Considerations for Increasing Competition

Box 4-A—Three Common Reliability Standards

Loss of Load Probability (LOLP)

LOLP is a measure of the long-term expectation that a utility will be unable to meet customer demand. Many

utilities prescribe a standard LOLP of 1 day in 10 years. This means that given the uncertain failure of generation

and transmission equipment and variations in customer demands, engineering analyses predict that there will be a

bulk system outage for 1 day in a l0-year period.1 The LOLP specifies neither the duration of the outage (e.g.,

whether the outage lasts several seconds or an hour) nor the magnitude (whether the outage affects one distribution

substation or the entire system). Different utilities use different definitions of LOLP; there is no single consistent

method of calculating it.

Contingency Security Criteria

After a major system component such as a generator or transmission line has failed, the redistribution of power

flow on the remaining system will not automatically meet customer load. Even if sufficient generation is available,

voltages and thermal loadings on the transmission system may fall outside acceptable limits, or the system may be

unstable resulting in cascading failures. Utilities typically specify a reliability criterion of first (or second)

contingency security, meaning that sufficient reserves of transmission and generation are immediately available

such that the power system will continue to operate even if the one (or two) most critical components fail.2 This

is called the principle of n-1 (or n-2) operation, and applies at all times, even when some elements are already out

of service. For example, if three lines are out of service, the system’s operation must be adjusted so that it will be

able to stand the loss of a fourth line, Usually the critical components are the largest generators or transmission lines,

or some component at a critical location in the network. In general, contingency studies assume that no more than

one or two major failures will occur at a time (multiple failures are improbable unless there is some common cause).

Contingency studies rely upon engineering judgment to decide which types of failures are reasonable or credible,

since the large number of components makes enumerating all possible failure modes impractical.

Capacity or Reserve Margin

The reserve margin is the oldest and most traditional measure of reliability. Reserve margin is the difference

between generating capacity and peak load expressed as a percentage of peak load. Similarly, capacity margin is

the difference between capacity and peak load expressed as a percentage of capacity (rather than peak load ).3 Thus,

for example, a system with a peak load of 4,000 MW, and installed capacity of 5000 MW has margins of: Reserve

Margin = (5,000-4,000)+ 4,000= 0.25, or 25%; and Capacity Margin = (5,000-4,000)+ 5,000= 0.20, or 20%. The

numerator for both measures is the same, but the denominator for is capacity margin is smaller, so the capacity

margin is always smaller than reserve margins by a few percentage points. Capacity margin is the measure used by

the North American Electric Reliability Council, although in practice most utilities refer to their reserve margins.

Typically reserve margins of about 15 to 20 percent have been considered sufficient to allow for maintenance and

unscheduled outages (corresponding to capacity margins of approximately 13 to 17 percent).4 However, the amount

of reserve margin required depends on system specific factors such as the number and size of generating units and

their performance characteristics. For example, a system with a few large units will require higher reserves than a

system with many small units.5

IReca]] Ihat he bulk pwer SySLem klties ge~tlm and transmission but excludes distribution. T?uts, outages are expected to be mOre common man ~

LOLP sIandard indicales.

2N(fi Am~cm E[=~c Rellablll~ Cmll (NERC), Tr~sjer cq~;~ip Rejereflce f30cmcn/ (Princeton, NJ: 1980), pp. 6-7.

3Re=we m~gms ad capacity mag~ ~ ~~film]ly relal~ by [he equati~: capacity Margin = Rescme Mmgin + (1 + Reserve Margin).

4A. Kauf~ SMI K. Nelwn, Library of Congress, Congressional Research Serwm, “DO We Rcidly Need All Those Electric Plants?” August 1982.

5N~ ~acm Electric Reliability Council (NERC), Relmbthiy Concepr.s (Princemn, NJ: Fcbm~ 1985), p. 16.

Maintaining Supply Reliability any piece of equipment may fail, either on its own or

due to external influences (e.g., lightning strikes).

The cost and performance of generation and Preparing for continued operation after equipment

transmission equipment is variable and uncertain, as failure is called maintaining security. As defined by

are customer loads. From one moment to the next, the North American Electric Reliability Council
Chapter Power System Technology ● 9 9

Figure 4-3-Weekly Load Curve

Thousand megawatts

12

10

8

6

4

2

0

I

Inter mediate

Base

Sunday Monday Tuesday Wednesday Thursday Friday Saturday

SOURCE: Power Technologies, kc., “Technical Background and Consdarabons m ProDosed Increased Wheeling, Transmissmn Access

and Non UtJIIty Ganaratim,” contractor reporl prepared for the OMce of T~no@y Assessment, fich 1988, pp. 2-3.

(NERC), “security is the ability of the bulk power

electric system to withstand sudden disturbances

such as electric short circuits or unanticipated loss of

system components. ”9

Ensuring sufficient availability of supplies is

called maintaining adequacy. Again according to

NERC, “adequacy is the ability of the bulk power

electric system to supply the aggregate electric

power and energy requirements of the consumers at

all times, taking into account scheduled and unscheduled outages of system components."10 In

addition to unexpected failure, virtually all equipment requires some maintenance, and has operating

limitations that reduce availability. In the longer

term, the cost and availability of fuels is uncertain,

resulting in uncertain operating costs for generating

units. In the longer term still, construction cost and

schedules for new equipment are often uncertain, as

is the demand for power. Maintaining adequacy

involves addressing these cons

ties.

Coordinating Transactions

Nearly all utility systems are

tints and uncertaininterconnected with

other systems, allowing for a variety of transactions.

Transactions may take a variety of forms, including:

short-and long-term purchases and sales with neighboring systems; purchases from suppliers within a

utility’s service area (e.g., an independent power

producer); operation of jointly owned power plants;

and wheeling of power. *l .

gNO~ Amc.i~~ Electric Re]i~bi]i[y co~cil(~R(’), Re/~bill~ Concepu (~inceton, NJ: NERC, February 1985), p. 8.

l“lbid.

I IFor a comprehensive di~ussion of tie [y~s of in~~ti]ity u~~[ions u~, xc: EIwrw [formation &irninistration, ~nterlttiflty Bdk pOWer

Transuctiom, DOE/EIA-0418, Ocmtwr 1983.
100 ● Electric Power Wheeling and Dealing: Technological Considerations for Increasing Competition

Except where contrary arrangements are specifically made, it is the responsibility of each utility to

provide the power used by its customers without

absorbing power from its neighbors or sending

unwanted power to them. Through NERC, North

American utilities have set standards for controlling

inadvertent interchange.12

One requirement for inadvertent transactions is

based on “area control error” (ACE), a measure of

difference between the actual and scheduled interchange at any moment which also accounts for

power frequency deviations. NERC guidelines specify both that ACE must be zero at least once in each

10-minute period and must not average beyond a

specified level for any period. Controlling ACE and

inadvertent power transfers requires careful scheduling and control of transactions between the entities

as well as monitoring and recording the transactions

for billing or other compensation.

Implementing Coordinated

Operations and Planning

Performing the functions of following load, maintaining reliability, and coordinating transactions

12N~h ~encm Electric Reliability Council (NERC), Operating Manuul (Princeton, NJ: ~c. 1, 1987)

lsFor a more tW~lca] descrlpl]on, see ex~ple: Institute of Electrical and Electronics Engineers (IEEE) Commitlcc Report, “lhcription ~d

Bibliography of Major Economy-Security Functions, Parts 1,11, and Ill.” /EEE Transactions on Power Appararus and Systems, vol. PAS-1(M), No, 1,

JamlMy 1981, pp. 211-235.
Chapter 4--Power System Technology ● 101

involves executing several

and planning procedures. 13

coordinated operating

The procedures each focus on different time

horizons and different aspects of the power system

(see table 4-2). Some procedures such as coordinating the energy output of generating units to balance

demand are performed continuously. Others, such as

planning generation additions, are performed far less

often. The time horizon each procedure is concerned

with also varies widely. For example, controlling

energy input to a generator focuses on a time horizon

of under a minute, while long-term planning may

have a 20-year or more horizon reflecting the long

construction time and useful life of generation and

transmission equipment. Each time horizon beyond

a few seconds requires forecasts of customer demand and performance of system equipment.

Governor Control of Generators

for Load Following

At every moment, the power generated must

balance the amount demanded to maintain the 60 Hz

frequency required by both customers and the power

system. Frequency fluctuations result from an imbalance between the supply and demand for power

in a system. In any instant, if the total demand for

power exceeds total supply (e.g., when a generator

fails, or as demand increases through the course of

a day), the rotation of all generators slows down,

causing the power frequency to decrease. A similar

process occurs in reverse when generation exceeds

loads, with the governors reducing the energy input

to generators to maintain frequency.

Controlling frequency involves balancing the

supply and demand for power. Speed governors on

most generating units constantly monitor frequency

and regulate those units’ power output to help

balance demand and restore the frequency. The

constant change in a unit’s power output slightly

increases maintenance requirements, and slightly

decreases operating efficiency.

Power output from a generator does not change

instantaneously. The rate at which a generator’s

power output can increase or decrease, called the

ramp rate or response rate, depends on the type of

generator. That is, the usefulness of a particular

generator in regulating frequency varies from unit to

unit. Large steam generating units such as nuclear

power plants and large coal units generally change

output levels slowly, while gas turbines and hydro

units are very responsive. Table 4-3 shows typical

response rates for different types of generators. The

response rate is expressed in percent of rated

Table 4-2-Operation and Planning Functions

Function Purpose Procedures involved

Following load

Frequency regulation

Cycling

Maintaining reliability

Maintaining security

Maintaining adequacy

Coordinating transactions

Following moment-to-moment

load fluctuations

Following daily, weekly,

and seasonal cycles

(within equipment

voltage, power limits)

Preparing for unplanned

equipment failure

Acquiring adequate

supply resources

Purchasing, selling, and

Governor control

Automatic generation control (AGC)

and economic dispatch

AGC/economic dispatch

Unit commitment

Voltage control

Unit commitment (for

spinning and ready reserves

Security dispatch

Voltage control

Unit commitment

Maintenance scheduling

Planning capacity expansion

AGC/economic dispatch

wheeling power in Unit commitment

interconnected systems

SOURCE Adapted from F, Moboshwi, Southern Cahforma Edison, letter 10 Off- of Technology Assessment, May 13, 19S6.
102 • Electric Power Wheeling and Dealing: Technological Considerations for Increasing Competition

Table 4-3--Typical Generator Response Ratesa

Unit type and size Response rate

Steam units (all fuels)

10-50 MW . . . . . . . . . . . . . . 4.8% per minute

60-199 MW . . . . . . . . . . . . . 3.8% per minute

200 and over . . . . . . . . . . . . 2.80/. per minute

Hydroelectric

10-59 MW . . . . . . . . . . . . . . 1-6% per second

above 60 MW . . . . . . . . . . . 4-6% per second

Combustion Turbine

All Sizes . . . . . . . . . . . . . . . . 55% per minute

‘see “power Plant Response,” Institute of Electrical and El~”cs Engineers

Vbrking Oroup on Power Piant Response to lad Changea IEEE Paper TP 65-71,

1965; and Surwy of Cyclical load Caps4iKties of Fosdt Fkd Ganaratlng Units(Pab

Alto, CA: Electric Power Research Institute, 1979) EPRI-975.

SOURCE: Power Technologies, Inc., “Teohnolo@oal Considerations in Proposed

Scenarios for Increasing Competition in the Electric Utility Industry,”

contractor report prepared for the Oft&a of Technology Assessent, March

1988, pp. 2-16.

capacity per minute or per second at which output

can change.

The ramp rate of a generator reflects the maximum

rate at which the unit’s power output can change.

Given this upper limit, each generator’s governor is

set to specify how rapidly and to what extent the unit

actually will respond to frequency changes. Some,

but not all units need to be on governor control to

respond quickly. In fact, some units do not respond

at all, but instead are set to produce a fixed power

output. The amount of generation under governor

control required to follow load depends on expected

changes in load and on the ramp rates of the

available controlled generators. System engineering

analyses determine the amount of generation required to be under governor control. Setting the

generator governors is a function with a slightly

longer time horizon, discussed next.

Economic Dispatch and Automatic Generation

Control for Load Following, Reliability,

and Coordinating Transfers

Coordinated operation based on the incremental

costs of generation, called economic dispatch, is one

key to minimizing cost.14

The incremental production cost of a generating

unit is the additional cost per kilowatthour (kWh) of

generating an additional quantity of energy or the

cost reduction per kWh due to generating a lesser

quantity of energy. Incremental production costs

depend on the cost of fuel and the efficiency with

which the unit converts the fuel to electricity, and

any other operation costs that vary with the level of

power output. In economic dispatch, units with the

lowest incremental costs are used as much as

possible to meet customer demand. Typically, economic dispatch is entirely recomputed every 5 to 10

minutes.

Automatic computer control of generator output

is used to implement the dispatch of generators in a

control area. Automatic generation control (AGC)

systems calculate what increase or decrease in each

generating unit’s output is required to maintain the

balance between supply and demand in the least

costly way. Based on AGC calculations, generator

governors are reset to affect the change. An AGC

system constantly monitors the power system frequency to determine whether increased or decreased

output is required. The AGC system typically resets

generator governors every 5 to 10 seconds based on

an approximation of economic dispatch.

When governors balance supply with loads, high

incremental-cost units such as combustion turbines

may be used because they are able to change power

output rapidly. The AGC systems set the governors

on power plants so that power output from lowoperating cost generators increases to displace

output from more expensive generators that were

used to control frequency.

To perform its job, an economic dispatch and

AGC system needs cost and performance information about each of the power system’s operable

generating units. For example, the system must

know the range of power each generator can produce

(called the control range) and the ramp rate.

Typically, the efficiency with which fuel is converted to electricity, and hence the incremental cost,

depends on whether the plant is being operated at

full or part capacity. Control ranges, efficiency, and

incremental costs vary widely with the type of

generator, and sometimes on contractual requirements

for purchasing power.

I+jcc B.F. wollcn~rg ad AOJ. wood, Pwer ce~era~~~, OperurWn ad c~~r~~ (NCW York, NY: Jo~ Wiley & Sons, Inc., 1983); or A.S. ~k,

ModerrI Power System Control and Operarwn (Boston, MA: Kluwcr Academic Publishers, 1988).
Chapter Power System Technology ● 103

Minimizing total cost often involves one utility

purchasing electricity produced by another. Interutility transactions are sometimes very highly automated, as in the case of the Pennsylvania-New

Jersey-Maryland interconnected system, which is

one large control area with 11 member utilities

acting as a tight power pool. In other cases, the

process is less automated, carried out through

brokerage systems or by system operators using

telephones or small computer networks to exchange

sale and purchase information.

AGC systems control both the planned and

inadvertent power exchange between control areas.

Interutility transactions are implemented by increasing the generation of the selling utility and decreasing that of the buying utility. When inadvertent,

excessive, or insufficient exchanges occur, AGC

systems adjust the governors on generating units to

increase or decrease power output, correcting the

amount of power transferred. To properly control

interutility exchanges, AGC systems must have

information on the planned schedule of power

transfers and must constantly meter the actual power

flows for comparison.

In calculating which generating units to operate

and at what level, the dispatch system must also

consider the effects of the transmission system.

Dispatch systems commonly incorporate two principal effects. First, losses on the transmission lines

may be significant in systems with widespread

generation and loads. When this is the case, the

dispatch systems must consider the incremental cost

of transmission losses in addition to the incremental

operating cost of generation. Accurately calculating

incremental transmission losses is difficult and time

consuming. however. Losses increase disproportionately with increases in power transfers and

depend on the often indirect path of power flows.

Both features result in computational difficulty for

determining actual losses. However, some consideration of transmission losses is required. Typically, an

approximate mathematical model of the losses is

used.

The second transmission consideration relates to

adequacy and reliability. The capacity to transfer

power while remaining within voltage and load flow

limits is a constraint on economic dispatch. When

sufficient transmission is not available to deliver

power from the lowest cost generators to loads, other

generators must be operated. This is called operating

off-economy. The dispatch system then needs to

know not only the capacity of the transmission

system and the current use but also the amount of

capacity required for the transfer and the effect on

system voltages. Again, due to the computational

difficulties of calculating power flows, the dispatch

system relies on another portion of the energy

management system to determine the security (e.g.,

ability to withstand equipment failure) of the dispatch scheme chosen and override the economic

dispatch if needed. That is the function of security

constrained dispatch, discussed later.

Voltage Control for Load Following

The job performed by governors and AGC focuses on meeting frequency requirements economically as loads change. However, changing generation dispatch may also change voltages across the

system. Voltages must be kept within design tolerances for a power system to provide acceptable

service to customers. Maintaining voltage involves

balancing the supply and demand of power, although

in this case, it involves balancing reactive power

(called VARs) rather than real power (see box 4-B).

An imbalance in the supply and demand of VARs

causes voltage to rise or drop across the power

system. Understanding the pattern of voltages and

reactive power flows is a complicated problem

arising from the physics of electric systems.

Power system equipment creates the primary

demand for VARs. Long, heavily loaded transmission lines typically consume VARs, as do power

transformers and motors. One effect of reactive

power flows is that the use of distant low-cost

generating units may not be possible if sufficient

VAR supplies are not available despite otherwise

adequate transmission line capability.

Maintaining voltages to within the standards

required by system equipment is the function of

VAR control. Voltages at various locations are

telemetered to the energy control center from

various points in a power system and checked to

ensure they fall within the acceptable range. When

voltages begin to deviate from the acceptable range,

both automatic and remotely controlled actions are

taken using a variety of reactive power control

devices. Supervisory control and data acquisition
104 ● Electric Power Wheeling and Dealing: Technological Considerations for Increasing Competition

Box 4-B—Real and Reactive Power

Power is the product of voltage (electrical potential or pressure) times current (the number and velocity of

electrons flowing). In an AC system, both voltage and current vary sinusoidally over time with a frequency of 60

cycles per second (60 Hertz). However, the current and voltage are not necessarily in phase with each other. That

is, the current may reach its maximum slightly before or after the voltage does in each cycle. Active, or real power

results from current and voltage in phase with each other. Measured in watts, it is the power delivered to a load to

be transformed into heat, light, or physical motion. Reactive power results from that portion of current and voltage

which are not in phase. Measured in V’s (for Volt-Amps Reactive), it can be thought of as the flow of power stored

(but not consumed) by electric and magnetic fields around circuit components.

That current and voltage may be out of phase results from a phenomenon called reactance. ’ When a voltage

causes a current to begin flowing through a wire, a magnetic field forms around the wire opposing and delaying the

change in current. When the voltage is reduced, the collapsing magnetic field again opposes and delays the reduction

in current. The magnetic field may also induce or retard a current in nearby wires (e.g., other conductors in a

transmission line). The overall effect of the forming and collapsing magnetic fields in delaying changes in current

relative to voltage creates inductive reactance, or inductance. The larger the current, the larger the inductive effect.

Similarly, different voltages between circuit components (e.g., between conductors in a transmission line or

between a conductor and the ground) create electric fields. These forming and collapsing electric fields result in

capacitive reactance (or capacitance), in which current changes are advanced relative to voltage changes. The larger

the voltage, the huger the electric field and the capacitive effect.

Capacitance and inductance exist in any piece of electrical equipment. When capacitance and inductance are

balanced in a transmission line the voltage and current are in phase with each other. Then there is no net flow of

reactive power. When the inductive effect is greater than capacitive effect the current lags the voltage at any point

on the transmission line and the line is said to consume reactive power. Similarly, when the capacitive effect is

greater, the voltage lags the current and the line is said to produce reactive power.

A transmission line’s operating voltage is determined by the line design, and the capacitive effect is constant.

However, different real power flows on a line result from different currents, with fixed voltages. Thus, the inductive

effect, due to magnetic fields caused by current flowing, increases as the amount of power flow increases. For this

reason, low real power flows on a line may result in a high flow of produced reactive power. High active power flows

on a line may result in a high flow of consumed reactive power.

if&c~ma is me~~ of tie ive~~ to fl~~ &t~ining how much cufienl will flOW for a given vo]lage. The Otherpart of impedance is Cdkd ~f?~l~klme,

wh]ch caurs as the flowing electrons collide with atoms of memf in the conductors. Resistance is a form of electrical friction which cremes hea[.

SOURCE: office of Technology Assessmem, 1989.

systems combine telemetry of voltage to the control VAR output and off-economy dispatch are common

center and remote control of VAR supplies.

VARs may be supplied or consumed by generators either automatically or under the control of

system operators. Whereas real power output of a

generator is controlled by governors controlling the

energy input, reactive power is regulated by adjusting magnetic fields within the generators. As with

real power, reactive power output from a generator

is limited. Limits to reactive power output are due to

possible overheating within the generator resulting

from high levels of output. Control of generator

modes of voltage control on the bulk power system.

Other automatic and manual voltage control

devices include capacitors, shunt reactors, variable

transformers, and static VAR supplies. These devices may be installed at various locations in the

transmission, subtransmission, and distribution systems. Voltage problems resulting from VAR flows

are one major cause of transmission limitations.

Also, improved VAR control may help reduce

operating costs by reducing VAR flows. ’s

t~sclcnti~c Systems, [~., Optimization of Reactive VAR Sources in System Planning, EpRl EL-3729. Novem~r 19~.
Chapter G-Power System Technology ● 105

As a result, the use of these devices is likely to

increase over time. VAR-related transmission limits, and some approaches to reducing them are

discussed in the final section of this chapter,

Security Constrained Dispatch for Reliability

The combined control of real and VAR generation

output and other VAR sources may not result in

secure performance. Maintaining system reliability

is the job of security constrained dispatch of

generation.

The objective of security constrained dispatch is

to prevent the possibility of “cascading outages” in

which the failure of one or two generators or

transmission lines results in the overloading and

failure of other equipment. A key to security

constrained dispatch is scheduling generation in a

“defensive” mode so that the power system will

have enough supplies ready to continue operating

within emergency standards for frequency, voltage,

and transmission line loadings should contingencies

occur. In a sense, security constrained dispatch

accounts for reliability constraints on transfer capacity.

An important parameter of the defensive operating practice is that transmission capability must be

held in reserve for the possible occurrence of a major

failure in the system. Generating units are similarly

held in reserve. Idle generating units and transmission lines with below capacity power flows may

mistakenly seem to be surplus, when in fact they are

essential for reliability. This difference between

appearance and reality must be carefully noted in

changes to the power system.

The analytical methods used are based on load

flow calculations of real and reactive power flows in

the power system. Control center operators typically

examine a series of contingency cases to determine

the most severe contingency and the resulting power

transfer limit. When that limit is lower than present

transfers, the economic dispatch is recalculated to

reduce the transfer to acceptable levels and implemented by the AGC and Supervisory Control and

Data Acquisition (SCADA) systems. By dispatching

generating units “off-economy,” security constraints

result in higher operating costs.

Power flow and contingency analyses needed for

security constrained dispatch are time-consuming

and computationally difficult. Complex systems

with many generating sources, transmission components, and loads have complicated flow patterns,

resulting in a large number of contingencies to be

examined. Because of the computational difficulties, security constrained dispatch often relies on

planning and analysis to determine transfer capabilities and constraints. The result is an approximation

of actual security constraints. Utilities are increasingly developing automatic energy management

systems by combining the data acquisition capabilities of SCADA systems with load flow and other

analytical tools needed to evaluate security in real

time. 16

Unit Commitment for Load Following,

Reliability, and Coordinating Transactions

Generating units typically need to warmup before

operating (unlike transmission lines). To be ready

for operation, generators must not only be warmed

up, but must also be rotating in synchronism with the

60 Hz of the power system. This requires utilities to

establish a unit commitment plan. Unit commitment

plans seek to ensure a sufficient supply of generation

for immediate operation in case of contingencies

such as failure of a generating unit or transmission

line. Also, the plan ensures that sufficient generation

under governor control is available for regulating

frequency in response to changing loads. Such

generation which is synchronized and ready to serve

additional demand is called spinning reserves.

Unit commitment plans also specify which units

will be warmed up and cooled down to follow the

cycle of loads over the course of a day, week, or

season. Utilities calculate unit commitment schedules which minimize the total expected costs of

operation and spinning reserves required to maintain

reliability and meet expected changes in demand.

Often, utilities also schedule power purchases from

other utilities. New unit commitment plans are

typically established each day or after major plant

outages or unexpected load changes.

Unit commitment planning requires a vast amount

of information. Virtually all the information about

generation and transmission operating cost and

16’’scAD~Ms Mmket still Vibrant, ” Elecrricul WOr&i, vol. 201, No. 10, November 1987, p. 36.
106 . Electric Power Wheeling and Dealing: Technological Considerations for Increasing Competition

availability required by the dispatch and security

systems is also needed to develop the best unit

commitment schedule. In addition, the time and cost

to warm up generating units and the availability of

personnel to operate generating units must be

considered. These factors vary depending on the

type of generating unit. Unit commitment schedules

are typically developed using computers to perform

the numerous calculations for identifying the minimum expected total costs.

Scheduling Unit Maintenance for Reliability and

Coordinating Transactions

Scheduling maintenance is similar to unit commitment, although with a somewhat longer time

frame. The objective is to schedule needed generation and transmission equipment maintenance to

meet reliability goals and minimize the expected

cost of operation. Maintenance scheduling requires

information about each piece of equipment’s need

for maintenance, and the expected customer demand. Maintenance schedules may be established

annually or following unexpected equipment outages.

System Emergency Operations and Restoring

Power for Reliability Emergencies

System emergencies occur when there simply is

not enough capacity available either within the

utility or through neighboring systems to meet load.

When voltages and frequencies deviate too much as

a result, relays and circuit breakers may isolate

overloaded generators and transmission components

from the system, exacerbating the imbalance between supply and demand. Emergency operations

involve avoiding cascading outages by reducing the

power delivered to consumers. In the extreme, this

requires disconnecting customers from the system.

Plans for load shedding must be coordinated with the

automatic isolation of generating units that occurs

under abnormal frequency and voltage conditions.

Restoring power also requires coordination of the

system components and the devices used to isolate

the loads. Following system failures, restoration

requires that some generating units be capable of

starting on their own, called “black-start capability, ” Not all generators have this capability, typically taking their starting power from the system.

Planning Generation and Transmission Capacity

System planning has the long-term focus of

adding adequate generation and transmission capacity to meet changing demands reliably and at low

cost. Planning begins with forecasting both the

changing patterns of demands on the system, as well

as the costs of alternate fuels and resources. Based

on these forecasts, planners implement generation

expansion plans to meet those changing conditions.

Plans for new transmission facilities must reflect

both the changes in demands and in generation.

Planning new generation and transmission facilities

is typically a utility responsibility, often performed

with considerable regulatory oversight. Also, because of the interconnected nature of utilities, plans

are also usually coordinated with power pool and

NERC region review to assure reliability.

Uncertainty in forecasting presents acute problems for planning, in which time horizons of 2 to 30

years reflect the construction and operating lives of

new generation and transmission facilities. In recent

decades, forecasts of long-term load growth have

often been highly inaccurate. In addition to uncertainty over long-term trends, load forecasting is

complicated by the effects of unpredictable (but

inevitable) variations in weather and economic

cycles from year to year. Similarly, the significant

uncertainty and swings in fuel prices make operating

costs highly uncertain. The result of this uncertainty

is a mix of facilities which may not ideally meet

existing conditions (e.g., with surplus or deficit

generating capacity). At any time, the existing mix

of generation and transmission capacity reflects

previous expectations of fuel prices, construction

schedules, and customer demand which may be

quite different from actual outcomes.

Generation expansion planners have many supply

technologies to choose from, with a wide range of

cost and performance characteristics. Typically,

generating units with relatively low operating costs

(e.g., nuclear, coal, hydroelectric) have been relatively expensive to build and have had long construction periods. Generating units that are relatively

quick and inexpensive to build (e.g., gas-or oil-fired

combustion turbines) have had relatively high operating costs. Because of uncertain fuel price and

availability, planners often seek a diverse mix of

generating technologies.
Chapter 4--Power System Technology ● 107

The growing interest in conservation and load

management technologies, together called demand

side management (DSM), has added further options

to expansion planners. DSM has an even wider

variety of performance and cost characteristics.

Increasingly, system planners must also consider

nonutility generation in transmission and generation

planning. Numerous computer-based analytic tools

have been developed to aid planners in evaluating

the financial and economic impacts of different

capacity expansion plans under a variety of demand

and economic scenarios.

Choice of generation types is often broken into

base-load, intermediate, and peaking reflecting the

time-varying patterns of demand (figure 4-3). Plants

chosen for base-load operation typically have relatively high construction costs justified by low

operating costs. Because of the limited hours they’re

expected to operate, generating units with low

capital cost are chosen for peaking duty, even though

they may have higher fuel and operating costs.

The varied operating and cost characteristics of

different generation technologies give each advantages and disadvantages for use in a power

system. System planning must ensure adequate

controllable generation for regulating both frequency (by controlling the output of active power)

and voltage (by controlling the output of reactive

power). The costs and ability to operate as spinning

reserves and to warm up or cool down under unit

commitment plans are also critical. Table 4-4

summarizes some of the key characteristics considered in planning of both existing and prospective

generation facilities.

Transmission system expansion must be adequate

to accommodate generating unit additions as well as

the changing patterns of loads. Siting of power

plants is integrally related to transmission requirements, and costs and capabilities need to be considered together. Depending on the location of a new

generating unit relative to the existing transmission

system, new transmission may or may not be

required. Transmission additions may also be

needed to increase transfer capability to neighboring

utilities. The appropriate level of interutility transfer

capability depends on the opportunities such as

exchanging reserve generating capacity and obtaining lower-cost energy and capacity .17

A variety of engineering-analytical tools are used

to determine the type of transmission additions

needed, and the overall impact on the existing

system. These tools help planners examine such

factors as:

. the effects on real and reactive power flows,

. the resulting transmission losses,

● the need for voltage and reactive power control

devices on the system, and

. the transient stability and contingency security

of and the impacts on system reliability.

Table 4-5 summarizes some of the key characteristics of both existing and prospective transmission

facilities which are considered in planning,

INCREASING TRANSMISSION

CAPABILITY

Transmission systems have a variety of uses such

as:

● delivering power from a utility’s supplies to its

customers,

. providing for interutility exchanges of economy energy, firm capacity and shared reserve

capacity,

. integrating nonutility generation, and

. wheeling power.

In integrated power systems, performing these

functions involves moving power from a large

number of generators to a large number of loads

along a network of transmission lines. At times,

transmission constraints occur which limit the ability to move power from one location to another. This

section describes the constraints on a system’s

transmission capability and some of the technologies available to ease those constraints,

Limits to Transfer Capability

Basic physical principles largely determine the

transmission capability of a power system. A few

fundamental factors underlie the physical limitations to transfer capacity of power systems. The

limitations may be due to either the abilities of

17 For ~ dlwu~~ion of ~jmnlng intemtility ~mission SYs[cms, s~ Pub]ic Semice E]cc~ic & G~ CO., An ApprO~h for Determining Tran@er

Capubiliry Objectives, Electric Power Research Institute, EPRI EL-3425, March 1984.
108 ● Electric Power Wheeling and Dealing: Technological Considerations for Increasing Competition

individual components, or to the requirements and

challenges of operating the overall system. Individual transmission line components have specific

voltage requirements and limited current-carrying or

thermal capability, either of which may constrain

their use. System-related constraints involve the

complex interactions between individual generators,

transmission circuits and their control system, and

the needs for maintaining adequate reliability. Table

4-6 summarizes the constraints on power transfers.

Physical laws alone do not dictate the absolute

amount of transfer possible. Rather, they indicate a

trade-off between level of transfers and reliability.

There is no simple power network equivalent of the

telephone company’s busy signal. For example,

higher transfers decrease transmission reserves,

increasing the possibility of an outage occurring. As

a result, transfer capability depends on both physical

characteristics and the reliability standards and

procedures used. (Recall that reliability criteria are

somewhat subjective and not set on a quantitatively

derived balance between the utility’s costs of

providing reliability and the consumers’ benefits of

uninterrupted service.)

Determining transfer capability and opportunities

for improvements can be a challenging matter of

balancing economics, reliability, engineering, and

policy, Developing meaningful estimates of transmission capability requires considerable engineering

expertise, data, and analytic tools. This challenge

arises because capability is not merely the rating of

a single line or a few lines. Rather, transmission

capability is a function of the strength of the system

as a whole, including not only the transmission lines

but the generating units as well. For example,

spinning reserves of generation located near loads

may reduce the amount of transmission capacity

from distant generators which must be held in

reserve to maintain reliability.

Transmission capability also varies over time,

further complicating any assessment of the adequacy, limitations or opportunities for expanding

capabilities. It varies as switching operations occur

and as demand, generation, and transmission patterns change. Fluctuating patterns of demand, changing availability of generators and transmission lines,

even weather, all affect capability.

In some cases, there may be a single binding

constraint that would produce a large increase in

capability if it could be relieved. More often there

are multiple constraints on a single transmission

line, or constraints on many lines at the same time so

that reliving a single constraint would make practically no difference. For example, in the PJM

system, west to east transfers are limited by voltagerelated factors 85 percent of the time and thermal

limits for the remainder.l8

Although this section discusses physical constraints, there are also institutional constraints on

power transmission. Even with sufficient physical

capability, some economically advantageous transfers may not take place. For example, lack of

regulatory approval, lack of intercompany agreements or contractual basis, or simply lack of

knowledge of economic opportunities may all prove

real and significant impediments to full use of

transmission capacity.

Constraints on Individual Components

Power is transmitted when the line voltage causes

current to flow in the conductors. The amount of

power an individual line carries is proportional to the

product of the current and the voltage. However,

every transmission line is limited in the amount of

power it can transmit by constraints on voltage and

current. Flows of reactive power limit both the

voltage and current capacity.

Thermal/Current Constraints

Current flowing causes conductors to heat up. The

amount of heat individual components can tolerate

limits the amount of power than can be transmitted.

Heating causes the metal conductors to expand and

sag. The resulting reduced clearance from the

conductor to the ground, towers, and other conductors exacerbates flashover constraints. Excessive

heating may also result in a permanent stretching

and lead to brittleness and a shorter lifespan.

Substation equipment is also subject to thermal

limitations. Excessive heat can destroy the materials

used in transformers and other terminal equipment.

A thermally overloaded component may reach its

critical temperature within seconds, minutes, or

hours, depending on its previous temperature, its

lscas~,za, %hullz & Ass~iates, Inc., Case Studies on Increasing Transmission Access, OTA contractor report, March 1988, p. VA.
Chapter 4--Power System Technology ● 109

Table 4-4-Key Physical Characteristics

of Generating Plants

Table 4-6-Transmission Capability Constraints

Operating cost

Fuel type and cost

Efficiency

Control ranges

Real power

Reactive power

Startup costs

Ramp rates

Fuel availability

Expected equipment failure-availability

Maintenance requirements and costs

Environmental impacts and emission requirements

Site availability

Location relative to transmission and loads

Construction cost and lead time

Lifetime

SOURCE: Offti of T-1ogy As~ssment, 1889

Table 4-&Key Transmission

Planning Characteristics

Location and capacity of individual lines

Equipment voltage requirements

Capability of VAR support equipment

Transmission losses

Equipment failure rates

Maintenance requirements

Environmental impacts

Rights-of-way and substation site availability

Construction cost

Construction lead time

Lifetime

SOURCE: Office of Technology Assessment, 1989,

physical characteristics, amount of overload, and

weather. Therefore it may be able to carry a heavy

current for a short time, a lesser current for a longer

time, and a still lesser one indefinitely. The latter

current is the component’s “normal” rating, applicable to normal operation. “Emergency” ratings are

currents that can be carried for shorter times on the

assumption that the loadings can be relieved by

changes in generation dispatch or reductions in loads

within the assigned time period.

Thermal ratings are usually established for loadings occurring for different periods of time-10

minutes, 30 minutes, 4 hours, etc. The ratings are

typically based on current flows rather than the

actual temperatures of transmission line equipment.

The actual temperature depends not only on current,

Physical constraints

Individual line constraints

Thermal/current constraints

Conductor sagging, equipment lifetime

Voltage constraints

Flashover, corona, and terminal equipment requirements

Reactive power flow and voltage

System operating constraints

Distribution of power flows (parallel path and loop flows)

Contingency security

Stability (steady-state and transient)

Institutional constraints

Interutility agreements

Regulatory approval

SOURCE: Office of Technology Assessment, 1988.

but on ambient weather conditions including temperature, wind speed, and icing. Identical components may have different ratings due to such factors

as the expected ambient weather conditions and the

reduction in equipment life considered acceptable

by the utility.

Voltage Constraints

The design of a transmission line specifies the

minimum and maximum operating voltages. Voltages exceeding the maximum may cause electricity

to flashover (i.e., arc between a conductor and the

ground or the tower), rather than travel along the

line. High voltages may also cause corona discharge

(i.e., ionized air molecules surrounding the line

resulting from high electric fields), creating noise

and radio interference. The maximum voltage allowable on a line depends on its height, spacing of the

conductors and insulators, and weather (e.g., corona

is exacerbated by high humidity, rain, or snow).

Excessive voltages may also destroy transformers

and other terminal and substation equipment by

breaking down their insulation.

Reactive Power Flows and Voltage

As discussed earlier, reactive power flows may

cause voltage to rise or drop significantly along

transmission lines, particularly long ones. With low

real power flows on a transmission line, capacitive

reactance may create high voltages along the line,

exacerbating high voltage constraints.
Similarly, increasing the real power flow on a

line also increases the line’s demand for reactive

power. As the flow of reactive power increases, the

voltage along the line drops significantly. If as a

result of reactive power flows, voltages fall below

the design minimum, transformers will not function

and either power cannot be transferred or the voltage

of power delivered to customers will be outside the

allowable range. Thus, the ability of generators and

other VAR control devices to supply reactive power

limits the amount of real power which can be

transferred. Since the amount of reactive power

required by a transmission line increases with line

length, reactive power problems typically affect

long lines.

System Operating Constraints

Parallel Path Flow: Distribution of Power

The flow of power in a transmission network is

dictated by the laws of physics. One of the key laws

is that power may flow on all available paths

between the generator and the load. This is called

parallel path flow (which is a slight misnomer, since

the lines are not necessarily parallel).

Generally, the amount of power flowing on any

path of a network is inversely proportional to that

path’s impedance. The impedance may bethought of

as an “electrical length,” which depends on both the

actual length and the voltage of the path. (One mile
Chapter Power System Technology ● 111

of 500-kV line has approximately one-fifth the

impedance of a mile of 230-kV line.) Also, a path’s

impedance to power flow does not necessarily

reflect the transfer capacity of that path.

The distribution of power flows and the inability

to control the flows has two important implications

for determining transmission system capability.

First, the transmission capacity of a network is not

the sum of the power that could be carried on each

line alone. Rather, the capacity is constrained by the

weakest link. The amount of power that can be

transferred from one area to another by a transmission system is the smallest power transfer at which

one of the components reaches a thermal or voltage

limit. (See box 4-C.)

Second, the capability of transferring power from

any generator to any loud on the system depends on

the other transfers occurring simultaneously. The

power flow from a generator to a load divides onto

each pathway to some extent. Even indirect or

distant lines may receive some of the flow and thus

have part of their capacity used up. As a result, the

capacity remaining for additional transfers between

other generators and loads depends on the other

transfers since they essentially share the same

transmission paths.

Parallel path flows and resulting transmission

problems can occur both within a single utility and

between interconnected utilities exchanging power.

Parallel path flows crossing the boundaries of

utilities along paths not contracted for, or scheduled,

are called loop flows. (See box 4-D.) In interconnected systems, such as those in the United States,

loop flows are common.

System Stability

In an electrical generating network all generators

rotate in unison, or synchronism, at the system

frequency of 60 Hz. The ability to maintain synchronism is called stability. Transmission capability may

be limited by instability. Normally, a disturbance

increasing or decreasing the speed of one generator

will cause small changes in the unit’s power output,

tending to bring that generator back to the common

speed of the system. Instability is a condition in

which this stabilizing process does not occur, and

some generators speed up with respect to others,

possibly causing the system to fall apart.

Two types of stability can be classified according

to the magnitude of the disturbance: steady state and

transient. 19 steady state stability refers to the ability

of the system to withstand small changes in loads.

Transient stability refers to the ability to withstand

large disturbances, such as the failure of a transmission line or generating unit. System engineers use

complex computer programs representing the generators, controls, loads, and the network itself to

examine which operating conditions (e.g., power

flows on the transmission system) are stable and

which are not.

Contingency Security

A major disturbance such as the failure of a

generating unit or transmission component causes

changes in real and reactive power flows and

voltages around the system. As discussed earlier, the

n-1 contingency security standard for reliability

requires that a system continue functioning without

cascading failures caused by thermal overloads, or

excessive voltage drops or sags, or instability if any

single component should fail without notice. Voltage control devices and generating units are set to

respond to a contingency to restore the frequency,

voltages, and power flows to acceptable levels.

Because of the possibility of a major disturbance, the

transmission system’s capability of carrying power

is limited not only by the actual flows but by the

flows that would exist if a given contingency should

occur. (See box 4-C.)

The standard approach to avoid such cascading

failures is to operate in a defensive or preventive

mode. In this mode, generation is dispatched and

flows are maintained so that sufficient generation

and transmission capacity is held in reserve to ensure

that the resulting redistribution of power would

remain within emergency ratings following the most

severe single contingency.

While the defensive mode is essential for reliability, it may require operating more costly generating units when lower cost units are available.

There is an alternative to defensive scheduling of

generation and transmission, that of developing

IgInstitute of Electrical and Electronics Engineers (IEEE) Committm RcPofl, ‘‘Proposed llxms and Definitions for Power System Stability, ” IEEE

Transactions on Power Systems, vol. PAS-101, No. 7, February 1986.
112 ● Electric Power Wheeling and Dealing: Technological Considerations for Increasing Competition

Box 4-C—Example of Transmission Constraints

The transmission capability between two points in a system may be limited by individual component

constraints or by network constraints. Individual line constraints may be exacerbated by parallel path flows in the

network. This highly simplified example shows some of the different constraints and their impact on overall

transmission capability.

Component Constraints

Consider the very simple transmission network illustrated in figure 4-4. Three parallel transmission lines

connecting a generator to a load. Each line has a capacity of 100 MW, above which it is constrained both thermally

and by voltage. That is, increasing power flows above 100 MW by increasing current would cause overheating and

sagging of the line. It would also increase reactive power demand, reducing the voltage at the receiving end below

acceptable levels. Increasing power flows by increasing voltage would cause flashovers, corona discharge, or

possibly destroy terminal equipment, If all three lines could be fully utilized, the system would have the ability to

transfer 300 MW.

Parallel Path Flows

Because of different path lengths, the power transmitted may divide unequally on the three lines. Assume that

the division is in the ratios of 10:9:8. Because of the uneven division, when Line A carries its rated power of 100

MW, Lines B and C carry only 90 and 80 MW respectively. Any attempt to transmit more power would increase

the loading on all three lines and overload Line A. Thus, due to the impact of parallel path flows, the total capacity

is only 270 MW.

Contingency Security Constraints

Using the defensive mode to meet the “n-1” contingency security requirement reduces the transmission limit

even more. If Line B were to suddenly fail, perhaps after a lightning strike, Lines A and C would receive the

additional flow and be loaded to 150 MW and 120 MW respectively. To prevent the possibility of an overload, the

allowable power transfer is only 180 MW. Then the normal loadings are limited to only 67, 60, and 53 MW

respectively, and the emergency loadings do not exceed the rating of 100 MW. The three 1OO-MW lines form a

system capable of safely carrying only 180 MW, or 60 percent of their total individual ratings.

Transient stability studies of this system may indicate that the two generators will lose synchronous operation

after a disturbance such as the line loss, even though no individual components are overloaded. That is, one

generator may slow down while the other accelerates, as both respond to the new voltages and power flows. If this

is the case, stability concerns may require further limiting transfers.

SOURCE: Office of Tdmology Assessment, adapted from Casazza-Schulw & Assw]atcs, Inc., Case Studies on /ncrea.iing Transtniss/on Access, OTA contractor

report, March 1988.

special protection systems for responding rapidly

enough to prevent cascading failures after a disturbance occurs. Such a mode of action is referred to

as corrective or remedial action. Remedial action

might involve measures including tripping (or rapidly disconnecting) a remote generator while rapidly

increasing the output of a nearby generator when a

specific contingency occurs. It is typically used

when the preventive mode of operation would entail

a heavy economic penalty.

According to the North American Electric Reliability Council (NERC), corrective action systems are

being considered more frequently as an alternative to

defensive generation scheduling.20 NERC notes that

widespread application of these more complex

schemes may affect future power system reliability

since system security becomes dependent upon the

correct functioning of these special protective systems. To provide the same reliability as the defensive mode, special protection schemes must either be

highly reliable or have built-in redundancy.

In practice, limits caused by contingency security

are challenging to analyze. Circuit configurations

are far more complex than the example of box 4-C,

zONo~ Amefi~~ Electric Rcliabili~ Comcil, 1987 ReliabiliO AssessmenbThe Future of Bulk Electric System Reliability in North America,

)987-/996 (Princeion, NJ: October 1987).
Chapter 4--Power System Technology ● 113

Gen

Figure 4-4-Transmission System

t - o

Gen

A

1 0 0

9 0 >

B

Load

c

80 270 MW

(a)

All lines in service.

System loaded without considering contingencies.

Gen

Line A at rated loading.

A 6 7

B 6 0

Gen

Load

180 MW

Limitations (all lines rate 100 MW)

Gen

B

c

120 >

Gen

Load

270 MW

(b)

Outage of Line B

System loaded without considering contingencies.

Lines A and C overloaded.

Gen

A

100

B

Load

c

80 180 MW

(c)

All lines in.

System loaded to “n-1 contingency limit”

SOURCE Casazza, Schultz & Associates, Inc., Casa Studies on Increasing Trarrsomwon Access, OTA contractor report, March 1988.

(d)

Outage of Line B

System was loaded to “n-1 contingency limit” before

Line B tripped.

Line A at limit. No overloads.

and the redistribution of power flows after some

equipment failure is complicated. Also, both real

and reactive power flows and their impact on voltage

and thermal limits must be considered. Moreover,

following a disturbance, the transition to the new

equilibrium state is not instantaneous. Rather, the

change occurs over time as generating units and

voltage control devices react and interact with each

other. Thus, stability analyses must examine not

only whether the new state following a disturbance

is stable, but also whether transition to a new stable

state will occur.

Prospects for Increasing Capability

Assuming that an increase in transmission capability is desired, what can be done? There are

possibilities for mitigating all types of constraints.

Options for upgrading both the transmission system

and generators may be useful. Options include:

1, increasing the thermal or voltage capacity of

an individual existing line,

2. improving the control of reactive power and

voltages on a network,
114 ● Electric Power Wheeling and Dealing: Technological Considerations for Increasing Competition

Box 4-D--Loop Flows in the Western

System Coordinating Council (WSCC)

Loop flows, the unscheduled use of another

utility’s transmission resulting from parallel path

flows, is common in the WSCC as in other parts of

the United States. The WSCC transmission system

has the general shape of an elongated doughnut

including a western section of lines joining Oregon

and California; an eastern section running generally

from Montana to Arizona; a section in the Northwest; and a section from southern California to

Arizona. Figure 4-5 shows a simplified view of the

WSCC doughnut.

Because of the shape of the transmission system

and the physical laws of electricity, whenever

power is sent from one part of the doughnut to

another, the flow is split two ways; some goes

clockwise, and some counterclockwise. For example, if 1,000 MW of power is sent from the

Montana-Wyoming area to the Pacific Northwest,

only 580 MW of this power flows along the

relatively direct counter-clockwise path, as seen in

the figure below; the remaining 420 MW flows

clockwise through California and north through the

western lines. The flows due to simultaneous

transactions carried on at the time are superimposed

on each other depending on their amount and

direction. For example, a sale from the Northwest

to California would reduce or reverse the flow

between the Northwest and Montana-Wyoming,

and increase the flow from Montana-Wyoming to

California on the eastern lines.

If the transaction from Montana-Wyoming to the

Northwest used a scheduled or contract path

directly joining the two areas and not including

California, the 420 MW flow not using that path is

a clockwise loop flow. WSCC has pursued use of

flow control devices called phase shifting transformers to reduce loop flows.

SOURCE: Casazza-Schultz & Associates, Inc., Cuse Wdies CM /ncreasing Trunstnission Access, OTA contractor report, March

1988.

3. improving the control of real power flows on

a network,

4. decreasing the response time of generators and

transmission line switching, and

5. adding new lines.

Figure 4-5--Western Interconnected System

L

ng

Denver

Are a

I

Colorado

 .

N eW

Mexico

SOURCE: Casazza+chultz & Assooiakm, Inc., Caw ShJdaIS on lncraas@ Trwmnrission Acwss, OTA contractor report March 1988.

Table 4-7 shows how these options relate to the

types of system limitations.

The costs of increasing transmission capability

are site-specific, depending on a host of factors such

as terrain, system configuration, type and age of

equipment being upgraded, etc. Often, a transmission line or generator being upgraded must be

temporarily taken out of service. Lost use of the

equipment creates a highly site-specific cost, particularly significant in cases where a line being

upgraded is in heavy use. As a result, generalizing

about cost and performance is difficult.

Meaningful estimates of the benefits of options to

increase transfer capability are even more difficult to

develop. There are several reasons. First, most

changes will affect not only transfer capability but

the system operating economics and system reliability as well. Developing a meaningful combined

measure of performance that trades off between

these factors has proven elusive. Second, the impact

of any measure of system transfer capability, operating economics, and reliability is highly site-specific.

The impact of a new transmission circuit in a remote

part of Nevada and an identical circuit parallel to an
Chapter 4--Power System Technology ● 115

Table 4-7-Technologies To Increase

Transfer Capability

Remedies to individual line constraints

Voltage uprating

Tower extensions

Upgrading insulators

Upgrading terminal equipment

(circuit breakers, relays, transformers)

Current uprating

Dynamic conductor rating

Sag assessment and monitoring

Restringing (live-line restringing)

Changing operating standards

Tower design and new lines

Conversion to multiple circuit towers

High-voltage direct current lines

Remedies to steady state system operating constraints

Control of load division

Phase angle regulators

Series reactance and capacitance

System reconfiguration

HVDC control features

Redispatch of generation

Reactive power management techniques

Shunt or series capacitors

Shunt reactors

Static VAR compensators

Synchronous condensers

Generators as VAR sources

Remedies to contingency security and stability constraints

/reproving generation response controls

Generator tripping and fast runback

Fast valving

Braking resistors and load switching

Advanced excitation systems and stabilizers

Transient excitation boost

Improving transmission response controls

High-speed reclosing and reducing clearing time

Rapid adjustment of network impedance

Fast acting phase angle regulators

Sectionalizing (adding switching stations)

SOURCE: Adapted horn Po~r Technol@es, “Technical B.w@mJ nd and cOn*ratIons In Proc+Osed Whaellm, Transmission Aocess, ti NofI-UfIIIty Generation, ‘ mntrktor report p@rd for the Office of Tec+Inolcgy Assessment,

March 1988, p. 6-2.

existing line in the Northeast are considerably

different. Also, the impacts vary over time, as loads

change, and as available resources and their costs

change.

The following is a summary of some of the

approaches to increasing transfer capability. For a

more comprehensive, technical description of solutions to increased transfer capability the reader is

referred to Technical Limits to Transmission System

Operation, published by the Electric Power Research Institute.21

Increasing the Capacity

of an Existing Line

Increasing Voltage

Since the acceptable voltage range for operation

of transmission circuits without flashovers is determined primarily by the line’s equipment and design,

the opportunities are limited to changing equipment.

Transmission towers can be extended and insulators

upgraded to increase the spacing between the

conductors, towers, and ground. Terminal equipment such as switches, circuit breakers, meters, and

transformers will also need to be upgraded to the

higher voltage ratings.

Increasing Current Ratings

One method to uprate the current carrying capacity of a line is to simply increase the allowed

temperature rise, and thereby increase the amount of

current flow allowed. This method has a very low

initial cost. However, there may be some reduction

in equipment lifetime.22

A related technique is to use dynamic line ratings.

Normally, a line’s current ratings are based on

imprecise and conservatively forecast estimates of

ambient weather conditions. Using dynamic line

rating, the actual ambient weather and the temperature and sag of the conductor are measured,

permitting the line to operate closer to its physical

limits on cool or windy days. Dynamic line rating

adds some increased operational complexity and

increases the variability of transfer capability over

time.

Resagging a line to raise it higher off the ground

may also allow increased current flows if the line is

constrained by excessive sagging. This has been

done in some cases while the line is still in service.

Another option is restringing-installing a larger

conductor with higher current ratings. This may

21power TW~~iogie~, ]nc,, Tec~ical Li~”ts t. Tra~~’ssion ,~ystem ~peration, EPR1 EL-5859, June 1981?.

~~lEEE Standard for Calculation of Bare Overhead Conductor Tcmperaturc and Arnpacity Under Steady-State Condinom. ANSi/’iEEE Standard

738-1986, 1986.
116 ● Electric Power Wheeling and Dealing: Technological Considerations for Increasing Competition

require reinforcement of the existing towers but

costs considerably less than adding a new line.

Tower and Circuit Reconfiguration

Voltage and/or current limits may also be extended by more extensive changes in line circuit and

tower design. If tower strength permits, a single wire

line may be replaced by a bundle of two to four

wires, raising both thermal and corona limits. In

addition to restringing circuits already in place, it

may be possible to string another separate circuit,

Original towers may already have space for new

circuits in anticipation of future need. A new

possibility under investigation is either to restring an

old AC line as a new HVDC line, or to add a new

HVDC circuit in combination with an existing AC

circuit as space permits.

Controlling Real Power Flows

As explained above, network transfer capability is

limited by the most constrained line in the system,

so any method which can control or alter flow in the

network may have major benefits. There are number

of methods which can be used to control network

flow, but this is done by changing the network

characteristics in different places, rather than by

changing the rules of network flow.

The first and foremost technique for controlling

network flow is off-economic dispatch of generating

units. By generating power at particular network

locations, rather than in economic order, network

flow can be kept with reliability and capacity limits.

A second practical, inexpensive, and common

method is to alter the network itself by disconnecting

one end of a constraining (typically lower voltage)

line. The line then carries only the customer load it

serves. This method may also be used on one of two

parallel lines under low load conditions, so that

increased loading on the remaining line is better

matched to the VAR compensation present. In both

cases, the benefit is purchased at the cost of lower

reliability, as fewer paths between generation and

loads remain.

Phase shifting transformers (also called phase

angle regulators) change the phase angle between

input and output by advancing or retarding the

relative time at which the input and output sine wave

voltage peaks occur. By doing so these devices act

as a valve which can increase or decrease the flow of

power on a line. Phase shifting transformers have not

been widely used due to past problems with reliability. They also have the undesirable side effects of

increasing reactive power losses. There is some hope

that future developments in high-power electronics

will produce devices that can be used with phase

shifting transformers to control individual line flow

(discussed below).

A technique called Rapid Adjustment of Network

Impedance (RANI) can be used to continuously vary

VAR compensation to maximize power flow on a

single line. It can also be used to vary the impedances on one or more lines in such away as to control

power flow on the network. Because this control is

achieved by varying line impedance, there is the

possibility that it will be paid for in increased line

losses. The cost of such line losses must be balanced

against improved reliability, reduced need for new

power lines, and other benefits.23

High-voltage direct current (HVDC) power lines

are used for high-power, long distance lines and as

asynchronous connections between the three main

interconnected regions of the United States.

Through application of high-power thyristors used

to convert AC power to DC and back again, the

voltage and hence the power transfer of the DC line

can be directly controlled, possibly enhancing stability as well. While it is currently uneconomic to

use DC lines for such power flow control, research

continues on multiterminal DC lines and improving

the cost and capacity of high-power semiconductors.

HVDC appears to be the single most powerful

method of direct flow control in the battery of

options and with economic feasibility could have a

major impact on the industry.

zJThe Bonneville power ~minis~~ion is experimenting with RAN1, with a preliminary study showing it to compare favorably with mechanically

switched shunt capacitors, static VAR compensators, and mechanically switched series capacitors on the Pacific AC Intcrtie in providing transient support

and damping and post-disturbance support and stability. In one configuration. loop flow was reduced 43 percent (348 MW) at the cost of 68 MW

incremental losses. (Personal communication with Mr. Dean Perry of BPA, July 1988).
Chapter 4--Power System Technology ● 117

Controlling Reactive Power and Voltage

Increasing the availability and control of VAR

supplies on the system is one approach to alleviating

voltage-related transmission limits.24 Generators are

one common source of VARs as well as real power.

Capacitors may be installed at various points to

increase the available supply of VARs. The capacitors can be designed to be switched in and out of

operation, allowing operators to control VAR supplies. Synchronous condensers and static VAR

compensators may also be installed on transmission

lines to provide a controllable source of VARs.

Inductors may be connected in shunt with the line in

specific instances. Series connection is rare and used

to control excess current in short circuit conditions.

Another technique typically used to control VAR

flows is to control the VAR output of generators, just

as real power is controlled.

Increasingly, methods are being developed for

operation and control systems to use computer load

flow models (called optimal power flow models) to

simultaneously dispatch both VARs and real power.

It is anticipated that the future will see more

applications of these methods, The cost of implementation will include metering and communication and

control equipment as well as new software.

Stability Response

A utility can increase its transfer capability by

shifting its reliability policy from the preventative

mode of operation to the remedial mode. There are

numerous special protection schemes being developed and applied. Generation response options

generally increase the ramp rate at which a generator

can increase or decrease its output or temporarily

increase its peak output. These options may increase

maintenance costs by increasing operating stresses.

Generator “tripping, “ “fast runback,” and “fast

valving” systems are generator control schemes

designed to rapidly reduce power fed into the grid

while continuing to keep the unit on line and

available, Increased output from generators can be

obtained by temporarily turning off auxiliary plant

equipment at the generating stations. A 10-percent

increase in output may be temporarily obtained

using these measures. However, operating power

plants in this way may reduce equipment life or

increase the risk of failure.

These methods have been used in specific cases

but have not been widely applied to date. They

require careful study and application if they are to

achieve the same level of system reliability as

achieved by the defensive scheduling techniques.

Future Trends

A wide variety of techniques for increasing

transfer capability are in use and under development

in the United States. There are some developments

which may have significant long-term effects on

system operation and transfer capability. These

include developments in high-power semiconductors;

ongoing improvements in computing and data processing capabilities; and, in the very long term, possibly

even superconductivity.

In general, developments in these areas will have

gradual but increasing impacts. For example, highpower semiconductors are already leading to fast,

nonmechanical switching of VAR control devices.

Further developments will lead to improved reliability and speed for phase shifting transformers and

other devices, before direct switching of highvoltage alternating current (HVAC) lines becomes

possible.

High-Power Semiconductors

With few exceptions, present-day power systems

use mechanical control devices. Mechanical circuit

breakers, relays, switches, tap changing transformers, and generator controls use moving contacts to

close or open circuits, and are therefore limited in the

speed and number of times they can operate. These

limitations mean that power systems are neither as

responsive nor as reliable as may often be desired.

Developments in high-power semiconductors to

allow electronic rather than mechanical control

promise to improve the performance of the power

system in significant and pervasive ways. This is not

a sudden revolution, but a continuing trend that has

already lead to static VAR compensation and HVDC

transmission lines. However, recent research has

24Sec, for example, Scicntifk System, Inc., Optimizatwn of Reactive Volt- Ampere (VAR) Sources in System Planning, EPRI EL-3729, Electric Power

Research Institute, November 1984; and University of Washington, Reactive Power Management Device Assessment, EPR[ AP-521O, Electric Power

Research Institute, August 1987.
118 . Electric Power Wheeling and Dealing: Technological Considerations for Increasing Competition

dramatically expanded the prospects for a range of

future uses.25

Controlling Power Flow

There are several possible applications of highpower semiconductors to the general area of controlling power flows. 26 As described above, there are

many means of relaxing power transfer constraints,

and several of them have the opportunity to be

significantly improved by the use of high-power

semiconductors. Static VAR Compensations and

Rapid Adjustment of Network Impedance (RANI)

are both early applications of high-power semiconductors (thyristors). Both methods rapidly and

continuously vary the amount of shunt or series

reactance present to control the total line impedance.

Higher power semiconductors will have applications to phase-shifting transformers and variable

voltage tap-changing transformers.

Use of high-power semiconductors as switches, or

resettable fuses, to directly reconfigure the actual

network will require very high voltage and current

capabilities. Switches that can handle such high

voltages and currents economically have not yet

been developed, but the prospect is within sight. The

speed and control of switches that can turn on and off

every cycle (or more often) without wearing out will

make remedial reliability methods more practical

and economic.

High-power semiconductors are currently used on

HVDC power lines to convert AC power to HVDC

and back again. The power thyristors used in this

conversion are sufficiently expensive that HVDC

power lines are only practical for lines which are

long enough to bear the high terminal cost or as

interconnections between asynchronous systems.

Lower cost and higher capacity semiconductors will

make shorter DC lines economically practicable and

allow multiterminal HVDC lines, instead of the two

terminal lines now used. Because the conversion

voltages at both ends of a line can be controlled,

HVDC transmission allow essentially complete

control of network flow.

Power Control of New Energy

Sources and Storage

In addition to increasing network transfer capability and reliability, high-power semiconductors will

play a crucial role in power conversion and conditioning for new power sources and energy storage

systems. Energy sources such as photovoltaics and

fuel cells produce relatively low voltage DC power.

It is necessary to convert this power to AC in order

to connect the generating unit to the grid. Wind

power plants already produce AC power, but the

mechanical governors needed to regulate frequency

are liable to stress, reduce reliability, and limit the

maximum power available from the wind. Solid

state power conversion can be used to let the wind

turbine generate as much power as possible, convert

the variable frequency power to 60 Hz AC, and also

supply VARs to compensate for the natural inductance of these generators. In addition to generation,

various proposed energy storage methods require

conversion of AC to DC power, and back again.

Whether as basic as batteries or as esoteric as

superconducting magnetic energy storage, higher

power semiconductors will play a key role in making

the necessary energy conversion reliable and efficient.

One key to increasing semiconductor power

capability is the development of high-purity silicon

devices which can handle large currents and voltage

with losses low enough that device temperature is

reasonably limited. One such device being developed is the metal oxide semiconductor controlled

thyristor (MOS-CT). These devices are light fired, or

optically triggered, by a laser diode either directly or

via fiber optics. Unlike conventional thyristors,

these devices can be turned off as well as turned on

during each half cycle. More importantly, these

devices can combine a microprwessor on the same

chip as the power semiconductor to produce integral

intelligent control of the high-power switch. The

thyristors may be stacked in parallel or series to

increase current and voltage and this stacking may

be done either on a single chip or by stacking chips

together.

Zssteitz & As~iates, ~urerl~s and Devicesfor Power Electronic Applicatwns, EPRI AP/EM/EL-S470, Electic Power Researeh Institute, hkch

1988.

Z6N.G. Hingoram,“ “High Power Electronics and Flexible AC Transmission System, “ IEEE Power Engineering Review, July 1988, pp. 34.
Chapter 4--Power System Technology ● 119

Development of high-power semiconductors is

currently underway as a joint effort between industry

and government. The Department of Defense is

interested in high-power switching required for

Strategic Defense Initiative (SDI) applications, and

the National Aeronautics and Space Administration

(NASA) is also interested in civilian space-drive

applications. In October 1987, EPRI opened the

Power Electronics Applications Center in Knoxville, Tennessee. This center and a series of yearly

conferences are intended to promote industrial and

consumer end-use applications of power electronics,

rather than basic research. This effort reflects the

belief that recent power electronics developments

have created opportunities and that applications

have lagged their potential.

Research is being conducted primarily by General

Electric with some work also being performed by

Westinghouse. The work is being funded by the

Army (under SDI), Navy, Air Force, NASA, and

EPRI. Current funding is about $3.5 million per

year, with about $2.5 million being spent upon

hardware/device development and about $1 million

(from DARPA) being spent on materials development. Total government spending is estimated to

total 10 to 40 million dollars, excluding industry

investment.

Single semiconductor devices rated up 20 kV and

a few thousand amps are envisioned within the next

10 to 30 years which will meet utility needs with low

losses, low cost, and fast switching capabilities.

Such capabilities make it likely that delivered power

will flow through high-power semiconductors several times before reaching the customer.

Improving Computer Capabilities

Continuing trends in data processing and computing capabilities have widespread applications in

power system operations and planning.27 Expert

systems and artificial intelligence continue the trend

towards increasing computer applications in the

utility industry and are properly a subset of a wide

array of advancing modeling and computer analysis

capabilities. 28

Expert systems essentially codify a subject or

system of knowledge that is too large or esoteric for

the end user, into software form. The codified rules

then guide the user interactively by requesting data

and making suggestions. Some of the varied applications for improved computing capabilities include

the following.

System Engineering and Planning

System planners use many specialized computer

applications for such diverse activities as:

. forecasting and modeling loads,

. selecting generation expansion plans,

. selecting transmission capacity expansion plans,

. examining reliability of systems,

● investigating system stability, and

. real and reactive power flows resulting from

systems changes.

Many of these applications are computationally

challenging and are continuing to benefit from the

expanding abilities of both computer hardware and

software.

Control Center Operations

As in system planning, many specialized computer applications are used in control centers. Faster

and more powerful hardware and software allow

improved monitoring, analysis, and modeling of

system conditions as they change. Areas of application

●

●

●

●

include:

real-time load flow models allowing optimization of VAR dispatch and optimization of

power transfers,

improved monitoring of thermal conditions and

voltages on transmission lines allowing dynamic line ratings,

improved response to system emergencies, and

real-time assessment of contingency security.

Transmission and Distribution Automation

The current transmission and distribution system

is largely mechanically controlled and operation is

confined primarily to generation dispatch and emer2

7 SIX for example, “Special Issue on Computers in Power Systcm operations,’” Proceedin~s of the IEEE, December 1987; or Carkm & Fink

Associates, Inc., /nlegrated Power System Analysis Pac&uge ~ Scoping Stud), EPRI EL-4632 VOIS. 1 and 11, Ekmic Power Research lnstilute, July 1986.

28univcrsity of Washington, De~eloPme~ of E~efl system av on-Line pow~r ,~~,stem operatio~l Aids, EpR1 EL-5635, Elccwic power Rcsetich

Institute, February 1988. Carnegie-Mellon University, ArriJkial lnrel/igencc Technologies for Power Syslem Operafwns, EPRI EL-4323, Electric

Power Research Institute, January 1986.
120 ● Electric Power Wheeling and Dealing: Technological Consideration for Increasing Competition

gency response. Development of more flexible AC

transmission controls, increased dependence on

remedial reliability responses, and distribution automation (including load shedding control) are trends

which will complicate operation of the transmission

and distribution system. These trends, which should

bring improved reliability and economy, make use

of the advances in communication and data processing capabilities.

Power Plant Diagnostics and Monitoring

Advances in power plant diagnostics and control

systems allow more reliable and efficient operation

at the price of complexity. Expert systems can assist

the operator in a range of ways from finding

problems before component failure, to helping

determine ramp rates and timing that will optimize

the trade-off between heat rate and plant life.

Operator Training and Simulation

In addition to helping run a generating plant,

expert systems can also be used for initial and

ongoing training of operating personnel. Such systems can be useful in practicing responses to

extreme situations which rarely occur, especially in

nuclear plants. Nuclear plants typically have a

simulator operating room for such purposes, but

expert systems can assist in organizing, recognizing,

and responding to data instead of just presenting a

scenario.

Superconductivity

Superconductors will have a number of obvious

and important possible applications in the utility

industry when further development makes them

practical. These applications include superconducting

generators, transmission lines, magnetic energy

storage, and large inductors.

These possible uses have been recognized for a

long time and have been researched to a limited

extent using older, conventional low-temperature

metal superconductors. The recent discovery of

ceramics which superconduct above the temperature

of liquid nitrogen (77° K) raises the hope of much

reduced costs and wider applications. The rate and

extent of superconductor applications depends upon

how fast and how far it is possible to push three

interrelated limits to superconductivity: critical temperature, magnetic field, and current density. The

critical temperature is the best known limit and

determines the extent of thermal losses (which

would be important in applications such as transmission lines). The current density limit is also important for power applications, since it is key in

determining size and cost. Cost limitations will

probably be based primarily upon fabrication costs

and operating costs.

The most likely actual early use appears to be in

energy storage.29 Economic storage of electricity

using superconducting magnets would be revolutionary indeed. The structure and operation of the

utility business is built on the fact that electricity

cannot be stored. Storage options to date include

pumped hydro, compressed air storage, and batteries, but are site limited, inefficient, and/or expensive. Energy storage would allow supplying electricity at a relatively flat, constant rate to meet the

changing daily load curve, which would in turn

allow use of efficient, base-load plants only. Reliability, system control, and the use of new energy

sources (such as photovoltaics) would all benefit

enormously. 30

The difficulties will include cost, refrigeration,

and enormous magnetic stress on brittle ceramic

superconductors. On a smaller scale, energy storage

may be used to improve system stability and

reliability.

Another possible application is in generators,

where use of superconductivity would produce

higher magnetic fields, smaller size, and lower

losses. Because of the high efficiencies of conventional generators (greater than 98 percent), gains

would be relatively small. Preliminary designs and

testing of prototypes have already been made for

such generators, using lower temperature metal

superconductors.31

Nu.s. Conmss, office of ~hnology Assessment, Commercializing High Temperature SuperconductMy, OTA-ITE-388 (Washington, w: U.S.

Government Printing Office, June 1988), p. 161.

3~or a ~Wusslon of ~e more gewr~ benefits of storage, see Electric Power Consulting, Inc., DYNAS’TO/?W Computer Modelfor QuanrifYn~

Dynamic Energy Srorage Benefits, EPRI AP-5550, Elecrnc Power Research Institute, December 1987.

31 LJ.s. con~ss, office of Technology Assessment, op. cit., footnote 29.
Chapter 4--Power System Technology ● 121

Transmission lines are a possible later use, but

not necessarily as attractive as they might first

appear. Although the line would have no resistance,

this would have to be balanced against cooling

losses, total cable and burial costs v. an overhead

line, and (presumably) reduced right-of-way requirements. More importantly, we have already seen

that pure resistance losses are not the constraining

limits to power transfer, particularly for medium and

long lines. Superconducting cables will not relax

synchronous stability or voltage support constraints.

HVDC circuits would benefit much more from

superconducting lines but AC/DC conversion equipment costs will still limit use to long lines until the

price of high power semiconductors drops. In either

case transmission losses typically total in the neighborhood of 1 to 3 percent (up to 6 percent for systems

with long lines), so any improvements will not be

revolutionary. Reduced siting and environmental

impact of buried

major forces even

marginal.

superconducting lines may be

if purely economic benefits are

Some utility applications of superconductivity

have already been designed and tested. These

include:

●

●

A 1982 test of superconducting transmission

cable proved a 2,000 MW capacity for a 16

inch, liquid helium cooled test cable. This test

was performed by Brookhaven National Laboratory in conjunction with EPRI.

A superconducting magnet installed and tested

by the Bonneville Power Administration for

use in controlling transmission line fluctuations

at its Tacoma substation. This reliability application of magnetic energy storage is likely to

precede application of large-scale energy storage for flattening daily load curves.
Chapter 5

Technological Requirements and

Performance Under

Increased Competition
CONTENTS

Page

INTRODUCTION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 125

OVERVIEW OF TECHNOLOGICAL IMPACTS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 126

INCREASING SUPPLY COMPETITION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 129

Load Following . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 131

Coordinating Transactions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 133

Maintaining Reliability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 134

INCREASING TRANSMISSION ACCESS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 136

Load Following . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 140

Coordinating Transactions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 145

Maintaining Reliability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 145

CURRENT UTILITY PERFORMANCE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 147

Individual Utilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ● . . . . 147

Interutility Coordination and Power Pooling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 147

TECHNOLOGICAL ISSUES OF OTA’s SCENARIOS . . . . . . . . . . . . . . . . . . . . . . . . . . . . 149

Scenario 1: Reaffirming the Regulatory Compact . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 150

Scenario 2: Expanding Transmission Access and Supply Competition . . . . . . . . . . . . . 150

Scenario 3: Competition for New Bulk Power Supplies . . . . . . . . . . . . . . . . . . . . . . . . . . 151

Scenario 4: Generation Segregated From Transmission and Distribution Services . . . 152

Scenario 5: Common Carrier Transmission Service . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 152

Boxes

Box Page

5-A. A Partly Independent Power Producer: The Ocean State Power Project . . . . . . . . . . 129

5-B. Bidding in Virginia . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 137

5-C. Bidding in California . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 139

5-D. Bidding in Maine . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 141

5-E. Southwest Bulk Power Market Experiment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 142

5-F. Western Systems Power Pool: A Current Experiment in Transmission Access

and Bulk Power Pricing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 143

5-G. Innovative Transmission Access: Turlock Irrigation District . . . . . . . . . . . . . . . . . . . . 144

Table

Table Page

5-1. Operation and Planning Functions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 127
Chapter 5

Technological Requirements and

Performance Under Increased Competition

INTRODUCTION

Proposals for increasing power industry competition raise challenging questions of technical

feasibility and cost. What technological requirements does competition raise? What would meeting

those requirements cost, and how would reliability

be affected? What is required to make a competitive

proposal workable?

The answers depend on the type of competition

envisioned. The five scenarios of chapter 3 present

widely varying visions of power industry change,

each with its own specific technical questions.

While each scenario is unique, they share two

fundamental competitive changes:

. expanded generation market-more companies

allowed to enter and compete in supplying

electricity; and

. expanded transmission access—a widened avenue of exchange between competing generators

and purchasers with the involvement of the

local utility restricted to transmission services.

Both types of change involve unbundling, or separating, of generation from transmission to different

degrees.

Power industry competition may take a variety

of forms depending on how and to what extent

increased supply competition and expanded transmission access are implemented. For example, supply

market competition may unbundle all generation

from transmission (scenarios 4 and 5). Alternately,

competition may be limited to some (scenarios 1 and

2) or all (scenario 3) new generation only, leaving

existing generation under the ownership and control

of integrated utilities. Competition in new generation may be limited to certain suppliers, such as

facilities qualifying under the Public Utility Regulatory Policies Act (PURPA), or may include other

independent power producers as well as new utility

generation.

Similarly, alternatives for expanding transmission

access range from encouraging further voluntary

wheeling (all scenarios) to mandating wheeling

among utilities (scenarios 2, 3, and 4) or for large

retail customers (scenario 2) to entirely unbundling

transmission from both generation and distribution

so that all power is wheeled power (scenario 5).

Chapter 5 examines the technical feasibility and

costs of the changes that will be required by

increasing competition. It also summarizes the

general technical and economic impacts of competitive change in the electric power industry. Next are

analyses of the challenges of increasing the number

of separate bulk power suppliers and those posed by

expanded transmission access. This is followed by a

review of the cost and performance of the current

utility structure, examining where economic performance of industry changes may lie. The last

section summarizes the technical issues raised by

each of the five scenarios discussed in chapter 3.

In this chapter, the impacts of competition are

viewed from a system coordination perspective. As

described in chapter 4, all the individual generation

and transmission components of a power system

must be coordinated. No matter what form competition takes, no matter what the extent of expanded

markets, some system will be required to coordinate

planning and operation of the individual pieces.

Even if the ownership of generation, transmission,

and distribution is entirely separated (scenario 5),

there still has to be a highly sophisticated system to

coordinate planning and operation.

Throughout this chapter, it is assumed that the

competitive changes should not result in degradation

of the reliability of a power system. This assumption

is necessary to keep separate the consequences of

competition from other unrelated decisions. For

example, service reliability could be reduced deliberately to lower the cost of service or to better match

consumer preferences under any scenario. However,

by accepting reduced reliability in one scenario but

not in another, comparisons of the effects of

competitive measures on planning and operating

procedures and on physical system requirements

would not be meaningful.

–125–
126 ● Electric Power Wheeling and Dealing: Technological Considerations for Increasing Competition

OVERVIEW OF

TECHNOLOGICAL IMPACTS

The technical feasibility of increased competition depends largely on developing new approaches to coordinated planning and operation

of the bulk power system. Defining workable

institutional arrangements between the participants in the power system is a fundamental

requirement. Implementing these new institutional relationships may also require adding

some new physical facilities and improving analytical capabilities.

As discussed in chapter 4, a power system is a

vast, complex machine composed of many interacting generators, transmission lines, and distribution

systems. A reliable, economic supply of electricity

requires carefully coordinated operation and planning of the individual generating units and transmission lines that comprise the bulk power system.

Coordinating the bulk power system involves three

main functions:

. following changing loads to balance the supply

of power with ever-changing demand,]

. maintaining reliable operations, and

● coordinating power transactions between interconnected systems.

Typically, these functions are performed in a way

that minimizes cost. Many operating and planning

procedures are involved in performing these functions (see table 5-l). The procedures range from the

immediate (e.g., regulating frequency) to the long

term (e.g., planning and constructing needed new

supplies) and reflect electricity’s complex physical

laws.

In today’s power systems, the responsibilities for

coordinating planning and operation belong to a

single utility or group of cooperating utilities.2

Current utility approaches to planning and operation

assume relatively centralized control and decisionmaking, with a system-wide objective of providing

reliable and economic service. The control areas

formed by one or more utilities are responsible for

regulating frequency and voltage, and coordinating

power interchange. They have control over generation and transmission components needed to meet

that responsibility. Unit commitment and maintenance scheduling are the responsibilities of the

utility owning the equipment, or the utility’s power

pool. Planning new supply resources and transmission facilities is typically a utility responsibility,

often performed with considerable regulatory oversight and review by the North American Electric

Reliability Council (NERC) region and local pool to

assure reliability.

Unbundling generation and transmission creates a more complex planning and operating

environment by defining new rights and responsibilities for suppliers, purchasers, and transporters of power. The changes modify basic operating and planning assumptions by raising the number

of separate players, each seeking their own economic benefit.3 Unbundling creates a gap between

the entity responsible for coordinating the overall

power system and the ownership and final control

over the system components.4 As the number of

players grows and unbundling increases, control and

decision-making authority is increasingly dispersed.

Operations will increasingly depend on individual

agreements between generators and purchasers (and

in some cases, transported), and will not necessarily

l~is b~~ing involves both active and reactive power.

zNote hat coordinat~ oprating and p]~ng neither implies nor requires ownership by a single entity or a small group. For eXiUnple, in tie New

England Power Pool (NEPOOL), around 100 separate utilities coordinate their planning and operation, sharing in the resulting benefits. In addition to

the multilateral pooling agreement, there are several hundred bilateral arrangements betweenNEPOOL members that speci~ how overall benefits are

allocated.

sNme ~~ it’s not ~esW t. ~eatly incre~ the num~r of ~p~ate p]ayers to @ymodi~ b~ic ~rating d planning assumptions. For

example, a vertically integrated utility could be separated into one generating company and one transmission/distribution compqny (possible in scenario

4). In this case, the number of players increases by only one. However, the resulting interactions between the two companies would be all IWW and

substantially different from what had existed &fore with a single integrated company.

gRccsll that in the ~en~os as discus- in chapter 3, as a practical matter responsibility for ensuring adequate SU@CS milks with thOSC CIOSCSt

to the customers, i.e., the companies performing distribution or the customers themselves under retail wheeling. ‘IWs is true no matter if all supply

is competitive and owned separately from the transmission and distribution functions or if a competitive market supplies only a prtion of new capacity

needs for vertically integrated utilities, Similarly, responsibility for coordinating all system components must rest largely with the companies

performing transmission, since it is the transmission network which provides the link between components.
Chapter S-Technological Requirements and Performance Under Increased Competition ● 127

Table 5-1--Operation and Planning Functions

Function Purpose Procedures involved

Following load

Frequency regulation Following moment-to-moment load fluctuation Governor control

Automatic generation control (AGC) and economic

dispatch

Cycling Following daily, weekly, and seasonal cycles AGC/economic dispatch

(within equipment voltage, power limits) Unit commitment

Voltage control

Maintaining reliability

Maintaining security Preparing for unplanned equipment failure Unit commitment (for spinning and ready reserves)

security dispatch

Voltage control

Maintaining adequacy Acquiring adequate supply resources Unit commitment

Maintenance scheduling

Planning Capm”ty expansion

Coonlimting tmnsactions Purchasing, selling, and wheeling power in AGC/economic eispatch

interconnected systems Unit commitment

SOURCE: *Z from F. Motiri, Southern Catifomia Ediaon, letter to OTA, May 13, 1986.

focus on overall power system needs. This may

affect both reliability and economy.

For example, selecting which supplies to commit

and dispatch is currently performed centrally by

integrated utilities at energy control centers. The

objective is to minimize operating costs (i.e., economic dispatch and scheduling) constrained by

reliability requirements and equipment limits. With

competitive generation or retail wheeling, the selection is further constrained by the arrangements

between supplier, transporter, and purchaser. As a

result, in some instances an unschedulable supply

may operate even when lower operating cost resources are available.

With increased unbundling, new institutional

arrangements must accommodate both the changing abilities and economic incentives of power

system participants and the technical characteristics of electricity. The new operating and planning

procedures must specify priorities for the use of

constrained facilities, information flows between

parties, and incentive and enforcement schemes. As

in today’s power systems, the arrangements may

include formal contracts between the parties as well

as less formal agreements on standards and procedures. Operating agreements and standards may be

developed through multilateral organizations (such

as NERC and the Institute of Electrical and Electronics Engineers) or bilaterally. In addition to the

agreements between suppliers, transporters, and

purchasers of power, other arrangements must specify the role of regulatory agencies and other interested institutions.

As unbundling increases, bilateral and multilateral contracts will be increasingly important instruments to communicate needs and define obligations

of suppliers, transporters, and purchasers of power.

By specifying prices and performance, including

penalties for failure to perform, contracts can help

ensure that competitive supplies meet power system

needs and mitigate uncertainty for both parties.

However, contracts may have some shortcomings

when compared to arrangements within a single

organization, as in a vertically integrated utility, For

example, given the tremendous uncertainty in the

power industry, anticipating all the terms and

contingencies which a contract should cover requires extensive effort. Even with carefully crafted

and flexible contracts, unexpected events outside the

scope of the contract may occur.

Implementing new arrangements may require

some changes in physical facilities. New monitoring and communication equipment may be needed to

track and control the new unbundled transactions

occurring. Additional transmission capacity may be

required as the pattern of loads and supplies changes.

Additional reserves of generation and transmission

capacity may be needed in the face of increased

uncertainty about how well the new institutional

arrangements will perform. Alternately, if competi-
128 . Electric Power Wheeling and Dealing: Technological Considerations for Increasing Competition

tion produces improved performance of generating

units, reduced reserve requirements may result.

New or improved analytical methods may be

needed both in developing and implementing new

procedures. Many attributes of power systems

central to planning and operation are not easily

quantified. For example, the availability of additional transmission capacity at any moment is

challenging to calculate and somewhat subjective.

The value of such generation characteristics as fuel

diversity and level of dispatchability is similarly

hard to quantify. And as noted by Edison Electric

Institute, “In virtually every form of coordination

sale, there are subjective determinations and uncertainties which are generally not susceptible to simple

quantification for purposes of regulatory adjudication. Many of these uncertainties relate to the

potential impacts on system reliability of a particular

transaction. ”5 As the functions currently performed

by integrated utilities are unbundled and provided by

different parties, accurate measures of the performance of each party and calculation of the cost or

value of their contribution to the power system will

become increasingly important. Evaluating performance is essential for developing prices and

priorities, a prerequisite for a functioning market.

There has been little analysis of the reliability

or economic impacts of competitive proposals.

The past decade brought some competitive experience to the industry.6 PURPA advanced new opportunities for qualifying facilities (QFs) to generate

power using untraditional technologies using cogeneration, renewable, and waste products. Some

utilities and State regulatory agencies have gained

considerable experience in integrating these QFs. A

few proposals for non-QF independent power producers using more traditional generating technologies have also been advanced. One is slated for

operation in 1989 (see box 5-A on the Ocean State

Power Project.) A few experiments based on more

flexible pricing have given some utilities expanded

transmission access. Analyses of the cost and

performance are still to come .

7 These competitive

changes continue to play a prominent role in the

evolution of the industry. However, many current

competitive proposals reach well beyond the experiences gained in the past decade, The lack of

experience in widespread wheeling and in competitive generation of unrestricted size, type, kxation, and penetration results in substantial uncertainty over how well the system would work under

the scenarios.

How suppliers, purchasers, and transporters of

power will respond to any competitive proposal is

speculative. It is this individual behavior and how it

is coordinated, however, that determines the real

feasibility, reliability, and economic impact of

increased competition in the electric utility industry.

The costs and benefits of increased competition

depend not only on the cost of developing and

implementing the new procedures but on how those

procedures affect the efficiency of the current utility

structure and encourage improved performance.

This study has identified no insurmountable

problems of technical feasibility with any of the

scenarios, although there are some substantial institutional challenges of developing new planning and

operating arrangements. The ease or difficulty of

implementing the institutional changes to meet

technical requirements is necessarily speculative.

For the scenarios with incremental competition in

generation and controlled transmission access (scenarios 2 and 3), some view the institutional changes

as relatively easy to develop; others believe there

will be considerable difficulty. However, growing

experience indicates that some forms of scenarios 2

and 3 are feasible. Major system-wide changes raise

considerable uncertainties and risks to reliability and

economy. Separating all generation from transmission (in scenarios 4 and 5) raises the greatest risks.

Both reliability and economy could be greatly

reduced in the potentially long time required to

experiment and develop new procedures for such

extensive changes.

S~Wn ~W~c ~titute: ~RC ~ket RM85-17m (Phase I) Comments of Edison Electric Institute, Aug. 9, 1985, p. 10.

6SW ch, 6 for mm discussion of State and utility cxpCrie~s.

7~eW include tie wes~em Systems power poo], in o~ration from ]987 ~o@ 1989; ad its precursor, the 2-year Southwestern Experiment

which ended in 1985 (see boxes on the Western Systems Experiment, and the Southwest Experiment later in this chapter).
Chapter S---Technological Requirements and Performance Under Increased Competition ● 129

Box 5-A—A Partly Independent Power Producer:

The Ocean State Power Project

In August 1988, the Federal Energy Regulatory Commission (FERC) accepted a power sales agreement for

the Ocean State Power Project (OSPP) in Rhode Island. OSPP will use a single 235 MW natural gas-fired combined

cycle unit, with a possible second unit at a later date. It is the most advanced example of a large independent power

producer (IPP) that is not a qualifying facility under the Public Utility Regulatory Policies Act. While only partly

independent of utility ownership, OSPP is one model of a non-QF independent power producer.

Ownership

OSPP is a partnership of private developers and electric utilities. Fifty percent interest in the plant is divided

among several affiliates of the electric utilities purchasing some of the power output.2 They are:

. 25 percent Eastern Utilities Associates, parent of Montaup Electric Co.;

. 20 percent Narragansett Energy Resources, affiliate of New England Power Corp.; and

. 5 percent NECO Power, Inc., subsidiary of Newport Electric Corp.

A subsidiary of TransCanada Pipelines has a 40 percent interest. (Another TransCanada subsidiary is OSPP’s

natural gas supplier. ) The remaining 10 percent interest is held by affiliates of J. Makowski.

According to FERC, with respect to the above utilities, OSPP would not qualify as an IPP.3 However, a

substantial portion of OSPP’s power will be sold to Boston Edison, which has no financial interest. With respect

to Boston Edison, then, OSPP would qualify as an IPP.

Operation

Although not owned primarily by electric utilities, OSPP will operate as a traditional utility generating unit.

In New England, the New England Power Pool performs economic dispatch based on generating unit operating costs

and system operating requirements. Because of the high operating efficiency of OSPP’s combined cycle unit the

project developers expect that the plant will generally operate as a base-load unit.4 Plant operation is expected to

begin in 1990.

locem Sfak ~ower, OKIa keping Amendments to Power Sales AgrWXLWINS, FERC Docket No. ER8W78-UU f@. 19.1988.

Also, Ocean Sfde Power, 38 FERC 61,140 (1987).

2E\ectric Utiiity Week, May 23, 1988.

30cc@ side pOwer, ~~qtin~ ~a~n~ to pow= sa]cs &~en~, ~Rc hket No. ER884784MX), Aug. 19, 1988, foomo[e 28.

4J, Makwvski and C. Riva, “Gas Fired Electricity: The ocean State pOW~ hJ~L” Energy Technology XIII: Energy in Transition, Gwentment Institutes,

hlC., March 1986, pp. 189-198.

INCREASING SUPPLY

COMPETITION

This section examines the effects of extending

current coordination systems to an increasingly

competitive supply market. The challenges of increased wheeling are left to the following section.

In today’s power systems most generation is

owned and operated by vertically integrated utilities

which also own and operate the transmission and

distribution systems. However, there is already a

moderate and increasing amount of competitive

supply in use employing a variety of generation

technologies and forms of ownership. Competitive

suppliers of electricity include:

●

●

●

●

PURPA QFs, either cogenerators or small

power producers using a variety of untraditional supply technologies and fuels;

non-QF independent power producers (IPPs);

utilities with surplus capacity; and

foreign electricity suppliers, most notably Canada.

Developers of demand management programs may

also play a role in increasing competition.

The physical performance capabilities of competitive suppliers may present both challenges
130 ● Electric Power Wheeling and Dealing: Technological Considerations for Increasing Competition

and opportunities to coordination. For example,

some cogeneration units may be inherently less

responsive to controls than a typical utility generator. However, those same cogeneration units may

also bring the planning and operating benefits of

reduced construction lead time, lower capital and

operating costs, higher availability, and smaller unit

size. The physical characteristics which determine

the value of a generator are diverse, including such

factors as size, location, construction lead time and

cost, ramp rates, dispatchability, voltage and VAR

output, fuel type, operating efficiency, and reliability, as described in chapter 4.

Modem planning and operation systems have a

demonstrated ability to integrate a wide variety of

supply technologies, exploiting the advantages of

each. Whether that ability can be extended to

coordinate an increasingly competitive supply market depends on two factors. First, does the generation technology used by competitive suppliers raise

unique technological challenges? For example, is

the equipment used in a cogeneration or independent

power facility inherently less responsive to controls

than typical utility generation? Second, do the

arrangements between the competitive suppliers and

purchasers provide the appropriate information and

control to coordinate generator operation and planning?

Challenges caused by most generation equipment

should be relatively minor or nonexistent. In fact

many competitive suppliers-particularly IPPs, utilities with surplus low cost capacity, and foreign

imports-may use traditional generating technologies (see box 5-A). The performance capabilities of

even those competitive suppliers using cogeneration

and less traditional technologies and fuels often

produce power with characteristics within the wide

range commonly found in today’s utility generation

equipment. 8

Some generating units, notably those using wind

or solar power and in some cases, cogeneration, have

variable power output, unlike traditional utility

resources. For example, power may vary regularly

with the sun’s daily cycle or may change suddenly

as clouds block the sun, winds gust, or industrial

facilities change steam requirements. These technologies, often grouped together as dispersed

sources of generation (DSGs) have been widely used

as QFs under PURPA. The technical literature has

discussed many aspects of the growth of DSG plants

on utility system planning and operation.9 Many

technical problems of the relatively small-sized

DSGs are due to the combined effects of the

operating characteristics of these plants and the fact

that they are often connected to the utility network

at distribution voltage levels.

Conservation and load management may also

play a role in more competitive supply markets.

Many U.S. utilities actively promote conservation

and load management as alternatives to traditional

supplies. While the cost and operating characteristics of conservation and load management options

vary widely, many have some operating characteris10 For example, tics similar to supply resources.

interruptible rate programs, which allow utility

dispatchers to turn off customer loads at peak

periods with little notice, have characteristics similar to peaking generator units. Some conservation

programs have characteristics similar to base-load

resources. As with DSGs, when properly planned

and integrated into a power system, conservation

and load management should cause no operating

problems.

Although the performance capabilities of technologies used by most competitive supplies raise

relatively few difficulties, new arrangements for

coordinating planning and operation are required.

Unbundling generation from transmission requires

modifying current operating and planning proce6R=~I frm ch. 4 th~ ttiy*5 power systems employ a wide variety of generating technologies with diverse abilities to contribute to voltage ~d

frequency regulation, to provide spinning reserves, and to schedule output and maintenance. Construction lead times and costs, and operating costs also

vary widely. A vital role of coordinated planning and operation is to find ways to integrate the wide variety of avtilable resources and harness their

beneficial characteristics.

9Sm, for Cxmple, power ‘llxltn@@eS, inc., Appficution of /nducrion Generators in Power Systems (Palo Alto, CA: EIcctic Power Research

Institute, 1981), EPR1 EL-2043, U.S. Congress, Office of lkchnology Assessment, New Electric Power Technologies: Problems and Prospectsfor

the 19Ws, OTA-E-246 (Washington, DC: U.S. Government Printing Office, July 1985). Systems Control, Inc., integrating Dispersed Storage and

Generation Info Power System Controf (Palo Alto, CA: Electric Power Research Institute, 1987), EPRI EL+957.

IOSW, for Cxmple, OTA, OP. cit., footnote 9.
Chapter S--Technological Requirements and Performance Under Increased Competition ● 131

dures, including developing new pricing arrangements and analytical capabilities. Most experience

to date has come from implementation of PURPA,

in developing the pricing arrangements for QFs.

Coordinating generation to follow changing loads

and provide sufficient reserves at minimum cost

already presents significant and challenging problems. An increasingly competitive supply market

raises further challenges by reducing power system

operators’ direct control over coordinated operation

and planning of generation and transmission. The

following sections examine how the basic functions

of following changing loads, maintaining reliability,

and coordinating transactions would be effected.

Load Following

Frequency Regulation

Regulation-adjusting the power output of generators to follow moment-to-moment load fluctuationsis a fundamental function in reliable power system

operation. Regulation is implemented using generator governors and automatic generation control

(AGC)/economic dispatch to control the output of

spinning reserves made available under unit commitment schedules.

How Much Control Is Needed?—There is no

need for all generators to contribute to regulation. 1l

The amount of regulating generation required depends on system conditions including anticipated

load changes and the ramp rates and availability of

other generators. Spinning reserves required for

regulation are typically a few percent of load.

Determining the amount of regulating capacity

required is one function of unit commitment scheduling. Typically, regulating duty is shared by as

many units as possible, each operating at slightly

below its capacity. This allows the most rapid

response, and minimizes the stress on any individual

unit. So long as sufficient generation is controlled by

governors and AGC, following changing loads

presents few problems.

How Can Control Be Obtained in a Competitive

Market?—There are both direct and indirect costs of

contributing to frequency regulation. Participation

in regulating duty slightly reduces a unit’s fuel

efficiency and tends to increase maintenance requirements and reduce lifetime, creating direct costs.

Also, a generator participating in regulating duty

operates at below its rated capacity some of the time,

creating an indirect cost if payment is based on total

energy output. Competitive suppliers are unlikely to

bear the costs of contributing to regulation unless

specific arrangements are made. Rather, they are

likely to operate at a fixed power output not under

AGC control.

As a result, regulation has to be explicitly

included in operating arrangements under any scenario resulting in high levels of competitive supply

penetration (scenario 1 and 2 at the utility’s discretion; scenario 3 eventually; scenarios 4 and 5

immediately). Because most utility-owned generators typically contribute to regulation, calculating

the precise value has not been an area of major

concern or debate. More precise cost analyses may

be required if a rationale for choosing either the

amount of compensation or the preference in supply

bidding is to reflect the cost of contributing regulation.

The direct costs of regulation-fuel efficiency

losses and maintenance cost increases-are relatively small. For this reason, obtaining agreements

giving an adequate amount for frequency regulation

should not cause significant problems at any level of

competitive supply penetration. Metering, communication, and accounting equipment may be required to

allow the monitoring of generator performance

according to agreement. Such equipment is typically

not required now because of the unified utility

ownership of generators.

Penetrations of nondispatchable technologies such

as wind and photovoltaic generators are unlikely to

be high enough to cause system-wide problems. To

the extent that problems do arise, system planning

may require the use of storage devices or in the

extreme, limit total penetration.

11~ f=t, ~UC]eW ~enera~g ~nlt~ ~W & ~t typlc~ly contribute to regulation but ~ra~ at ~c~ full capacity ~1 & time, Ner supplies such ss

wind turbines, photovokaics, and some cogeneration technologies are physically unable to provide regulation. ‘heir power output depends on kxal

conditions, not on the need to regulate frequency. Wind and solar generators, by having rapidly fluctuating output, may actually create a need for

more regulating capacity.
132 ● Electric Power Wheeling and Dealing: Technological Considerations for Increasing Competition

Some QFs and IPPs contribute to frequency

regulation now. 12 This gives some evidence of the

willingness of independent suppliers to provide

regulation when required to or compensated. In

some cases, competitive supplies such as IPPs may

operate essentially as traditional utility-owned generating units, as in the case of the Ocean States

Power Project.

Cyclical Loads

Following daily, weekly, and seasonal cycles in

load is also a fundamental function in power system

operation. Unit commitment schedules are developed reflecting forecasted load changes over daily,

weekly, and seasonal cycles. Generators in the unit

commitment schedules increase or decrease their

output either under AGC/economic dispatch following actual loads as required, or according to a

schedule, following predicted loads. Performing

economic dispatch and scheduling unit commitment

for following load cycles is central to minimizing the

operating costs of power systems.

How Much Coordination and Control Is Needed?—

As with regulation, not all competitive supplies

need to provide complete control of dispatch and

scheduling to minimize operating cost. For example,

current power systems use minimal dispatch and

commitment scheduling of some plants since a large

portion of demand, called the base-load, is constant.

Nuclear units and to a lesser extent large fossil-fired

steam turbines, with long and relatively expensive

warm-up and cool-down requirements operate continuously to meet base-load requirements (although the

fossil units may contribute to regulation as well).

Few are designed to be operated in a cycling mode. 13

Furthermore, most modem large coal-fired generating units are not designed to operate below output

levels of between 25 to 40 percent of maximum

capacities.

The amount of base or off-peak load limits the use

of generation which cannot be cycled. With a large

amount of such generation operating during off-peak

periods, low operating cost units may be turned off

while less efficient cycling units are run. The result

is true whether that generation is physically incapable of cycling or is only unschedulable due to

operating agreements. Utilities typically choose a

mix of generating units intended to operate as base

load, intermediate, and peaking units reflecting daily

and seasonal loads (see ch. 4).

The ability of generators to follow loads may also

be limited by transmission availability, voltage

constraints, and stability. Those constraints are

highly dependent on the location and time-varying

patterns of load and available transmission and

generation. As a result of constraints on the ability

of generators to cycle, additional voltage control

devices may be required.

The possibility of reduced operating economics

grows as the fraction of power which is not under

coordinated and flexible scheduling and dispatch

increases. The amount of schedulable generation

required for following daily and weekly cycles

depends on system conditions, including anticipated

load changes and the ramp rates and availability of

other generators and available transmission. Daily

cycles vary from system to system but may have

off-peak loads (typically between midnight and 6

a.m.) as low as 30 to 50 percent of daily peak loads.

Weekly and seasonal variations are even larger.

Following such wide cycles requires a large amount

of schedulable generation.

How Can Coordinated Control Be Obtained in a

Competitive Market?—As with regulation, Specific

arrangements must be made for competitive suppliers to follow load cycles, since that requires operating at below capacity. Provisions for following

cyclic loads have to be explicitly included in at least

some operating arrangements under any scenario

resulting in moderately high levels of competitive

supply penetration (scenarios 1 and 2, depending on

the utility’s choice; scenario 3 eventually; scenarios

4 and 5 immediately).

lzIn ~ OTA s~ey of 23 uti]ities, 6 of the 16 with nonutility generators on their system had at least some that contributed to ret@atlOn.

t3A siPificml issue in life extension projects for old generators is that units designed for base load duty are expensive to retrofit for cycling duty.

lqpower ‘IkcImologies, hlC., “’lkchnical Background and Considerations in Proposed Increased Wheeling, Transmission Access, and Non-Utility

Generation,” contractor report prepared for the Office of Technology Assessment, Mar. 30, 1988, pp. 7-23.
Chapter 5-Technological Requirements and Performance Under Increased Competition ● 133

To date, most nonutility suppliers schedule and

dispatch their own operations.15 For small amounts

of competitive generation (possibly scenarios 1 and

2; and in early years, scenario 3), this approach

should present few problems, particularly if purchase prices reflect less than optimal operating

economics. Purchase prices for nonutility power

may reflect time-of-day or seasonal variations in

expected costs, encouraging supplier operation in

peak hours and seasons over off-peak times. However, this approach will become increasingly less

economic as the fraction of uncontrollable supply

increases. The magnitude of increase in system

operating costs depends on system-specific load and

resource characteristics and the fraction of supply

not under coordinated dispatch and scheduling. As

a result, actual value of dispatchable v. nondispatchable generation is not entirely straightforward

to calculate and may be the subject of disagreement

in pricing or bid evaluation.

With large amounts of competitive or unbundled

generation (scenarios 4 and 5 immediately; scenario

3 eventually; scenarios 1 and 2 possibly) explicit

arrangements for coordinated dispatch and scheduling will be required. Such arrangements are becoming more common today. Increasingly, competitive

suppliers and purchasing systems are developing

operating agreements giving the system increased

control over unit commitment scheduling and, in

some cases, dispatch. In a few cases, independent

suppliers are scheduled and dispatched by the utility,

behaving much like a utility generator. In others, the

amount of dispatchability is quite limited, say to a

specific number of hours per year and only under

specific conditions. For example, some QFs in

California agree to reduce output for a specified

number of hours per year when loads are low and

inexpensive hydroelectric power would otherwise

be wasted.

In these cases, the purchasing system can schedule unit commitment and dispatch the nonutility unit

based on price and other contract terms. However,

several factors determine the operating cost and

efficiency of any plant, including whether it’s

operating at full or part load, the amount of reactive

power output, and whether it’s ramping. All of these

factors may change over time for any plant. These

details are important in determining the actual

operating cost of a plant but may be difficult to

include accurately in any dispatching agreement.

Spot pricing (or real-time pricing) is another

approach which has been considered for coordinating the output of generators to follow loads. Under

spot pricing, the price paid to competitive generators

is recalculated regularly (e.g., hourly or daily) to

reflect actual power system requirements and the

availability of alternate supplies. 16 Based on these

“real-time” prices, competitive suppliers schedule

and dispatch their own generation reflecting system

conditions.

The use of spot pricing requires new technologies,

including algorithms for calculating prices and

telecommunication equipment to transmit the

prices. This approach holds some promise as an

alternative to central dispatch for coordinating

competitive supply markets. However, a lack of

experience with spot pricing leaves significant

uncertainties about its practical application. For

example, such basic questions as the responsiveness

of suppliers to hourly, daily, or weekly spot price

changes are yet to be answered.

Coordinating Transactions

Coordination—scheduling and controlling the

flows of power between utilities—is fundamental to

interconnected power system operations. Scheduling transactions requires analyzing both the economic merit and physical ability to perform the

transactions, as is the case in unit commitment and

dispatch of a utility’s own supplies. Inadvertent

interchange, the unscheduled transfers of power

between systems, is kept within NERC operating

standards for Area Control Error by having sufficient generation available under AGC in each

IsAccording t. ~ ~iWn EIw-~c ~stitute smey of nonutility generation, less than 1 percent of interconnwted capwlty placed in operation since

PURPA is fully dispatchable by the purchasing utility. Another 36 percent had limited dis~atchability.Ln contrast, over 6 percent of pre-PURPA

nonutility capacity was fully dispatchable, with another 14 partly dispatchable. 1986 Capacity and Generation of Non-Utility Sources of Energy,

Edison Electric Institute, 1988. Still, evidence of the willingness of most nonutility suppliers to provide dispatchability is limited. While most nonutility

suppliers are not dispatchable, i[ is unclear whether that reflects a lack of emphasis placed on obtaining dispatchability in the past rather than an inability

or unwillingness of the nonutility sources to be dispatchable.

16sW, fm exmple, F.c. SchWpW et al., Spot Pricing of E/ecrricizy (Boston, w: Kluwer ~~emic! 1988).
134 ● Electric Power Wheeling and Dealing: Technological Considerations for Increasing Competition

system to perform load following net of transfers.

Thus the control of unit commitment scheduling and

AGC for coordination is essentially an extension of

that required for load following. Insufficient generation under AGC and unit commitment scheduling

may result in poor regulation or increased inadvertent interchange.

Maintaining Reliability

Security

Maintaining security-preparing for continued

operation after equipment failure or other disturbances and restoring service after outages-is essential to reliable power system operation. Security is

maintained through unit commitment schedules that

provide spinning and ready reserves and the coordination of scheduled outages of generation and

transmission. Also, security constrained dispatch

techniques may override economic dispatch to avoid

transmission constraints and provide transmission

reserves. Together with the coordinated engineering

of relays and circuit breakers used to isolate failed or

overloaded components, they ensure that no single

failure will result in cascading outages.

How Much Control Is Needed?—NERC operating guides require each region or subregion to have

spinning and ready reserves17 equal to the loss of

generation resulting from the most severe failure of

a single generation unit or transmission line.18

Typically, the required reserves area few percent of

total demand. These reserves are in addition to the

spinning reserves scheduled for load following and

must respond rapidly when needed. As long as

competitive supplies are no larger than the largest

existing generators and have similar reliability,

higher levels of spinning reserves for security should

not be required.

Beyond the need to schedule some units for

spinning reserves, all generating units must be

responsive to security constrained dispatch during

emergencies and for restoration following a system

failure. At a minimum, that response may be as

simple as isolating the generator from the power

system using automatic relays. Control of generation

for security is relatively infrequent compared to the

control required for load following. The occasions

on which security constraints require overriding the

least costly generation schedule are highly dependent on the location and time-varying patterns of load

and available transmission and generation. When

security constraints require redispatching generation, there are usually a number of choices of

generators which could make the change. As a result,

the frequency and amount of control actions required

on any particular generator to avoid potential

cascading outages are hard to predict, as is the total

cost increase over optimal economic dispatch.

How Can Coordination Be Obtained in a Competitive Market?—From the perspective of a generating unit, coordinated control of scheduling and

dispatch of spinning reserves for maintaining security and for frequency regulation are much the same.

For this reason, the problems and approaches to

obtaining spinning reserves are similar to those

discussed above under load following.

Control of generation under security constrained

dispatch is somewhat different for maintaining

security than for following load, however. The main

difference is that the control required for security is

more immediate than for load following—if the

proper control isn’t exercised rapidly, bulk system

failure may result. Also, the dispatch control required for security is less predictable and less

frequent, and all generation must be under some

control for occasional emergencies and system

restoration following outages. Operating arrangements must specify the emergency conditions under

which a normally undispatchable generator may be

dispatched. Because of the difficulty of predicting

and defining emergencies, developing and implementing appropriate arrangements will require careful attention.

Finally, planning secure operations requires resolving security-related system engineering problems involving both generators and transmission

components. For example, stability problems may

be due to the interaction of the system controls, the

electro-mechanical behavior of generating units, and

the properties of the transmission system. Possible

solutions may require modifying generator voltage

ITRc~y ~WWes ~cl~e generating units and interruptible loads available within 10 minutes.

16Nfi America Ekctric Reliability Council, NERC Operating IUanuuf (Princeton, M: December 1987), p. 11.1.
Chapter 5--Technological Requirements and Performance Under Increased Competition ● 135

controls, adding controllable reactive power supplies on the transmission system, rejection of excess

generation and load reduction by voltage control or

intentional interruption of customers. System engineering problems depend on complex interactions

between interconnected systems and their components and are hard to anticipate. In any power

system, cooperation between all participants is

required, and contract terms or other arrangements

establishing the framework for solving the problems

need to be established.

Adequacy

Maintaining adequacy-providing enough supplies to meet consumer demand while remaining

within the operating limits of system equipment—is

also essential to reliable power system operation. In

addition to unit commitment and economic dispatch

discussed above, maintaining adequacy involves the

vital function of adding new capacity. Coordinating

maintenance scheduling is also important in maintaining adequacy. Maintenance schedules are designed to time equipment upgrades and repairs so

that adequate supplies are always available while

minimizing overall system operating costs, In the

extreme, uncoordinated maintenance scheduling could

result in insufficient available generation if for some

reason enormous amounts of maintenance were

planned simultaneously. The issues are similar to

unit commitment scheduling for load following.

How Much Coordination of Planning IsNeeded?—

Long-term planning seeks to provide adequate resources to meet demand at lowest cost, reflecting the

long construction lead times of generation and

transmission. There has to be enough total capacity

available after accounting for maintenance and

unplanned outages to meet both real and reactive

power requirements. Some capacity has to be

capable of following changing loads to balance

supply with demand. Transmission capability must

reflect the location of both the supplies and demand.

Furthermore, uncertainty abounds because demand

is uncertain, as are fuel costs and the availability and

performance of supplies.

An increasing reliance on competitive supplies

alters traditional long-term planning in several ways.

First, decisionmaking for new generation investment is increasingly separated from the power

system planners. This reduces the system planners’

direct role in developing supplies with desired

characteristics such as the mix of base load and

peaking units, fuel mix, load following ability, and

siting near available or planned transmission. However, even in a competitive system, planners should

still be able to direct the type of development

desired.

Also, in the current power industry, utilities

conduct cooperative planning studies to determine

transfer capacities and requirements and perform

coordinated regional studies. Data about system

forecasts and resource plans are exchanged freely.

An increasingly competitive supply environment

may reduce the incentives and avenues for cooperative planning, with resulting increase in uncertainty

and inability to plan optimally. The degree of

reduced cooperation and the resulting reliability and

economic impact are speculative and yet to be

determined. Even if data is shared freely, the

complexity of permutations of several competitors

may make the planning problem of system optimization larger.

Second, a competitive supply market may increase uncertainty about the long-term availability

and performance of supplies. For example, will a

generating unit under construction-be completed, or

will a completed unit continue operation if the owner

has severe financial problems?19 How will the

requirements of an industrial process affect the

availability of an associated cogeneration unit? Will

competitive suppliers without fixed prices contracts

greatly increase price when supply shortfalls occur

and reduce prices when there is surplus capacity?

While these issues are not unknown in present utility

planning, dissimilar objectives of competitive sup19Some pm of my incm~d uncertainty over supplies may actud]y demonstrate a mme responsive ~in which proposers of uneconomic

resources rapidly withdraw their projects when market conditions are unfavorable. However, it is conceivable that some competitive suppliers may

have performance problems unrelated to a power system’s need for their power. For example, a plant closing could halt operation of an industrial

cogeneration facility regardless of the electric system’s power requirements. Even in this case, the plant closing may not necessarily result in a loss

of the power resource. If proper arrangements were made, the generator could conceivably continue operation, although not using the waste heat for

industrial processes. Also, a plant shut-down would also eliminate the plant electric load so the net effect on the power system would not be the simple

loss of the generation unit.
136 ● Electric Power Wheeling and Dealing: Technological Considerations for Increasing Competition

pliers and the power system purchasing the electricity may increase volatility in the supply market.

Third, competitive markets hold some promise for

shortening construction lead times. While lead time

varies greatly by generation technology, there is a

possibility that competitive generation markets will

produce more efficient construction practices and

thus shorter lead times for any technology .20 As a

result, the responsiveness of new supply to uncertain

and changing power system needs may improve. To

the extent that lead-time reductions occur, the

importance of forecast uncertainty will diminish, to

the benefit of system planning.

Coordinating Planning--Long-term contracts will

be essential in coordinating planning. The process of

developing contracts will be instrumental in communicating needs and defining the obligations of

suppliers and the power system. By specifying

prices and performance, including penalties for

failure to perform, long-term contracts can help

ensure that competitive supplies meet power system

needs and mitigate uncertainty for both parties.

Individual competitive suppliers could also

choose to develop generation without long-term

agreements, speculating on future needs of the

power system. This could occur either if no longterm contracts were offered, or if the supplier

believed the future market would offer more favorable terms. However, there is no evidence that

suppliers are willing to make such speculative

investments. Similarly, a power system may find

short-term agreements with speculative suppliers

advantageous if a large enough oversupply develops

or if it anticipates more favorable terms in the future.

Once a purchaser (a utility in scenarios 1, 3, and

4; a utility or a larger retail consumer in scenarios 2

and 5) has determined its supply requirements

through its own planning process, it needs to select

among alternate suppliers (assuming sufficient suppliers materialize). Supply requirements may be

specified in terms as wide-ranging as the type of fuel

used, location of units relative to existing and

planned transmission, and type of operation (e.g.,

cycling or base load). In the past few years, utilities

and regulatory agencies in several States have

developed a wide variety of bidding procedures for

procuring generation from competing suppliers.21

The bidding procedures developed in different

States incorporate a variety of mechanisms to

accommodate the needs of coordinated planning and

operations (see boxes 5-B, 5-C, and 5-D) which

describe bidding in Virginia, California, and Maine.

In the face of uncertainty regarding how well new

competitive procurement systems will work, one

possible planning response is to increase generation

and transmission reserves. The amount of additional

generation reserves needed to maintain reliability, if

any, depends on subjective assessments of not only

the construction and operating performance of

competitive suppliers relative to utility generation

but also on the ability of new operating arrangements to adequately accommodate system requirements. Additional transmission reserves would support the higher level of generation reserves and also

prepare for more varied siting decisions by competitive suppliers.

INCREASING TRANSMISSION

ACCESS

Wheeling is the transmission of electricity from a

seller to a purchaser using the transmission facilities

of a third (or “wheeling”) party. A key feature

distinguishing wheeling from other electricity transmission is power ownership. Usually a utility owns

the electric power flowing on its transmission

system. The utility either generates the electricity or

purchases it from others and then transports it for

sale to customers. In wheeling, however, the wheeling utility neither purchases nor generates the

electricity being transported; rather, it accepts power

at one point and delivers it to another.

.

Wheeling allows both buyers and sellers of.

electricity access to expanded markets.22 A variety

of both purchasers and sellers may desire transmis-

%uther, the choice of technologies maybe shifted in favor of those with shorter lead times, although such a choice may occur without increasd

supply competition.

21M.J. ~tousek ~ W.J. LeBlm, “Bidding for Ekaric Resources: An Indusay Review of Competitive Bid Design and Evaluation,” prepared for

Electric Power Research Institute, November 1988; M.H, Rothkopf et al., Designing PURPA Power Purchase Auctwns: Theory and Practice,

University of California, LBL 23906

22W~]~g nom~ly ~vo]ves tie bulk ~wer sy~ems, but some sm~] n~uti]ity generators may be d~tly comected to the distribution system.
Chapter 5--Technological Requirements and Performance Under increased Competition . 137

Box 5-B—Bidding in Virginial

Status

In March 1988, Virginia Electric and Power Company (VA Power) solicited bids from qualifying facilities,

independent power producers, and other utilities for 1,750 MW to provide power to come on-line starting between

1989 and 1994. VA Power chose about 2,000 MW for further negotiation from the nearly 14,000 MW of received

bids. The accompanying figure breaks down the offers by fuel and generation type.2 Find contracts are now being

negotiated.

Approaches To Meeting Operating and Planning Needs

VA Power’s system uses several approaches to ensure that its planning and operating needs are met. These

include: minimum performance requirements and liquidated damages; a bid scoring system including various

nonprice factors; and additional incentives for dispatchability.

Performance Requirements and Liquidated Damages-Liquidated damages are to be paid if a project does

not come on-line and stay on-line as agreed. Performance requirements set limits on the number of days of forced

outage and standards by which a bidder’s compliance with dispatch orders are measured; capacity payments are to

be cut

●

●

●

●

●

if these performance requirements are not met. Some of the specific terms included are as follows:

Each successful bidder must pay $30/kW in “earnest money. ” If a facility does not reach commercial

operation within 2 months of the scheduled date, the bidder loses 10 percent of the earnest money in each

of the next 10 months if the project does not come on-line.

If a facility’s dependable capacity proves to be less than expected during testing (before commercial

operation), the bidder will pay a penalty of $30/kW of reduction.

If, during the life of the power plant, dependable capacity is less than 90 percent of what was expected, the

bidder will pay a penalty of $21 .60/kW of reduction; this penalty is increased each year to keep pace with

inflation.

A penalty of 4 percent of the capacity payment each year is imposed for each day of forced outage beyond

an established limit. The limit is the greater of 25 days or 10 percent of the days operated under dispatch.

(This is an indirect encouragement to offer full dispatchability.)

A penalty of 10 percent of the capacity payment each month is imposed for each time the facility does not

operate within 5 percent of the dispatched level of operation; an alternative to this penalty is to declare the

incident equivalent to a forced outage day.

Scoring System—The bid evaluation system accommodates VA Power’s planning and operating needs by

including a variety of nonprice factors. Explicit numerical values were not assigned to specific nonprice factors,

although the general factors to be taken into account were listed and given a weight. The factors noted for bid

evaluation and their relative weights were:

●

●

●

●

70 percent weight to price.

10 percent weight to project viability. This includes factors such as level of development and the experience

and financial status of the bidder.

10 percent weight to fuel type. VA Power used this category to express its preference for fuels with stable

prices (e.g., coal) and for projects that used instate fuels.

10 percent weight to other factors including location of the project in terms of its proximity to load centers

and transmission lines, and extent of dispatchability.

l~e ~atena~ ~ ~i~ ~x is &an pri~]y f~ C.R, R~ch, “competitive ~ummmt of Generating Capacily: Summary of procedures in Selected

States,” contractor report prepared for the Office of Technology Assessment, December 1988,

2Electric Utiii(y Week, June 2.0, 1988, p. 19.

Continued on next page
138 ● Electric Power Wheeling and Dealing: Technological Considerations for Increasing Competition

Continued from previous page

Dispatchability Incentives and Requirements-Dispatchability received only slight encouragement from

the bid evaluation: it is just one of six factors which, as a group, have 10 percent of the weight in evaluation.

However, other incentives were given to bidders encouraging them to operate under full economic dispatch.3 These

incentives include the following:

● Dispatchable bidders were allowed to index their fuel prices to actual energy prices, Nondispatchable bidders

were eligible only for a fixed (and thus riskier) price for a price tied to VA Power’s lower cost units.

. As noted above, by offering dispatchability, a bidder limits the extent of performance penalties for forced

outages. For example, a fully dispatchable plant would be allowed 36 days (10 percent of the year) of forced

outages before a penalty is imposed, rather than the standard of 25 days.

3~ tie Pro$orm c~c[, d.ispatchabihty is defied with [he following requirements: 6-hour notice for start-up and shutdown, ~d s-minute nolice fm

changes in the level of operation. All facilities over 100 MW were requued to be equipped for automatic generation controt.

sion access. Without transmission access, an IPP or

QF can only sell its power to the local utility that

owns the transmission system. Similarly, a utility

with competitive supplies cannot sell to the retail

customers of neighboring utilities or to distant

utilities unless access is provided through the

intervening transmission system.

When power is wheeled to a utility for resale to its

customers, the transaction is called “wholesale

wheeling.” Vertically integrated utilities may use

both short- and long-term wheeling arrangements to

displace their own existing or planned generation.

Utilities with little or no generation of their own (in

this report, called “requirements utilities’’ 23) may

use wheeled power to displace generation from the

local generation and transmission utility. “Retail

wheeling” is the delivery of power from a generator

other than the local utility to an ultimate consumer

such as a large commercial or industrial user.

To a large extent, the challenges in creating new

methods of coordination revolve around developing

workable definitions of obligations and rights of all

parties and the institutions to carry them out. For

example, when a retail or requirements utility

chooses a distant supplier, does the local utility have

an obligation to serve if those customers return?

How much advance notice will purchasers and

suppliers need to give the transporter? If the

nonutility supplier fails to deliver power, does the

wheeling utility have to provide back-up power?

These definitions of rights and obligations, while

critical for determining technical feasibility and

economic impact, also raise fundamental questions

of equity and appropriate levels of cooperation.

A wide variety of wheeling arrangements are

possible, depending on the types of power suppliers,

purchasers, and transporters and specific agreements

among them (see boxes 5-E, 5-F, 5-G). Wheeling

agreements must specify the amount of advance

notice and other conditions under which the transporter can halt a transaction. The duration of

wheeling arrangements may vary from hours to

years. The amount of advance notice buyers and

sellers must give the transporter before increasing or

decreasing the amount of power to be wheeled may

also vary.

The technical challenges and the likely cost and

reliability impacts of increased wheeling depend on

the buyers, sellers, and transporters and on the type

of service being provided by each and their mutual

obligations. The ability to accommodate increased

wheeling also depends on the volume of transactions

envisioned.

Increased wheeling poses new challenges for

operation and planning. In today’s power system

operations, coordinated unit commitment and dispatch procedures perform several functions. They

ensure that both real and reactive power needs are

met and they provide sufficient ready or spinning

reserves to following changing loads and prepare for

zsRwuiremcn~ uti]itie~ ~i~ some of heir own generation are called partial requirements utilities. Those with no generation of tiir on me c~l~

full requirements utilities.
Chapter 5-Technological Requirements and Performance Under Increased Competition ● 139

Box 5-C’-Bidding in Californial

Status

The heart of California’s bidding procedure is a long-term power purchase contract, referred to as the Final

Standard Offer Number 4 (S04).2 S04 requires a‘ ‘price-only bid” competition through a‘ ‘second price auction. ”

Price-only competition means that the only variation among the bids is the price offered. Nonprice factors such as

dispatchability and siting are not included. A second price auction means that all winning bidders are paid the same

price, specifically, the price offered by the first losing bid.

Because there has been no need for additional generating capacity in the State recently, the bidding procedure

has not been used yet. The agreed-to S04 is the contract that will be used when generating capacity is needed and

a bid solicitation is announced. However, the investor-owned utilities in the State are now mounting an effort to

change the basic bidding regulations underlying S04. The investor-owned utilities propose a change to the bidding

system to include both price and nonprice factors. A switch to a first price auction has also been proposed.

Approach

The California bidding system has no numerical ranking which places explicit value on operational and

planning needs. This does not mean, however, that these nonprice factors are not taken into consideration.

California’s system reflects nonprice factors through minimum requirements that must be met by all bidders and

financial incentives for additional performance features. These requirements and incentives of the S04 contract are

discussed below.

Project Milestones

Each successful bidder must provide a $5/kW project fee to be refunded upon project completion. project

milestones are set which track the project development; from securing a site, through initial construction, to

beginning operation. If a milestone is missed, the $5/kW project fee is forfeited and the utility may terminate the

contract.

Liquidated Damages

Suppliers under firm capacity contracts are liable for liquidated damages if they default on the contract, or if

they reduce the level of firm capacity. Liquidated damages are meant to compensate the utility for losses it incurs

because the supplier does not deliver capacity and energy as contracted. If a supplier defaults on the contract or

reduces the firm capacity rating, it must pay an amount equal to the utility’s replacement cost for the energy and

capacity.

Minimum Performance Requirements and Bonuses

For firm capacity contracts, the full payment is made on the facility’s full capacity only if specific performance

requirements are met. The primary requirement is that the facility achieve at least an 80 percent capacity factor

during the on-peak times-of-day of each peak month. If the facility fails to meet this requirement its firm capacity

will be derated after a probationary period. Alternately, if the supplier substantially maintains a capacity factor of

85 percent or higher, the utility pays a bonus.

Curtailment Requirements and incentives

Curtailment is a form of limited dispatchability. Under S04, suppliers must agree to have their generation

curtailed under certain circumstances. Suppliers are required to choose one of two forms of curtailment. Under the

first, a supplier maybe curtailed in cases of “Hydro Spill” or “Negative Avoided Costs. ” (Hydro Spill conditions

occur when low system demand forces the utility to allow water to pass an unloaded turbine in order to reduce

generation. Negative Avoided Costs are said to be incurred when the utility’s high-cost units are at their lowest level

of operation and the acceptance of further nonutility supplies would actually lead the utility to incur higher costs).

If either Negative Avoided Cost or Hydro Spill conditions exists, the supplier must reduce generation to 30 percent

of capacity or less. No energy payments are made during these curtailment periods.

i~mat~a[ in fis box is drawn primarily fran Boston Pacific CO., k., “Competitive pKKIM~ t of Generating Capacity: Summary of Procedures in

Selected States,” contractor repon prepared for the Office of Twhnology Assessment, Deamber 1988.

2fie ~KM~lm h-is bm~ ~ tie Sm ~m~ac[ ~g~la[~ by t~ ~ll]iti~s, private power pro&wms, and Commission staff as of Jtme 1988.

ConMud on next page
140 ● Electric Power Wheeling and Dealing: Technological Considerations for Increasing Competition

Continued from previous page

The second curtailment option allows the utility to curtail the supplier’s generation up to 1,500 hours per year

during off-peak and super-off-peak periods, No more than one curtailment can be imposed in a single day and the

curtailment period cannot be less than 3 hours. Curtailments can be imposed during periods of Negative Avoided

Cost. Economic curtailments can also be imposed; in these cases, energy payments are based (generally) on actual

utility incremental costs. Supplier’s choosing this second curtailment option receive higher energy prices in other

off-peak and super-off-peak periods than those choosing the first option.

Adders, or Incentives for Other Performance

Additional payments by the utility can be negotiated to gain features such as greater dispatchability and for

reactive power support. An early CPUC Decision ordered the utilities to consider the payment of “adders” if

additional performance features are requested from suppliers beyond those in the S04. The specific list of adders

is as follows: emergency availability; black start capability; reactive power support; scheduled maintenance;

real-time pricing; prescheduled dispatch; and full dispatchability. A later CPUC Decision created the possibility of

“subtracters” as well. These payment adjustments would be based on a comparison of the performance features

offered by the supplier through its contract to the performance features offered by the utility resource assumed to

be avoided; adjustments maybe upward or downward, Final details have yet to be worked out.

equipment outages. Finally, these functions minimize operating costs while remaining within the

constraints imposed by the generation and transmission system capabilities.

By reducing the centrally coordinated control of

generation, increased wheeling raises the possibility

of less economic operation and reduced reliability.

Reduced economics and operation problems are the

same concerns that may result with improperly

integrated competitive supplies discussed in the

previous section. However, expanded transmission

access adds new complications.

As the number and magnitude of wheeling

transactions increase, scheduling use of the transmission will require increasingly accurate and objective analytical methods. In particular, calculating

transmission capacity will be critical as was discussed above under long-term planning. The use of

a local utility to provide load following capacity may

also result in disagreements about the cost of

providing spinning reserves, load following, and

regulation services. More accurate methods of

determining the cost of these services will then be

required.

The following sections examine how wheeling

may effect the functions of following load, coordinating transactions, and maintaining reliability.

Load Following

Frequency Regulation

Providing frequency regulation has a relatively

small direct cost, assuming sufficient coordinated

control has been obtained, and should not prove to

be a very challenging requirement. Assuming the

correct amount of regulating capacity has been

acquired and brought under coordination of the local

control area as discussed above, wheeling should

add little complication. However, use of wheeled

power will displace generation within the purchaser’s control area. This may result in shutting

down units during light load times, reducing the

regulating capacity available.

Frequency regulation must be provided by the

control area entity, whether that is an integrated

utility (scenarios 1, 2, and 3), or the transmission

company (in scenarios ,4 and 5). Even with

increased telemetry between individual sellers and

buyers to keep each informed about the other’s

performance, the ability of an individual generator to

exactly match load is limited since loads can

typically change faster than an individual generator.

Also, because fluctuations in individual loads tend

to offset each other, the larger the power system

being regulated, the smaller the fraction of regulating capacity required.
Chapter 5-Technological Requirements and Performance Under Increased Competition ● 141

Box 5-D—Bidding in Main1

status

Established in 1984, Maine’s bidding system is the oldest in the United States. Four Requests for Proposal

(RFPs) had been issued by the end of 1987 and 78 contracts had been signed for a total of 500 MW. Operational

projects total 275 MW, and another 222 MW were expected on-line by 1991. In its June 1987 solicitation, Central

Maine Power’s (CMP) solicited 100 MW and received 1,444 MW in actual bids. CMP’S June 1987 solicitation is

the basis for this discussion,

Approach

CMP’s system has three main components. These components, prequalification (or screening); bid evaluation;

and liquidated damages; are used to select new capacity to meet CMP’s operating and planning needs.

Prequalification or Screening

CMP asked bidders to demonstrate their ability to construct and operate the proposed facility. The screening

requires that a bidder present substantial evidence that the project is well along in areas such as engineering design

and permitting, fuel contracting, and financing.

Scoring System

To accommodate CMP’s planning and operating needs, the bid evaluation system considers a variety of price

and nonprice factors. The value of the nonprice factors was explicitly quantified using six scoring indices. Each

index had a base value of one, so all respondents started with a score of six,

. Price Index: This index reflected the extent to which the bidder’s price was below CMP’s forecasted avoided

cost. For each percent discount offered by the QF, its score is increased by 0.1 points. For example, a 10

percent discount would add a full point to the score.

. Capacity index: An additional point was added to the score for bidders providing reliable firm capacity. To

obtain the point, the bidder must meet NEPOOL’s test for firm capacity and (for thermal units) commit to

high on-peak performance or (for hydro units) agree to a semi-annual capacity audit and to a minimum

generation level.

. Operating Index: Dispatchability earned an additional 0.3 points. Coordinated maintenance scheduling

earned 0.2 points more. Finally, scheduled operation favoring peak periods was rewarded by up to 1.5 points.

. Security Index and Endurance index: These indices rewarded bidders that took steps to reduce the risk to

CMP of future project nonperformance. Bidders that set up a security fund to cover the utility’s cost of

replacing the energy and capacity if the facility does not operate as contracted scored up to 0.5 points.

Bidders that did not require levelized payments (i.e., payments exceeding the forecasted avoided cost in any

year) or provided a security fund received up to 1.5 points.

. On-line Index: This index encouraged bidders to come on-line later in the 1990’s. An additional score of

0.05 points is given for each year the Initial Delivery Date is set beyond 1990.

Liquidated Damages

Winning bidders are subject to penalties, or liquidated damages, if they do riot perform as contracted. The

payments for liquidated damages are an attempt to make the QF responsible for the cost of replacement energy and

capacity if that QF falls short on providing capacity and energy as planned, or if the contract is terminated. A

standard long-term contract specifies damages in cases such as capacity shortfalls during peak periods; energy

deliveries below the guaranteed minimum; and abandonment of the contract.

l~e maten~ ~ ~s box is drawn primarily from Bostort Pacific CO., IIIC., “Competitive Procuswnent of Generating Capacity: Summary of Procechl.res in

Selected States,” contractor report prepared for the Office of Technology Assessment, December 1988.

Cyclical Loads . feasibility for retail consumers and full requirements utilities,

The need to follow cyclical loads raises four . impact on the economy of operations,

issues for wheeling in addition to those described for . control center limits, and

competitive supplies. These are: . transmission scheduling.
142 • Electric Power Wheeling and Dealing: Technological Considerations for Increasing Competition

Box 5-E-Southwest Bulk Power Market Experiment

In December 1983, FERC approved a 2-year experiment in bulk power marketing and transmission access

involving six utilities in the Southwest. ’ The experiment was intended to determine the economic efficiency gains

and competitive impacts of modifying FERC’s regulation of coordination transactions-transactions between

utilities with their own generating capacity. Transactions involving distribution utilities with little or no generation

were not addressed. There were no apparent concerns or problems with the technical feasibility of implementing

the experimental power transactions and transmission access.

In the experiment the participants were allowed substantial freedom in setting prices for “economy energy”

(for interruptible sales from hour to hour up to 30 days) and “block energy” (for sales extending at least one month).

Prices were allowed to range from 0.9 ¢Wh to 9.4 ¢/kWh. The utilities were allowed to retain 25 percent of the

resulting savings as profit, with the remaining 75 percent flowed through to customers. (Traditional regulation

requires 100 percent of such savings to be passed on to customers). Further, the utilities agreed to provide

transmission access (up to technical limits) at a fixed price of O. 15¢Wh, and thus not prevent trades involving other

participants.

FERC contracted with the Rand Corp. for technical assistance in evaluating the experimental design proposed

by the utilities; assessing the usefulness of the data; and analyzing the experimental results.2 Rand published first

year results in October 1985. The analysis of economic efficiency impacts was inconclusive: “Our findings with

respect to efficiency are decidedly mixed, and vary depending on the analytic technique selected. . . . By some

measures, efficiency increases under the experiment; by others it is unchanged or falls by a statistically significant

amount.”3 Rand noted that the first year findings were possibly unrepresentative for several reasons.

According to Rand’s first year report, the second year was expected to be more representative of the efficiency

gains resulting from the experimental regulatory changes. Results of the experiment’s second year have not been

published to date.

l~ou~we~t /7Ver~m, FFRC @inlm NO. ~3, ~kei No. ER84-155~, ~, ~, 1983. me six utilities were Arizona Public s-ice; the City Of

Fanningtut; El Paso Electric; Public Service Company of New Mexico; Salt River Reject; and .%uthwestcm Public Service (which began participation in the final

3 months of the first year.

2~e Rmd Cq.~ovl~ ~ ~~isW ~~ t. ~RC bef~ the exx~ WSS appmv~. The R~ Crop., ]SSWS in f)w Design cfu hfarket Experiment

for Bulk Electrical Power, December 1983.

3~. ~tm ~ s. Be=, Regulation, E@~Ky, ~ CoWe[ltion in t~ &~nge of E[ectrkiq: Firsl year Results From the F15RC Bulk Power Markt

Experiment/, The Rand Ctxp., October 1985, p. vii.

Retail Consumers and Full-Requirements Util- require either: 1) the purchaser to accurately forecast

ities-Following the load cycles of retail customers

and full-requirements utilities with wheeled power

may prove difficult. For vertically integrated utilities (scenarios 1, 2, and 3), purchasing wheeled

power presents no significant problem since they

have the capability to follow their own loads.

Similarly, control-area size transmission and distribution utilities (scenario 4) or distribution-only

utilities (scenario 5) that buy power from individual

generation companies with large amounts of supplies should have no problems beyond those described above under competitive supplies for generators within the control area.

However, for small full-requirements utilities and

retail customers, following actual load cycles will

loads far enough in advance to arrange a schedule

with the supplier; or 2) the supplier to monitor the

purchaser’s loads and adjust output accordingly.

Failure to meet one of these requirements will result

in an over- or under-supply of wheeled power. This

would have to be accounted for with the local

control-area utility and may result in increased

spinning reserves for frequency regulation. Accounting for transmission losses further impedes the

ability to match supply with individual loads. The

dependence of losses on ever changing system

conditions and the possibility that some transactions

may actually decrease losses add to the difficulty.

Impact on the Economy of Operations-With

increased levels of wheeling in which individual
Chapter 5--Technological Requirements and Performance Under Increased Competition ● 143

Box 5-F—Western Systems Power Pool:

A Current Experiment in Transmission Access and Bulk Power Pricing

In March 1987, the Federal Energy Regulatory Commission (FERC) accepted another 2-year bulk power

marketing experiment, called the Western Systems Power Pool (WSPP).l The WSPP experiment began on February

1, 1987. Like the Southwest Experimen~ the WSPP experiment is intended to determine whether more flexible

pricing and greater information sharing will promote more efficient use of generation and transmission facilities and

reduce costs to consumers. As with the Southwest experiment, there have been no apparent concerns or problems

with the technical feasibility of implementing any of the experimental power transactions, including transmission

access.

There are several differences between the WSPP experiment and the Southwest Experiment. One principal

difference is transmission access. The WSPP provides only for voluntary transmission service and gives substantial

pricing freedom to the transmitting utilities. Transmission access prices are allowed to range from 0.1 ¢/kWh to 3.3

¢/kWh. In contrast, the Southwest Experiment provided mandatory transmission access (subject to availability) at

a fixed price of 1.5 ¢/kWh. Thus, according to FERC, the WSPP experiment will examine ‘‘whether mandatory

transmission access is a prerequisite to a competitive market. ”2

WSPP also allows a much wider range of prices for generation than did the Southwest Experiment. In the

WSPP experiment’s first year, prices were allowed to range up to 24.5 ¢/kWh, compared to the earlier experiment’s

cap of 9.4 ¢/kWh.

Size is another difference between WSPP and the Southwest Experiment. WSPP is very large, including over

20 utilities in 10 Western States. The utilities in this region produce about 12 percent (82,000 MW) of the total

electric generating capacity of the United States. That is substantially larger than the Southwest Experiment, which

was open to six utilities in three States, with under 13,000 MW capacity. To implement the experiment over this

large group of utilities, the WSPP experiment uses a computer “bulletin board” into which buy and sell offers are

placed each day.

The experiment is scheduled to conclude on May 1, 1989, but the participants have requested a 2-year

extension. As a condition of FERC approval, the participants are required to produce interim and final reports

examining economic efficiency impacts and potential monopoly power. The interim report does not draw

conclusions on these issues due to a lack of data.3 However, the report notes that some transmission owners are

holding less transmission in reserve for their own uses, resulting in increased availability to others.

lmder ~cep[mg Experimental Ra[es for Filing, FERC Docket No. ER87-97-(XI1, Mw. 12, 1987.

21b]d., p. 3.

~T.w. K=l~ et al, we~lern s~~te~ power p~o[A~~e~s~ent In[er(m ~eporl (M~10 Park, CA: Strategic Decisions (hup, January 1989).

purchasers and sellers specify generation patterns, economic dispatch and scheduling. Wheeling of

the control area’s options; for economically scheduling and dispatching generation will be less flexible

and less responsive than they are currently. A likely

result is increased operating costs.

In particular, overall system economic impacts of

scheduling constraints will be exacerbated if a large

number of relatively small wheeling arrangements

specify the dispatch and unit commitment of independent suppliers. For this reason, wheeling for

retail customers (scenarios 2 and 5) and for smaller

utilities, particularly those without generation (scenarios 2 through 5), are most likely to affect

power to integrated utilities (scenarios 1,2, and 3) or

to large transmission and/or distribution companies

(scenarios 4 and 5) should not have the same

negative impact.

Control Center Constraints-A third complication for following cycling loads introduced by

wheeling is a limit to the number of generators and

wheeling transactions that can be handled from any

control center. If the number of transactions increases significantly (most likely in scenarios 2 and

5; possible in scenarios 3 and 4), control center

equipment, personnel, and procedures will have to
144 ● Electric Power Wheeling and Dealing: Technological Considerationsfor Increasing Competition

Box 5-G-Innovative Transmission Access:

Turlock Irrigation District

In June 1988, FERC approved a novel agreement under which Turlock Irrigation District gained transmission

access to a number of competing power suppliers. 12 In exchange, Pacific Gas and Electric (PG&E) gained a Pricing

system allowing it to retain more of the savings from coordination transactions than were previously allowed. PG&E

also gained release from responsibility to provide power and transmission beyond which it committed itself

contractually. 3

Turlock is a partial requirements utility, with capacity of approximately 157 MW and peak loads of

approximately 266 MW in 1988. According to FERC, ‘‘Turlock has always been a captive customer of PG&E due

to its reliance on the PG&E transmission system. ”4 Under the new agreements, Turlock will have “reserved

transmission service” providing 176 MW of import access to three other northern California utilities and to

Southern California Edison at cost-based prices. Together with its own capacity and approximately 5.3 MW of firm

capacity from PG&E, this gives Turlock sufficient resources to meet its own load. In addition, the agreement allows

PG&E and Turlock to negotiate “coordination services. ” The coordination services would allow Turlock to pursue

short-term purchases with PG&E and other utilities when low-cost opportunities exist. In addition, the agreement

covers such provisions as charges for unauthorized power flows, voltage regulation, scheduling, and regulation

services.

FERC’S order of approval noted uncertainty and some concern about “whether PG&E may exercise any

leverage over Turlock because of its control over Turlock’s transmission access to other suppliers. ” The agreement

is not an experiment, however, and no formal mechanism has been instituted to determine whether such leverage

is exercised.

Finally, it’s worth noting that neither FERC, nor PG&E, nor other interveners expressed concern with the

technical feasibility of reliably implementing the agreement.

lpm~c GUS &Electric, FERC Docket No. ER88-2194W, Miu. 31, 1988.

2parw cm ~E/ectr~, ~RC Ihxket No. ER88-219-MII, J~ 1, 1988.

3~RC a~wda similar tr ansmission access and pricing agreement between Modesto Inigation Distric[ and PG&E in July 1988. Pacific Ga and Electric,

FERC Docket No. ER88-302~1, Juiy 5, 1988.

epmf~ GUS and Electric, op. cit., Mar. 31, 1988, p. 10.

be upgraded. The cost and reliability of control

center upgrades to accommodate increasing numbers of transactions will be location specific. Increases in the volume of wheeling transactions,

especially those whose levels change frequently,

have already led to changes. For example, Houston

Lighting and Power has added an energy scheduler

to the dispatch staff, with over half his time

dedicated to handling the effects of cogeneration and

wheeling cogenerated power.24

control. With few exceptions, scheduling the use of

transmission is not a significant problem today. If a

utility has a transmission bottleneck, as many do, it

selects an alternative (although less economic)

generation dispatch which avoids the constraint. The

options for different dispatch patterns are limited

mainly by the operating capabilities of the generators. The ability to choose a variety of generation

patterns is critical for reacting to the complex and

uncertain changes in power flow requirements and

Transmission Scheduling-Finally, increased wheel- transfer capabilities that power systems face.

ing creates an expanded challenge for transmission As wheeling increases, scheduling transmission

scheduling. In current power systems, following use independently of generation becomes increasloads while controlling voltage and power flows on ingly necessary, distinct from the current combined

the transmission system to remain within physical generation and transmission scheduling problem.

limits is performed in part through generation Generation scheduling constraints caused by wheelze~~tute of EIw~c~ ~d ~ww~ic Engineers, committee Report, “problems in Coping With the proliferation of Interchange Schedules,” IEEE

Trartsactwns on Power Systems, vol. PWRS-2, No. 4. November 1987, pp. 883-889.
Chapter S---Technological Requirements and Performance Under Increased Competition ● 145

ing arrangements will reduce ability to control

transmission flows. In particular, if purchasers need

wheeled power to follow changing and uncertain

loads, the uncertain and changing pattern of generation usage could create unanticipated transmission

loadings which would otherwise be avoided by

redispatching generation.

The more predictable the level of wheeling

transactions, the less challenging transmission scheduling will be. For example, with long-term fixed

patterns of power transfers, perhaps specified

through contracts, the transmission scheduling problem reverts to a transmission planning problem in

which new facilities can be developed as required

(assuming capacity can be built as required and

transmission owners can earn sufficient returns on

investment).

Transmission scheduling involves setting priorities for who gets to use the transmission system and

at what price. As wheeling transactions become

more common, setting these priorities and prices

will become increasingly contentious. These are

issues of both economic efficiency and equity, and

beyond the scope of this analysis.25 There is no

single technically correct solution to the priority and

pricing problems, although a variety of approaches

do exist. (See boxes on Southwest Bulk Power

Market Experiment; Western Systems Power Pool;

and Turlock Irrigation District). These demonstrate

that untraditional uses of transmission are technically feasible and that arrangements can be developed that participants view as acceptable.

The idea of using marginal cost-based prices to

allocate transmission capacity has received considerable attention. This method would have the effect

of allocating transmission use to those willing to pay

most for it. The marginal cost analyses are necessarily technical because of the complex physics and

engineering of power systems. 26 Among the efforts,

the United States Department of Energy and the New

York State Energy Research and Development

Authority have cosponsored development of public

domain computer software for examining the mar27 The software, called ginal cost of wheeling.

WRATES, incorporates such factors as transmission

losses, fuel costs, and the operational costs of

generation and line capacity limits.

Coordinating Transactions

As noted above, increasing the number of transactions requires additional metering, telemetry, and

telephone communication for the AGC. This is true

for wheeling between control areas as well as within

them. If the volume of transactions becomes large,

power control centers of the transporting utility will

need upgrading, and more dispatchers may be

required.

Also, AGC systems used to coordinate transactions are based on the current structure of utilities in

which control areas are clearly defined. Metering of

tie lines into each area is an integral part of these

systems and is easily accomplished. However,

implementing large numbers of wheeling transactions may require revisiting the concept of control

areas and AGC. In particular, the present concepts of

control areas and AGC may be strained to the extent

that wheeled power is used to continuously balance

load and supply for a large number of retail

customers or small full-requirements utilities. As

loads and generators become independent from

integrated utilities under retail wheeling or wheeling

to requirements utilities, they can in concept become

separate control areas purchasing and selling power

using interchanges with the transmission system.

Maintaining Reliability

Security

With or without wheeling, maintaining system

security depends on carefully coordinated control of

generating units as described earlier. This control is

needed both to schedule generation and transmission

reserves and to redispatch generation and transmission following contingencies. Wheeling extends two

issues beyond those previously described. These are:

Msm National Rew]atoq Re~arch ~5titu@ (mRI), SOW Economic Principlesfor Pricing Wheeled power (Columbus, OH: WI, August 1987).

Msa, for exmple, ibid.; F.C. Schweppe et ~.~ “Wheeling Rates: An Economic-Engineering Foundation, ” MIT Lalmratory for Electromagnetic

and Electronic Systems, Report TR 85-005, September 1985; and F.C. Schweppe ct al., Spot Pricing of Electricity, op. cit., footnote 16. H.M. Merrill,

“Economically Efficient Allocation of New York’s Transmission and Distribution System, ” Power ‘Rxhnologies, inc., June 1985.

27M.C. Caramanis et al., ‘WRATES: A Tool for Evaluating the Marginal Cost of Wheeling,” IEEE 88 SM 649-6, IEE4PCS 1988 Summer Meeting,

hdy 24-29, 1988.
146 ● Electric Power Wheeling and Dealing: Technological Considerations for Increasing Competition

setting transaction priorities, and measuring transmission availability.

Setting Transaction Priorities-There is simply

no way to maintain reliable operations unless

wheeling is subject to availability of transmission

capacity. The same is true of any use of transmission.

Even if a wheeling transaction is scheduled, contingencies may occur that require curtailing the transaction. Any wheeling agreements, whether mandatory

or voluntary, must recognize this reality (as is the

case in all of OTA’s scenarios). Thus purchasers of

wheeled power must have either aback-up supply—

either their own or purchased-or be willing to risk

not meeting loads. (Note that curtailing a transaction

does not equate with curtailing the load if back-up

supplies have been arranged.)

As wheeling transactions become more common,

determining which transmission uses to curtail or

continue when transmission limits are reached, and

determining the appropriate price of back-up supplies may become increasingly contentious. As with

setting priorities and prices for transmission scheduling, these are issues of both economic efficiency

and equity, and beyond the scope of this analysis.

However, the technical requirements of operating a

power system mandate that these issues be addressed.

Measuring Transmission Availability-lncreasingly accurate measures and definitions of available

transmission capacity will be required. Without

accurate measures of capacity and costs, conflicts

between those who want to wheel and transmission

system managers will undoubtedly arise. Regulatory

authorities may not have sufficient credible information on which to render decisions.

Recall from chapter 4 how available transmission

capacity is measured today. There is no simple

equivalent of the telephone company’s busy signal

on a power network. Transfer capacity is not the

rating of a single line or a few lines. It is a function

of the strength of the network as a whole. Transfer

capacity depends on reliability criteria, which are

selected somewhat subjectively. It varies as switching operations occur and as demand, generation, and

transmission patterns change. Loop flows and actions taken by operators of other systems affect the

available transfer capability. Furthermore, developing estimates of transfer capability requires a lot of

engineering time and cooperation among all parties

involved.

Transfer limits today are determined by complex

system studies based upon reliability criteria established by mutual agreement among power system

engineers. This is a satisfactory arrangement as long

as the parties involved understand and trust each

others’ judgments. As the number of competing

generating entities and wheeling transactions increases, there may be a greater need for more easily

calculable and verifiable assessments of available

transmission and transfer capability.

Adequacy

Long-term planning involves ensuring that adequate transmission and generation resources are

available for operation. To the extent that wheeled

power will be used for long-term supplies, expanded

transmission access raises one crucial long-term

planning issue in addition to those resulting from

increased bulk supply competition. It is the prospect

of increased planning uncertainty.

Increasing Planning Uncertainty-As increased

wheeling allows power purchasers to buy from a

greater number of suppliers, confusion regarding

who will supply power to whom could exacerbate

other capacity planning uncertainties. The result

may be either under- or over-estimates of capacity

needs for both generation and transmission.

Mandatory wheeling to retail customers (possibly

in scenarios 2 and 5) raises the most critical source

of uncertainty. Because of the long lead-times

needed to build generation and transmission facilities, lack of sufficient advance knowledge of the

plans of retail customers who may wish to obtain

their power from outside sources could result in

inadequate transmission facilities and excessive

generation. Alternately, if a utility incorrectly assumes that a retail customer will obtain power

through wheeling, excess transmission capacity and

insufficient generation could result. For these reasons, advance notification of requests for wheeling

and subjecting wheeling to transmission availability

is required. A system of “transmission access on

demand” or unrestricted access can not be implemented. (Note that none of the OTA scenarios

include such unrestricted access.)
Chapter 5--Technological Requirements and Performance Under Increased Competition ● 147

Wholesale wheeling and voluntary retail wheeling pose relatively few planning problems since

there should be little confusion about who has

obligations to acquire adequate power supplies.

However, in every case, increased competition may

reduce incentives for cooperative planning between

utilities, generators, and customers, with a resulting

increase in uncertainty and the inability to plan

optimally.

As with competitive supplies alone, long-term

contracts provide one instrument to communicate

needs and define obligations of suppliers, buyers,

and transmission systems. By specifying prices and

performance, including penalties for failure to perform, long-term contracts can help ensure that

competitive supplies meet power system needs and

mitigate uncertainty for both parties. The allocation

of risks and responsibilities between the power

system and competitive suppliers under long-term

contracts depends in part on performance and

pricing terms.

CURRENT UTILITY

PERFORMANCE

The cost (and the benefit) of implementing

increasing competition depends largely on how the

economy of current utility planning and operations

are affected. This section briefly reviews current

performance.

Individual Utilities

Most utilities appear to operate their plants

efficiently, although that is difficult to ascertain.

However, there is some indication that the quality of

economic dispatch varies between utilities, although

conclusions are difficult to draw. Consider a study

performed by Philadelphia Electric Company for the

Electric Power Research Institute. 28 That study

found that different utilities had significantly different practices of monitoring the actual operating

efficiency of their generators, resulting in slightly

less than optimal economic dispatch.29 If dispatchers

believe that a suboptimal plant is operating at peak

efficiency, they may call on it in preference to one

that is actually more economic.

Units are maintained regularly to keep generation

capacity operating efficiently, although there is a

marked difference in the availability of otherwise

similar plants owned by different utilities. Part of

this difference is apparently due to differing maintenance programs.

30

Utility planning and addition of new capacity has,

in hindsight, often resulted in expensive and unneeded facilities. Still, the ability of independent

power producers to outperform utilities in construction, maintenance, and operation of generators is yet

to be determined, as is the impact of competition on

planning uncertainty and planning practices.

Interutility Coordination and

Power Pooling31

Interutility transactions are essential to minimizing operating costs of the U.S. power system. There

appears to be a regular and increasing tendency on

the part of systems with higher operating cost

capacity to seek out more economic sources of

power to purchase. The growth of imported power

from Canadian sources to displace higher cost, oil

fired generating capacity and to meet growing loads

is a well known example, as are the increasing bulk

transactions described in chapter 6.

However, there are some indications that economic interutility transactions, while high, could be

substantially improved.32 Proposed mergers be28ph11~lPh1a E]~~~ Co., /reproved Eco~mic Dispatch ~f~~wt~ ,’$ysle~ (P~o Alto, CA: Elwttic Power Research Institu(e June 1982), EPRI

EL-2461, VO]. 1.

z9That study ~SO identifi~ oppo~unitics for improved economic dispatch from more frequent monitoring. h is wo~h noting tiat the study was

undertaken in the late 1970s, before significant competitive pressures were being felt. reflecting the indusuy’s ongoing activities in identifying and

developing areas for increased efficiency.

30SW ~r Cxmple, U.S. Congess, office of mCtmOIOH Assessment, Nuciear Power in an Age M fJncertiiW. OTA-E-216 (Springfield. VA:

National Twhnical Information Service, February 1984).

sl~e mate~~ in ~is ~tion is drawn from Power Technologies, Inc., ‘‘l’ixhnical Background and Considerations in Proposed Increased Wheehng,

Transmission Access and Non-Utility Generation, ” OTA contractor report, March 1988, unless otherwise referenced.

32sW, for exmple, E,J, Tirel]o, Jr. ~~ M, WOI-ITIS, Electric U?ifities: The Casefor Consolidation, Shearson LehmanHuttonE4uitY Rescarcht Much

1988. That study concluded that cost savings of $2,6 billion per year could be obtained through more efficient economic dispatch artd maintenance

procedures alone. See also, Federal Energy Regulatory Commission, Power Pooiing in rhe Unired Srares, December 1981.
148 . Electric Power Wheeling and Dealing: Technological Considerations for Increasing Competition

tween utilities indicate that some utilities believe

that coordinated operations and planning could be

improved. For example, SCEcorp (parent of Southern California Edison) in supporting its proposed

merger with San Diego Gas & Electric noted that

“Major cost savings are anticipated through more

efficient use of generation and deferral or elimination of capital expenditures. ” In addition there

would be staffing reductions. Projected savings from

operations are $100 million annually and about $350

million in capital spending within the coming

decade. 33 Similar projections of savings have accompanied other merger proposals such as that

between Utah Power & Light and Pacific Power&

Light.

There are a number of regions where centrally

dispatched power pools coordinate plans for system

development and operate systems economically to

reduce both long-run investment costs and short-run

operating costs. These have taken the form of power

pool agreements among unaffiliated utilities and the

coordinated operation and planning of large utility

holding companies. These existing operations offer

one example of a practical and tested way of

improving overall efficiency of the utility systems in

other areas. One recent assessment of interutility

coordination found that annual savings exceeded

$15 billion—about three-quarters resulting from

reduced capital investments with the remainder due

to fuel cost savings.34

These economic gains are substantial. They could

perhaps be augmented with an increased level of

power brokering, pooling, and central dispatch

systems. These approaches involve cooperation as

well as competition. The benefits of pooling are

balanced by responsibilities of pool members to deal

openly and fairly with each other and to exchange

data freely concerning future load projections,

expansion plans, and operating costs. Centrally

dispatched power pools require investment in a pool

control center, communications and computer facilities, and the support of an adequate engineering and

dispatching staff. These are not inconsequential

costs. Ranges of initial costs for a large pool control

center have been informally given at levels of $10

million to $50 million. A support staff of 30 to 40

professional level people might require an ongoing

cost of $3 million to $5 million per year.

These costs must be compared to possible reductions in system expansion cost savings and annual

operating cost savings that may be obtained from a

central dispatch system for a large enough pool.

Coordinating operations on a pool-wide basis rather

than on an individual system basis means that the

most efficient units within the region are being used

to produce the energy required by customers on a

planned minimum costs basis. The consumers’ costs

are reduced overall by this production efficiency. A

system with a peak load of 10,000 MW and

fossil-fired generation could have an annual fuel bill

in excess of $1 billion per year. An operating cost

savings of one-half percent would be $5 million per

year; enough to pay for the pool operating staff costs

cited above.

A large portion of the savings from interutility

coordination are due to the reduction in facilities

required to handle the load growth in a region when

the interconnected systems plan and implement

system expansions on a coordinated basis. Installed

reserve requirements for generation are reduced

when systems substitute lower cost interconnection

capability that allows them to share generation

reserves for new generation capacity, This has been

done in all of the power pools over the years.

The pool planning organization, whether a holding company staff or a committee organized from

unaffiliated pool members, may plan for adequate

reliability and lower generation reserves by taking

advantage of the diversity in loads, the diversity in

both planned and forced outages, and by coordinating capacity additions so new facilities are installed

on a pool need basis rather than by each individual

system. Transmission plans can be studied and

implementations developed that will provide adequate transmission for exchanging power and energy

on a regular and emergency basis.

Arrangements can be made to allow the use of the

entire transmission system within the pool area for

the mutual benefit of all of the pool members. In

~3E[ectric utility Week, Aug. 1, 1988, pp. 7-8.

34J.A, C=za, ‘4FKX M~ket El~~City: potential Impacts On Utility Pooling and Coordination,’” Public Utilities Fortnighdy, vol. 121, No. 4, Feb.

18, 1988, pp. 16-23.
Chapter 5--Technological Requirements and Performance Under Increased Competition ● 149

most pools, ties are “free flowing,” eliminating the

requirement for complex wheeling contracts. If

transmission ownership is unbalanced, arrangements can be made to share transmission costs on a

relatively simple basis. New transmission capacity

may be planned jointly to develop optimal systems

at the lowest costs.

The individual systems must relinquish something for these benefits. They must support the pool

operation, both with sufficient funding and with

adequate engineering support. The operating arrangements mean that the most efficient production units

in the pool will be operated to supply customer

demands throughout the power pool. The owners of

these units must receive fair compensation and

energy purchasers must be charged a fair price. The

arrangements to accomplish this require negotiation

and time to develop and implement.

Individual system members of a pool must agree

to complete exchange of data and forecasts, which

has been encouraged by the generally noncompetitive environment that utilities have been operating in

to date. The members must be willing to coordinate

plans and system developments. They must agree on

generation plans and transmission system construction. They must be willing to surrender some of their

responsibilities in operations and scheduling to the

pool center. Finally they agree to coordinate plans

to:

● avoid system emergencies,

. coordinate corrective actions during emergencies, and

. restore service after an emergency occurs.

It is logical to ask why there are not more power

pools of affiliated and unaffiliated utilities. The

answer is not clear. The potential savings in operating costs do require a fairly large pool size to support

the annual costs of the pool operation. The individual utility may not escape the need for its own

operations control center by belonging to a power

pool of unaffiliated companies. (A holding company

may be different with all of the generation operated

by a centralized staff of the parent or one of its

service company subsidiaries.) A substantial portion

of the available operating savings maybe achievable

by other means such as economic interchange,

power brokers, or long-term interchange agreements.

TECHNOLOGICAL ISSUES

OF OTA’s SCENARIOS

This section examines technological issues raised

by increased competition as defined in OTA’s

scenarios. As discussed before, feasibility depends

largely on developing new institutional relationships between suppliers, consumers, and transporters which accommodate the need for coordinated operations and planning of the power system.

Implementing these new institutional relationships

will likely require adding some new physical facilities and improving analytical capabilities.

In examining the ability to accommodate competitive supplies and transmission access, the question is not whether it can be done, but how much is

feasible under what conditions without impairing

reliability and economics. There is no point at which

increased competition becomes clearly infeasible.

Rather, increasing competition expands the institutional modifications required and raises the uncertainty of success.

Any proposed change from the existing system

naturally raises uncertainty about how well the new

system will work. We know that the power system

of today does work, although some believe it to be

somewhat inefficient or inequitable.35 We also know

that the system is currently evolving and accommodating increased competition: Nonutility generation

and competition among suppliers is increasing

substantially in many regions of the country; transmission access is also increasing, although to a

lesser degree. The suppliers, transporters, and purchasers of power are defining institutional relationships and responsibilities which they feel meet their

individual and joint needs. However, we will not

know the actual impact of these changes on the

reliability and economy of the power system for

years to come.

The costs of implementing any scenario include

developing new operating and planning procedures,

adding new equipment and personnel to implement

the procedures, and possibly less efficient economic

35s= ~hS. 1 ~ou@ 3 of ~ls repofi for a dc~ription of the concerns expres~ over clurent industry performance.
150 . Electric Power Wheeling and Dealing: Technological Considerations for Increasing Competition

dispatch, scheduling, and planning resulting from

reduced coordination.

Scenario 1: Reaf’firming the

Regulatory Compact

The first scenario envisions little change in

industry structure. With no substantial, rapid increase in competition, existing operating and planning procedures will require only gradual evolution.

This raises no major challenges or uncertainties.

Existing State regulatory programs would be

modified to include ongoing approvals of major

construction projects. Except for meeting the requirements of project proapproval or rolling prudence

review, utility planning and operations would

evolve along the lines they are following presently.

It’s possible that proapproval could result in increased development of power plants with long lead

times and high capital costs. However, in an OTA

survey of 23 utilities, only a few indicated they

would consider revising their supply plans if given

prior approval. Several utilities expressed concern

over the risk of regulatory disallowances. However,

many indicated they either accept that risk and build

the generation most suited to their area’s needs or

believe that proapproval and rolling prudence would

not be effective in reducing risk.

Supply Competition

Nonutility generation would continue to be developed under PURPA. Modifying the rules for pricing

under PURPA would increase the likelihood that

operating and planning requirements, or nonprice

factors, would be reflected in avoided costs. These

nonprice factors are receiving considerable attention

today. Scenario 1 would encourage continued analysis of the requirements, costs, and benefits of

different levels of coordinated utility control of

dispatch and scheduling—both for load following

and for maintaining security. The impacts of nonutility generation on planning would similarly receive

continued analysis. For example, the requirements,

costs, and benefits of such factors as fuel type and

diversity, location relative to transmission facilities,

and construction lead time and risk would receive

continued attention. Utilities obtaining power from

IPPs-also allowed under this scenario-would

have to address these same issues of cost and value.

Transmission Access

Increased voluntary transmission access would be

encouraged, too, although in an unspecified way. It

is not known how effective these efforts will be to

actually increase access. Efforts to encourage utilities to provide additional voluntary transmission

access would likely involve continued analysis of

the costs of transmission service. For example, for

wheeling between vertically integrated utilities,

analyses would examine reliability-the adequacy

of and costs of transmission capacity; the costs of

spinning reserves; the system engineering of relays

and other protection devices—and the ability of

control centers to coordinate an increasing number

of transactions. For wheeling to small full requirements utilities, the costs and requirements of following changing loads-including frequency regulation

and following daily, weekly, and seasonal cyclesrequire examination as well. Retail wheeling, although unlikely, would require similar analyses.

Scenario 2: Expanding Transmission Access

and Supply Competition

Supply Competition

Under scenario 2, nonutility generation, including

IPPs, would be further encouraged. The resulting

change in costs and performance among competing

supplies is speculative. As in scenario 1, to the extent

that nonutility generation develops, nonprice factors

will require increasingly careful analysis. Again,

this will require site-specific analyses of the requirements, costs, and benefits of different levels of

central control of generation (e.g., scheduling and

dispatch for use in load following and maintaining

reliability). The technical-economic questions that

arise in system planning and operation will have to

be made explicit and acceptably understood to all

parties involved: utilities, regulators, nonutility generators, consumers, and other possible interveners.

This may be challenging, since expertise in detailed

areas of power system engineering and economic

analyses are required.

Transmission Access

The second scenario also leaves the vertically

integrated utilities in place. However, access to the

transmission system is expanded by allowing utilities and large retail customers to seek mandatory
Chapter 5--Technological Requirements and Performance Under Increased Competition ● 151

wheeling. It is not possible to determine how much

wheeling would result from implementation of a

“broad public interest standard” for wheeling. The

demand for transmission access will depend on the

type of service mandated (e.g., load following or

base load), the pricing of transmission service,

availability of transmission capacity, and the availability of lower cost bulk power supplies from

nonutility generators and remote utilities.

To the extent that transmission access is

mandated, the efforts in analyzing costs and availability of transmission services and developing

procedures for dispatch and scheduling for voluntary

wheeling, as discussed under scenario 1, would be

critical. The new wheeling orders would have to

address issues of developing priorities for transmission scheduling and for curtailing transmission uses

as contingencies occur. Provision of backup supplies

and spinning reserves for reliability and adequate

generation to follow changing loads must also be

addressed for wheeling to retail consumers and

requirements utilities.

Given the decreased authority of utilities to claim

transmission limits and set priorities for use of

constrained facilities (e.g., a rebuttable assumption

that the capacity to wheel exists places the burden of

proof on the utility), regulators must make provisions to ensure that significant degradation of

reliability and economy does not occur under

mandatory wheeling. Determining which wheeling

orders can be issued without exceeding a system’s

capabilities will require expertise and data in detailed areas of utility engineering and analysis,

including economic dispatch modeling, load flow

analyses, and contingency and stability analyses.

This expertise will also be required to give informed

judgments on the prices charged under wheeling

orders. Wheeling may require revising both generation and transmission system planning as new

patterns of loads and suppliers develop. Provisions

addressing the advance notification given by retail

and requirements utilities before switching suppliers

will need to be developed. Additional generation and

transmission reserves may be required to account for

any increased uncertainty or loss of coordinated

control in operating and planning.

Scenario 3: Competition for

New Bulk Power Supplies

Supply Competition

Scenario 3 creates a competitive market for all

new electricity supplies. Utility affiliates would be

able to ‘‘bid” to supply power in their own service

areas, with appropriate safeguards. Utilities would

remain the suppliers of last resort under traditional

rate-base regulation. This would further encourage

nonutility generation including IPPs. The resulting

change in costs and performance among competing

supplies is, again, uncertain. If competitive procedures prove more attractive than rate base supplies,

scenario 3 will eventually result in a generation

sector separate from transmission and distribution.

Utilities obtaining their new capacity through a

competitive process will face the same challenges

described under scenario 2. The technical requirements of analyzing the requirements, costs, and

benefits of different levels of coordinated control of

generation operation and planning, and developing

procedures to obtain that control, remain. Many of

these will need to be specified in advance of

solicitations so that they can be reflected in pricing

and evaluation. Again, included in the possible

changes is a need to increase reserves of both

generation and transmission as a response to greater

uncertainty. The uncertainty involves not only how

well generators will perform individually, but also

how well new institutional relationships for coordinating individuals will work.

Regulators and utilities will have a new and

challenging job in assessing the hard-to-quantify

value of supply characteristics such as dispatchability, fuel diversity, location, and likelihood of project

completion. As with mandatory wheeling, meeting

this requirement will call for expertise in detailed

areas of utility engineering and analysis, including

economic dispatch modeling, load flow analyses,

and contingency analyses, as well as system restoration, communications, and power control.

Transmission Access

Scenario 3 raises the same requirements and

challenges of mandatory wheeling discussed under

scenario 2. However, the extent of transmission

access and who it is available to differs. Again, the
152 ● Electric Power Wheeling and Dealing: Technological Considerations for Increasing Competition

extent to which transmission access orders would be

requested is speculative. The provision for public

interest transmission orders in scenario 2 would

continue to be available to utilities. In addition,

utilities seeking new power supplies or competing to

supply others must offer transmission access to other

suppliers. However, there would be no regulatory

orders for retail wheeling, simplifying some of the

wheeling issues discussed under scenario 2.

Scenario 4: Generation Segregated From

Transmission and Distribution Services

Under scenario 4, the power industry would be

restructured to create a competitive unregulated

generating sector separate from transmission and

distribution. That is, all supplies would be obtained

by transmission and distribution companies from a

competitive generation sector. Scenario 4 raises

immediate problems of establishing coordinated

operations. Coordinated control of generation for

frequency regulation and following cyclic load

changes, for maintaining reliability as system conditions change, and for controlling transactions between parties must be implemented. The transmission and distribution companies would retain the

traditional utility responsibility of planning and

acquiring supplies, although now from an unregulated competitive generating sector. The allocation

of rights and responsibilities between generators and

the transmission company must be carefully instituted.

The need to rapidly develop and implement

radically new operating and planning procedures for

competitive generation and mandatory wholesale

customer transmission access makes scenario 4

considerably more risky and uncertain than the

previous three. Both reliability and economy could

be greatly reduced in the potentially long time

required to experiment and develop new operating

and planning procedures.

The vital technical difference between scenarios

3 and 4 is the abruptness and certainty of change in

separating the generation sector. As existing utilityowned generating units are decommissioned, scenario 3 may eventually result in a transmission and

distribution sector separated from generation similar

to scenario 4. However, that outcome assumes that

utilities will not successfully compete in building

and operating generating units in their own service

areas, which may not be the case. Thus, the evolution

will occur slowly, if at all, giving a long time to

develop the procedures required for coordinating

operations and planning. Also, the long transition

period gives many opportunities for experimentation and the chance to reverse the course of change

if necessary.

Scenario 5: Common Carrier

Transmission Service

The last scenario completes the separation of

utilities into generation companies, transmission

companies, and distribution companies. The transmission companies become common carriers with

the responsibility to provide for adequate transmission capability. The main technical distinctions from

scenario 4 are the separation of transmission from

distribution; and the requirement to provide wheeling service to all retail customers, reintroducing the

operating and planning issues discussed in scenario

2. As in scenario 4, a great technical challenge is

presented by the abruptness and certainty of change.

The need to rapidly develop and implement radically

new operating and planning procedures immediately, including retail wheeling and the complete

separation of transmission from distribution, makes

scenario 5 even more risky and uncertain than

scenario 4. Again, both reliability and economy

could be greatly reduced in the potentially long time

required to experiment and develop new operating

and planning procedures.
Chapter 6

Regional Characteristics of the

Electric Power Industry
CONTENTS

Page

INTRODUCTION . . . . . . . . . . . . . . . . . . . . . . . . . 155

NERC REGIONS . . . . . . . . . . . . . . . . . . . . . . . . . . 155

INDUSTRY OWNERSHIP AND

STRUCTURE . . . . . . . . . . . . . . . . . . . . . . . . . . . 156

REGIONAL DIFFERENCES . . . . . . . . . . . . . . . 159

Electricity Demand Growth Rates . . . . . . . . . 159

Generating Capacity . . . . . . . . . . . . . . . . . . . . . 161

Generation and Fuel Use .. ............. 161

Capacity Margins . . . . . . . . . . . . . . . . . . . . . . . . 162

Generation Reliability . . . . . . . . . . . . . . . . . . . 164

Capital Spending . . . . . . . . . . . . . . . . . . . . . . . . 164

Electricity Prices . . . . . . . . . . . . . . . . . . . . . . . . 164

TRANSMISSION .. .. .. .. .. .. ... .:. . . . . . . . 164

Demand for Increased Transmission

Access .. .. .. .. .. .. .. .. .. +.. . . . . . . . . . . 167

NONUTILITY GENERATION . . . . . . . . . . . . . 168

Estimates of Total Nonutility Generation

Capacity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 168

Nonutility Fuel Use . . . . . . . . . . . . . . . . . . . . . . 169

Regional Nonutility Generation Potential . . 169

Regional Experience With Nonutility

Sources of Power . . . . . . . . . . . . . . . . . . . . . 172

REGIONAL DIFFERENCES AND INDUSTRY

CHANGE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 173

Adequacy of Supply . . . . . . . . . . . . . . . . . . . . . 173

Transmission Access . . . . . . . . . . . . . . . . . . . . 174

The Regulatory Environment . . . . . . . . . . . . . 177

Competitive Environment . . . . . . . . . . . . . . . . 178

Impacts on Retail Customers . . . . . . . . . . . . . 178

OTA SCENARIOS AND REGIONAL

IMPLEMENTATION . . . . . . . . . . . . . . . . . . . 179

REGIONAL PROFILES . . . . . . . . . . . . . . . . . . . 184

The East Central Area Reliability

Region (ECAR) . . . . . . . . . . . . . . . . . . . . . . . 184

Electric Reliability Council of

Texas (ERCOT) . . . . . . . . . . . . . . . . . . . . . . . 185

Mid-Atlantic Area Council (MARC) . . . . . . 186

Mid-American Interconnected

Network (MAIN) . . . . . . . . . . . . . . . . . . . . . 189

Mid-Continent Area Power Pool

(MAPP-U.S.) . . . . . . . . . . . . . . . . . . . . . . . . . 190

Northeast Power Coordinating Council

(NPCC) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 191

Southeastern Electric Reliability

Council (SERC) . . . . . . . . . . . . . . . . . . . . . . 192

Southwest Power Pool (SPP) . . . . . . . . . . . . . 194

WesternSystems Coordinating Council

(WSCC) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 195

Page

Alaska . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 196

Hawaii . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 197

Box

Box Page

6-A. Transmission Case Study: Importing Power

From Canada . . . . . . . . . . . . . . . . . . . . . . . . . 188

Figures

Figure Page

6-1. North American Electric Reliability

Council . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 156

6-2. Electric Regions in the Contiguous

United States... . . . . . . . . . . . . . . . . . . . . . . . 159

6-3. Installed Generating Capacity,

1988 and 1997 . . . . . . . . . . . . . . . . . . . . . . . . 162

6-4. Projected Electrical Energy Production

by Fuel 1988and 1997 . . . . . . . . . . . . . . . . 163

6-5. Estimated Margins at the Time of

Regional Peak Demand . . . . . . . . . . . . . . . . 165

6-6. Planned Transmission Additions . . . . . . . . 167

6-7. Nonutility Fuels, 1986 . . . . . . . . . . . . . . . . . 171

Tables

Table Page

6-1. U.S. Membenship of North American

Electric Reliability Council Regions . . . 157

6-2. Characteristics of Electric Utilities by

NERC Region . . . . . . . . . . . . . . . . . . . . . . . 158

6-3. Capacity, Generation, and Sales by Class

of Ownership and Region, 1987 . . . . . . . 160

6-4. Life Extension Resource Base: Age of

6-5

6-6

6-7

6-8

6-9

6-10

Fossil-Fired Steam Plants in 1995

by Region . . . . . . . . . . . . . . . . . . . . . . . . . . . 163

Estimated Regional Capacity Margins.. 164

Projected 5-Year Capital Expenditures . 166

Average Retail Electricity Prices by Class

of Service and Region, 1986-87 . . . . . . . 166

The lO Most Expensive and lO Least

Expensive Service Territories in the

Continental United States . . . . . . . . . . . . . 167

Actual and Projected Nonutility Generation

Capacity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 169

Nonutility Generating Capacity by

Region . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 170
Chapter 6

Regional Characteristics of the Electric Power Industry

INTRODUCTION

The electric power industry in the United States is

a diverse and complex patchwork of investor- and

consumer-owned utilities, government agencies,

cogenerators, self-generators, and independent power

producers. Regional differences in industry composition, structure, and resource base characteristics

are in large part attributable to patterns in population, climate, economic activities, and the history of

electrification in each region. These variations can

influence the outcome of any initiatives to expand

transmission access and to inject more competitive

pressures into the generation market. Differences in

generation reserve margins, fuel mix, load growth,

and coordination among regions will be important in

encouraging or discouraging the participation of

outside or nontraditional power generators in competitive markets.

This chapter begins with an overview of the

structure and regional divisions of the electric power

industry. Next, it provides an overview of regional

differences, including, for example, demand growth

rates, capacity margins, capital spending, electricity

prices, and nonutility generation potential. Key

regional issues and determinants for increasing

competition in the electric utility industry and some

of the anticipated regional impacts of implementing

OTA’s scenarios are also discussed. The chapter

concludes with a detailed summary of the characteristics of the industry in each of the nine regional

councils of the North American Electric Reliability

Council, including, for example, generation and

transmission capacity, fuel use, projected demand

(load) growth, and reliability concerns.

NERC REGIONS

The electric power industry is subdivided by

reliability council regions, by interconnections, by

control areas and power pools, and by utility. This

section will focus on the reliability council regions.

Chapter 2 provides an overview of industry control

areas, power pools. and interconnections.

The North-American Electric Reliability Council

(NERC) and its regional councils were established

in the late 1960s to assist utilities in providing for the

reliability and adequacy of electric generation,

transmission, and distribution systems. Formation of

the organizations was aided by Federal legislation

following the Northeast blackout of 1965. NERC is

a major source of information about electric utilities’

generation and transmission capacity and utilization.

Within the NERC federation there are nine

regional reliability councils covering the Continental United States, Canada, and portions of Mexico as

shown in figure 6-1. The Alaska Systems Coordinating Council is an affiliate member of NERC,

Hawaii’s utilities are not participants in NERC. See

table 6-1 for council membership and subregions.

Table 6-2 summarizes key operating and financial

characteristics of NERC regions. The boundaries of

NERC regions are established by the extent of the

service territories of member utilities. 1 Operationally, six NERC regions are further divided into

subregions shown in figure 6-2.

The regional councils coordinate planning and

operations and exchange information on electricity

supply, demand, and reliability. The councils provide NERC with annual and seasonal assessments of

electricity supply and the factors affecting adequacy,

reliability, and security.

Membership in NERC regional councils is voluntary and eligibility criteria are set by each region.

Sometimes, membership (and benefits) is not available equally to all utilities within a region. Most of

the regions limit full voting membership to utilities

that own generation or transmission and that can

have a significant impact on regional operations;

there are often additional qualifications. For example, the Southwest Power Pool (SPP) requires a

minimum generating capacity of 300 MW for full

l&f~re ]987, ~eglona] ~undwles and mcmbers}llp Were de[crmined by wtl~re tie gcncra[lng plan(s were located with [hc rcsull thal some UlillllCS

with widely dispersed operations, load centers, and generating plants could belong to several regions.

-155-
156 ● Electric Power Wheeling and Dealing: Technological Considerations for Increasing Competition

Figure 6-l-North American Electric Reliability

Council

ECAR: East Central Area Reliability Coordination Agreement

ERCOT: Electric Reliability Council of Texas

MAAC: Mid-Atlantic Area Council

MAIN: Mid-American Interconnected Network

MAPP: Mid-Continent Area Power Pool

NPCC: Northeast Power Coordinating Council

SERC: Southeastern Electric Reliability Council

SPP: Southwest Power Pool

WSCC: Western Systems Coordinating Council

SOURCE: North American Electric Rehabihty Council, Copyn@ @ 1988,

voting membership. 2 The Southeastern Electric

Reliability Council (SERC) has a minimum generating size of 25 MW for voting members. Voting

strength is often apportioned according to the

relative loads of member systems with larger systems having proportionately greater influence over

regional decisions than smaller systems. Participation in regional activities is usually available on a

nonvoting basis to nonqualifying utilities either

directly as associate members or indirectly through

representation.

Two regions also function as power pools: the

Mid-Atlantic Area Council (MAAC) and the MidContinent Area Power Pool (MAPP). Regional

council/pool members agree to coordinate planning

and operations, maintain adequate reserves, and

provide certain transmission services for other

members. For example, MAPP requires members to

maintain a reserve margin of 15 percent. MAAC

voting membership is coextensive with membership

in the centrally dispatched Pennsylvania-New JerseyMaryland Interconnection (PJM).

Over 95 percent of the generating capacity in the

contiguous United States is owned by utilities

associated with NERC-either as full voting members of reliability councils, as associate members of

reliability councils, or as cooperating utilities. NERC’s

voluntary operating standards and guidelines thus

have a substantial influence over system requirements and operating conditions and over determinations of transmission capacity availability.3

Regional councils are highly individualistic in

establishing reliability and operating criteria and in

collecting and dispersing information. Some regions

require adherence to their own reliability and

operating criteria and impose penalties for those

who fall short of these obligations.4

INDUSTRY OWNERSHIP AND

STRUCTURE

The electric power industry in the United States

includes electric utilities, independent power producers, cogenerators, and self-generators. Within the

utility sector there are some 200 investor-owned

utilities; 2,000 publicly owned State, municipal,

county, district, or joint action agency utilities; 900

consumer-owned cooperatives; 5 Federal power

marketing agencies; and the Tennessee Valley

Authority.5

Regional ownership statistics in table 6-3 reflect

the very different market shares of private and public

Z]nfomation from IIW North America EIWtric Reliability Council 1987 Annual Report; and “Summary of Responses of the Regional Reliability

Councils to the National Governors’ Association Survey on Electric Transmission Coordination and Planning. ” OTA Conwaclor Report, Ohio public

Utilities Commission, Mar. 28, 1988 (hereafter “Reliability Council Survey Responses,”)

qThe role of utility or regiona] reliability standards in transmission capacity limits is discussed more extensively in Chs. 4 md 5.

4See statemen~ of individu~ regionat membership WalifiCatiOnS in “Reliability Council Survey Rcspnses,” supra note 2.

5Comp]ete ~d accurate information on tie n~~r of generators in ~c nontr~itiona] or nonutibty sector, their capacity, fuel UW, ~d generation k

not centrally available through the Energy Information Administration or industry sources.
Chapter 6-Regional Characteristics of the Electric Power Industry ● 157

Table 6-1—U.S. Membership of North American Electric Reliability Council Regions

Area served Population

NERC region States Member systems (square miles) served

ECAR—East Central Area

Reliability Coordination

Agreement

ERCOT—Ebctric Reliability Council of Texas

MAAC-Mid-Atlantic Area

Council

MAIN—Mid-American interconnected Network

MAPP—Mid-ContinentArea

Power Pool

NPCC--Power C O

ordinating Council

SERC—Southeastern Electric Reliability Council

SPP—Southwest PowerPool

WSCC—W@stern Systems

Coordinating Council

MI, OH, WV,IN

Most of KY and

parts of VA, MD,PA

Most of TX

DE, NJ, PA, DC, and

parts of MD& VA

IL, and parts of MO, MI,

and WI

IA, MN, NB,ND, and

parts of WI, SD, MT, MI,IL

CT, ME, MA, NH, NY, RI,VT

AL, FL, GA, NC, SC, TN, and

parts of VA, MS, and KY

AR, OK, KS, LA, and

parts of MS, MO, TX, and

NM

AZ,CA,CO,ID,NV,OR, UT,

VW, WY, and parts of

NM, MT,SD,TX

16 Public power

(includes 6cooperatives)

5 Government agencies

4 Associates

48,700 21.1 million

170,000 18 million

420,000 (U. S.) 13.6 million

18 members 194,000 36 million

16 IOUS

2 Cooperatives

76 Members 195,000 11 million

6 IOUS

49 Cooperatives

20 Municlpals

1 State agency

11 Members

(all IOUs)

5 associates (representing

group of cooperatives)

13 Members

11 IOUs

1 Cooperative

1 Municipal

1 Associate

27 Participants

11 IOUs

8 G&T Cooperatives

4 Municipal

3 Public power districts

1 Federal agency

16 Associates

18 Full members

17 IOUs

1 State authority

28 Member systems

16 IOUs

8 Municipals/public

2 Cooperatives

2 Federal agencies

8 Associates

41 Systems

17IOUs

12 Municipal

8 Cooperatives

4 Government agencies

57 Members

19 IOUs

17 Municipal

112,527

345,650

27.4 million

25 million

500,000 25+ million

1.8 million 48 million

(US & CAN)

SOURCE: *RC 1966 Amid Repom and Uw 1986 RelialnMyA ssassnrent’ 77w future of the Bulk Elecfnc Sysfam m North America 196i-1997, September 1988.

power suppliers. Private or investor-owned utilities utilities. In the South and West, public power,

operate in all States, except Nebraska. They domi- cooperatives, and Federal power agencies account

nate power generation, transmission, and wholesale for a larger portion of sales to retail customers than

and retail sales in all but one region (East South elsewhere in the Nation, reflecting the historical role

Central). In Hawaii, all power is supplied by private of these entities in the electrification of these
158 . Electric Power Wheeling and Dealing: Technological Considerations for Increasing Competition

.

0

In

A
Chapter 6--Regional Characteristics of the Electric Power lndustry ● 159

Figure 6-2-Electric Regions in the Contiguous United States

RELIABILITY

COUNCIL

ERCOT

MAAC

MAPP

NPCC

SPP

MAIN

SERC

ELECTRIC REGION

No Subregions

No Subregions

No Subregions

NEPOOL (New England Power Pool). NYPP

(New York Power Pool)

SOEST (Southeast Sub-Region). NORTH (Northern

w ‘-COUNCIL

Sub-Region). WCENT (West Central Sub-Region)

Wscc

CECO (Commonwealth Edison Company). SCIM (South Central

Illinois-East Missouri Group). WIUM (Wisconsin-UPPer

Michigan Systems Group).

ECAR

FCG (Florida Electric Power Coordinating Group). SOCO

(Southern Company Group). TVA (Tennessee Valley Authority)

VACAR (Virginia-Carolinas Group)

SOURCE. Office ot Tectmology Assessment, 1989.

regions. (These numbers can be somewhat misleading, however, because many public power utilities

purchase wholesale power generated by private

companies. )

Among investor-owned utilities, the large holding

company power systems are important regional

entities which control access to major regional

transmission facilities. Their size, strategic 1ocations, and financial resources would make them

ELECTRIC REGION

RMPA (Rocky Mountain Power Area). NWPP (Northwest Power

Pool Area). AZNM (Arizona-New Mexico Power Area). CASN

(California-Southern Nevada Power Area)

APS (Allegheny Power System). WOIM (West Virglnia-Ohiolndlana-Michigan Systems). WPANCO (Western PennsylvaniaNorth Central Ohio Group). CDH (Cincinnati-Day ton-HamiltOfl

Group). KY (Kentucky Group). IND Indiana Group). LMS (Lower

Michigan Systems)

REGIONAL DIFFERENCES

The electric power industry displays regional

variations in demand growth rates, generating capacity, capacity margins. fuel use, levels of reliability, and capital spending, as well as the potential for

nonutility generation. Some of these differences are

summarized in table 6-2.

Electricity Demand Growth Rates

formidable competitors in large regional markets NERC indicates that U.S. demand for electricity under any competitive industry structure. Regulated

holding companies are important regional intlu- or net energy for load (NEL) will grow at an average

ences in the Northeast Power Coordinating Council annual rate of 2.0 percent between 1988 and 1997.6

(NPCC), MAAC. East Central Area Reliability Nationally, this is a downward revision of overall

Coordination Agreement (ECAR), SERC, and SPP. demand projections from those published by NERC

bNo~h ~erlcm Elc~trl~ Rc]iabi]i[y Counc ii, / 98/3 E/e(,rrlciry .$upp/}’ and Demund for /g81~-) 997, @’10bCr 1988, p. I ~. El~~lrf~~fY dcm~d is

measured as net energy for load–-defined by NERC as the annual clcctrx energy nccdcd to serve the utilltics’ customers. NEL mcludcs transmission

losses and represents the Axtrwal energy generated by Ihc utilltlcs’ own gcncraling sources plu~ clccwical energy purchaws from other ut illtics and from

nonutillty gcncmtion Iacilltws, Icss electrical energy \alcs to other utilitic~. NEL does not include energy pumpmg rcquircmcnls for pumped storage

generating fiicditlc~. NEL IS roughly cqulvalcnt m DOE’S Net @ncralkm.
160 . Electric Power Wheeling and Dealing: Technological Consideration.ffor increasing Competition

Table 8-3-Capacity, Generation, and Sales by Class of Ownership and Region, 1987 (percent by region)

NERCa region Number of Installed capacity Net generation Sales to ultimate

Class of ownership utilities (percent) (percent) consumers (percent)

ECAR:

Private . . . . . . . . . . . . . . . . . . . . . . . . . .

Public/State . . . . . . . . . . . . . . . . . ,.. .

Cooperative . . . . . . . . . . . . . . . . . . . . .

Federal . . . . . . . . . . . . . . . . . . . . . . . . .

ERCOT:

Private . . . . . . . . . . . . . . . . . . . . . . . . . .

Public/State , , . . . . . . . . . . . . . . . . . . .

Cooperative . . . . . . . . . . . . . . . . . . . . .

Federal . . . . . . . . . . . . . . . . . . . . . . . . .

MAAC:

Private . . . . . . . . . . . . . . . . . . . . . . . . . .

Public/State . . . . . . . . . . . . . . . . . . . . .

Cooperative , . . . . . . . . . . . . . . . , . . . .

Federal . . . . . . . . . . . . . . . . . . . . . . . . .

MAIN:

Private . . . . . . . . . . . . . . . . . . . . . . . . . .

PublicState . . . . . . . . . . . . . . . . . . . . .

Cooperative . . . . . . . . . . . . . . . . . . . . .

Federal . . . . . . . . . . . . . . . . . . . . . . . . .

MAPP(U.S.):

Private . . . . . . . . . . . . . . . . . . . . . . . . . .

Public/State . . . . . . . . . . . . . . . . . . . . .

Cooperative . . . . . . . . . . . . . . . . . . . . .

Federal . . . . . . . . . . . . . . . . . . . . . . . . .

NPCC(U.S):

Private . . . . . . . . . . . . . . . . . . . . . . . . . .

Public/State . . . . . . . . . . . . . . . . . . . . .

Cooperative . . . . . . . . . . . . . . . . . . . . .

Federal . . . . . . . . . . . . . . . . . . . . . . . . .

SERC:

Private . . . . . . . . . . . . . . . . . . . . . . . . . .

Public/State . . . . . . . . . . . . . . . . . . . . .

Cooperative . . . . . . . . . . . . . . . . . . . . .

Federal . . . . . . . . . . . . . . . . . . . . . . . . .

SPP:

Private, ,., . . . . . . . . . . . . . . . . . . . . . .

Public/State . . . . . . . . . . . . . . . . . . . . .

Cooperative . . . . . . . . . . . . . . . . . . . . .

Federal . . . . . . . . . . . . . . . . . . . . . . . . .

WSCC(u.s):

Private . . . . . . . . . . . . . . . . . . . . . . . . . .

PubIic/State . . . . . . . . . . . . . . . . . . . . .

Cooperative . . . . . . . . . . . . . . . . . . . . .

Federal . . . . . . . . . . . . . . . . . . . . . . . . .

NERCb(U.S):

Private . . . . . . . . . . . . . . . . . . . . . . . . . .

PubIic/State . . . . . . . . . . . . . . . . . . . . .

Cooperative . . . . . . . . . . . . . . . . . . . . .

Federal . . . . . . . . . . . . . . . . . . . . . . . . .

50

230

113

—

88.1

7.6

4.4

—

90.9

3.0

6.1

—

88.7

5.7

5.6

—

7

57

65

—

40.5

57.4

2.1

—

81.0

15.9

3.0

—

80.8

12,4

6.8

—

19

58

22

—

96.5

3.5

o*

98.3

0.4

1.3

0

95.1

1.8

3.1

—

22

149

51

1

96.9

2.4

0.7

0

97.5

1.5

0.9

0.1

91.5

5.5

3.1

0

18

497

189

—

51.5

28.9

19.5

—

48.4

25.3

26.3

—

59

26.3

14.7

—

62

134

16

—

85.4

14.6

●

o

81.7

18.2

●

o

88.8

10.7

0.5

0

22

312

187

2

69.9

8.3

1.6

20.2

68.1

7.7

6.1

18.1

64.6

20.4

11.8

3.2

20

293

158

1

79.9

11.4

8.7

0

77.1

7.1

13.2

2.6

77.9

9.5

12.6

0

32

240

139

6

55.5

41.7

2.8

0

51.9

20.9

64.3

24.8

4.3

6.6

3.5

23.7

252

1,970

10

73.5

18.6

3.6

4.3

75.2

10.5

5.8

8.5

77.0

14.2

6.9

1.9

bExofudasAla.shaandt+awah,

“Tha absolute value of the number isless than O.5,

NOTES: Totafsmaynotaqual sumofcomponents betxwsa ofindapandent rounding. Data shown, exceptformstalledcapacity, areprebminarydatareportad onthe Energylnformation

MminmtrationFormEIA.861 ThEIA-Wl &wwmuXs~tit~Mrati~afi4esda@are~[hrew~~on~atform Thedatafornetgeneratonandsalestoulnmate

consumers maynotagree with rrumberspubhahed in EIAreports, whicharebesed onthe FormEIA 759, ”Monthly PowerPkant Report~andtheForm EIA-826, ’’ElectricUtdity

C9mpanyMonthlyStatament.-

SOURCE: Energy lnforrnatiin Nmm@rauon, Form EIA-880, ”Annual Electric UttMy Report, Prehmmary Data:
Chapter 4---Regional Characteristics of the Electric Power Industry ● 161

in 1987 and continues a recent trend.7 All NERC

regions except NPCC (U.S. portion) and MAAC

projected lower 10-year NEL growth in 1988 than

they did in 1987. Projected regional NEL growth

rates for 1988-1997 vary considerably. (See table

6-2.) They range from a high of 2.9 percent in the

Electric Reliability Council of Texas (ERCOT)

region to a low of 1.5 percent in the ECAR region.

Variations are evident within regions as well. For

example, the Western Systems Coordinating Council (WSCC) region projects a growth rate of 1.1

percent for the Northwest Power Pool Area, but a 3.4

percent growth rate for the Arizona-New Mexico

Power Pool Area for the same period. What causes

these fluctuations in growth rates among regions?

Population growth, climate, industrial activity, regional nonutility generation capacity, and cost are

just a few of the factors that influence demand

growth.

Peak demand for electricity in the United States is

highest in the summer. NERC projects that U.S.

summer peak load will likely grow at an annual rate

of 1.9 percent between 1988-1997; projected regional summer peak growth rates range from 1.3

percent in MAAC to 2.4 percent in ERCOT and

SERC (see table 6-2). Winter peak demand has been

growing faster than summer peak in six of the nine

NERC regions; these are ECAR, MAAC, MAPP,

Mid-American Interconnected Network (MAIN),

ERCOT, and SPP. All six regions are expected to

remain summer peaking up to 1997.

Generating Capacity

The amount, type, and age of installed generating

capacity also varies by region, as does the pace of

planned additions (see figure 6-3 and table 6-4).

These differences reflect varying load characteristics (population, climate, economic activity) and

resource availability.

According to NERC, most regions currently have

more than enough capacity to meet their increasing

needs under most circumstances for several years at

least. This assessment rests on two critical assumptions: that electricity consumption increases at the

projected growth rates; and that existing and planned

generating capacity is available when needed.

This assessment of adequacy includes built-in

safety factors in both a 15 to 20 percent minimum

reserve capacity and other capacity that is uncounted

to allow for scheduled maintenance and could be

used if needed. Even so, if actual demand growth

exceeds the resumption or if existing and planned

generating capacity levels are not reached, several

regions and systems could see increased reliability

risk or experience actual shortfalls in electricity

supplies. Among the analysts that have examined

these prospects, there is some disagreement about

when and where additional generation capacity may

be needed.8 The disagreements are rooted in differing expectations over future growth in electricity

demand and whether or not planned capacity is built

as scheduled.

Generation and Fuel Use

More than half of the electricity generated in the

United States in 1987 (about 2.6 million gigawatt

hours (GWh)) came from three regions: SERC,

WSCC, and ECAR. Figure 6-4 shows electricity

generation by fuel and region.

About 55 percent of the electricity generated in

1987 came from coal-fired plants. Six regions used

coal for more than 50 percent of their electricity

generation—ECAR, MAAC, MAIN, MAPP, SERC,

and SPP. Two regions, MAIN and MAAC, generated a significant percentage of their power from

nuclear plants. Hydropower is an important generating source in the U.S. portion of WSCC, accounting

for about one-third of the electric energy production

in that region in 1987, an unusually dry year.

Hydroelectric plants also contributed 15 percent of

generation in NPCC in the United States.

In some regions, the oil and gas capacity base is

quite high. NERC projects that oil and gas will

provide about 65 percent of capacity in ERCOT,

over 50 percent in NPCC (U.S. portion), and 45.5

percent in SPP. Oil and gas plants are generally used

for peaking power, but in some regions they also

71bld. ~ew lo.yew dcm~d fora=t~, we of co~se highly ~cerlain. TO a~co~[ for this un~eflain[y, NERC akso estimated lha[ [hc actuaf ~nllid

NEL growth woutd fall within a range of 0,9 percent per year to 3.5 percent per year. NERC did not provide comparable ranges for regional forecasts.

ESW for Cxmple, U,S, ~p~men~ of Energy, Deputy Assistant Secretary for EncrbT Emer6cncicst “Staff Report: Electric Power Supply and

Demand for the Contiguous United States 1987 -1996,” DOE/lE-0011, February 1988; Amy Abel, ‘° Canadian Electricity, the U.S. Market and the Free

Trade Agreement,” Congressional Research Service Report 88-427 ENR, July 5, 1988.
162 ● Electric Power Wheeling and Dealing: Technological Considerations for increasing Competition

1 8 0

1 6 0

1 4 0

1 2 0

1 0 0

8 0

6 0

4 0

2 0

0

Sum mer (

Figure 6-3-installed Generating Capacity,

thousands of M W )

1968 and 1997

4

8 8 ’97 ’ 8 8 ’97 ’88 ’9 7 ’ 8 8 ’97 ’ 8 8 ’97

4

88 ’9 7 ’ 8 8 ’97 ’ 8 8 ’97 ’ 8 8 ’97

ECAR E RCOT MAAC MAIN MAP P N PCC SE RC SPP Wsc c

- COf31 = Nuclear ~ Hydro ~ Oil/Gas m Othe r

SOURCE: OftIos of Technology Assessment trorn NERC deta.

contribute significantly to meeting base-load needs.

For example, ERCOT generated 46 percent of its

electricity from oil and gas in 1987, and NPCC-U,S.

produced almost 39 percent of its electricity from oil

and gas,

Capacity Margins

Regional and individual utility variations in

capacity margins reflect differences in system characteristics, such as the duration of the peak load

season and the outage rates for different ages, sizes,

and types of generation capacity. Also, differences

in the availability of supplementary bulk power from

other systems will affect capacity margins. See table

6-5 showing projected capacity margins from NERC

by region for 1988-1997 and figure 6-5 showing

projected reserve margins at the time of regional

peak demand.

Determination of adequate capacity margins varies from region to region with a margin of 15 to 20

percent generally considered desirable. See discussion in chapter 4. NERC expects capacity resources

in all regions to be adequate to meet projected

demand in 1988-97; however, overall capacity

margins will decrease over the same period.

One of the results of the lower capacity margins

could be that some utilities may have less flexibility

in dealing with more severe situations. Another

result could be the increased likelihood of load

curtailments if a shortage develops.

Still another result could be greater reliance on

older generating units. This in turn will increase
Chapter 6-Regional Characteristics of the Electric Power Industry ● 163

Table 6-4--Life Extension Resource Base: Age of Fossil-Fired Steam Plants

in 1995 by Region

7 0 0

6 0 0

6 0 0

4 0 0

3 0 0

2 0 0

100

0

SOURCE

Fossil-fired capacity ±30 years old in 1995

As a percent of As a percent of

Region MW fossil-fired capacity all installed capacity

ECAR . . . . . . . . . . . . . . . . . . . . . . .

ERCOT . . . . . . . . . . . . . . . . . . . . .

MAAC . . . . . . . . . . . . . . . . . . . . . . .

MAIN . . . . . . . . . . . . . . . . . . . . . . .

MAPP (U. S.) . . . . . . . . . . . . . . . . .

NPCC (U. S.) . . . . . . . . . . . . . . . . .

SERC . . . . . . . . . . . . . . . . . . . . . . .

SPP . . . . .. . . .. . .. . ..... .

WSCC . . . . . . . . . . . . . . . . . . . . . .

33,335

12,186

11,589

14,172

6,695

16,806

32,239

21,359

24,811

32.9

20.4

35.5

41.3

25.8

52.6

35.8

30.0

39.5

31.9

22.0

22.0

28.0

22.5

30.0

20.9

32.0

18.5

SOURCE: Offi-ofTechndogy Assessment, fromdatagymaratad by E.H. Pec&n&Assm%Nes, Oecember 19S4, andNorthAmercan

EbctrIc Reliab-ihty Council, 1%7 E&ctncity Sup@y and Oernand kw IW7-1996, November 1987.

Figure 6-4-Projected Electrical Energy Production by Fuel, 1988 and 1997

Thousands of GWh

!!!

!ll

’88 ’97 ’88 ’97 ’88 ’97 ’88 ’97 ’88 ’97 88 ’97 ’88 ’97 ’88 ’97 ’88 ’97

E CAR E RCOT MAAC MAIN MAPP N PCC SE RC SPP Wscc

- Coal = Nuclear = Oil/gas ~ Hydro ~ Othe r

: Offti of Technology Assessment from NERC data.

maintenance requirements and result in more outage change supply adequacy or excess capacity into a

time, as well as an increase in sulfur oxide emis- shortage situation. These include delayed capacity

sions. A number of developments could easily additions, nuclear safety concerns which result in
164 ● Electric Power Wheeling and Dealing: Technological Considerations for Increasing Competition

Table 6-5-Estimated Regional Capacity Margins

(percent of planned capacity resources)

1988 1997

Regions (U. S.) summer summer

ECAR . . . . . . . . . . . . . . . . . . . . . . . 23.0

ERCOT . . . . . . . . . . . . . . . . . . . . . 21.3

MAAC . . . . . . . . . . . . . . . . . . . . . . . 19.0

MAIN . . . . . . . . . . . . . . . . . . . . . . . 25.4

MAPP . . . . . . . . . . . . . . . . . . . . . . . 28.4

NPCC . . . . . . . . . . . . . . . . . . . . . . . 22.1

SERC . . . . . . . . . . . . . . . . . . . . . . . 20.0

SPP . . . . . . . . . . . . . . . . . . . . . . . . 26.7

Wscc . . . . . . . . . . . . . . . . . . . . . . 31.5

Total NERC . . . . . . . . . . . . . . . . 24.3

20.5

17.8

20.3

15.2

20.9

20.5

17.7

16.6

25.5

19.9

SOURCE:North American Electric Rellabdity CouncII, IsW8 Ek?cfrr@ Sug@y 6

hn’rand/or 1989199~Octobar 1988,p.24.

unit deratings or delays in operation, and higher than

predicted demand growth rates.

Generation Reliability9

How a NERC region assesses generation reliability depends on the structural relationships between

the regional council and its member systems and the

degree to which various approaches are formalized

by legal documents. Nearly all regions employ a

probabilistic approach to generation adequacy analysis. The industry standard of 1 day in 10 years loss

of load probability is widely shared, 10

Significant parameters used in assessing adequacy include demand growth, load patterns, weather, potential slippage of in-service dates, transmission ties, and fuel and unit availability. Most regions

encourage the use of a normal weather parameter in

determining demand. With regard to capacity characteristics, all regions have a formal requirement for

establishing the capacity rating. Also, all regions use

either a probabilistic or judgmental evaluation of the

effects on adequacy of operational capacity availability rates.

Capital Spending

The Electric Light and Power Survey of investorowned utilities, cooperatives, and public power

organizations indicated that regional capital investment will follow population and business growth

trends. For example, the greatest spending activity

will occur in the SERC and WSCC regions, which

have the greatest capacity and the highest demand.

Table 6-2 shows capital spending by region for the

1988-92 period.

Electricity Prices

Retail electricity prices vary by region and by

class of service. Department of Energy (DOE) data

for 1987 show that average retail residential electricity prices ranged from 6.89 cents per kWh in

WSCC to 9.76 cents in Alaska and 9.69 cents in

NPCC. Electricity prices for commercial and industrial customers also varied considerably. The NPCC

and Alaska regions were the most expensive for

commercial customers; industrial customers in

Alaska, MAAC, and NPCC paid the highest prices.

Table 6-7 shows the average retail electricity prices

by class of service and region for 1986 and 1987.

NARUC’s (National Association of Regulatory

Utility Commissioners) 1986-87 winter survey of

residential electric bills found that costs varied by as

much as 300 percent regionally. Costs ranged from

4 cents per kWh in Spokane to 13.1 cents per kWh

in New York. The average was 8.1 cents nationally. 11 

The Northeast and Pacific regions were the most

expensive, while the Northwest and Rocky Mountain areas were the least expensive, according to

NARUC. 12 Table 6-8 shows the ten most and ten

least expensive service territories in the United

States.

TRANSMISSION

NERC reports that there is no major transmission

surplus in any region of the country. In MAAC, for

example, the transmission system is reported to be

fully loaded much of the time. Overall, new transmission line construction is declining. In fact, since

1985, the total amount of planned transmission

facilities has declined, both in the United States and

Canada. This decline is due in large part to the

9Reliability (kmncil Survey Responses, Supra note z, at p. 12.

1Os= discu~ion of 1 day in 10 years loss of load probability (LOLP) in ch. 4.

11~ Nati~~ A~~iatj~n of Re@~o~ Uti]lty co~lsslon~rs (NAR(JC) 1986.87 Win(cr Survey of Resklcntial Electric Bills, Elecfric Lighf d?d

Puwer, vol. 66, No. 3, March 1988, p. 3,

121bid.
Chapter 4-Regional Characteristics of the Electric Power Industry ● 165

MAPP

MAAC

E RCO1

MAIN

N PCC

SPP

ECAR

Wsc c

SE RC

Figure 6-5-Estimated Margins at the Time of Regional Peak Demand

NERC-U.S. (summer )

o 6 0 100 160 200

Thousands of MW

-1988 peak demand 1997 peak demand UMargi n

SOURCE: NOrth tier-n Electric Reliability Council.

cancellation or deferral of new generation additions

and their related transmission facilities (see figure

6-6). In addition, many utilities are giving greater

emphasis to efforts to increase the capability of

existing transmission systems because of the difficulties in siting and building new lines.

NERC expects that some transmission systems

will continue to be heavily loaded by economy

energy transfers, both within and among regions,

during the 1988-97 forecast period. These transfers

are expected to increase whenever sufficient fuel

price differentials exist. For example, within regions, hydrogenerated energy will continue to be

transferred from the Northwest area of WSCC to the

Southwest area, provided there are no dry spells.

Also, because of loop flow and parallel path

phenomena, energy transfers among systems can

increase loadings in other systems that are not

parties to the transfer. MAAC’s transmission system

adequacy has been affected by New York Power

Pool (NYPP) imports of Canadian hydropower, for

example. To counteract these increases in interregional loading, NPCC and MAAC have reached

an agreement on what constitutes normal and

excessive use of each other’s transmission system.

The agreement includes the purchase and installation of phase shifting transformers near the New

York/New Jersey border. OTA’s case study “Importing power from Canada to New England”’

illustrates this particular transmission problem.

13 For more detai]ed information on [he OTA case study, sw Casazza, Schulti & Associates, Inc., ‘‘Case Studies of Transmission Bottlenecks,” OTA

contractor report, Nov. 30, 1988.
166 ● Electric Power Wheeling and Dealing: Technological Consideration for Increasing Competition — —

Table 6-6-Projected 5-Year Capital Expenditures

(by NERC Region–millions of dollars)

5-year

Region 1988 1989 1990 1991 1992 total

ECAR . . . . . . . . . . . . 3,303 3,204 2,756 2,460 2,022 13,745

ERCOT . . . . . . . . . . . 1,676 1,264 1,188 1,184 1,502 6,814

MAAC . . . . . . . . . . . . 3,182 2,939 3,012 2,729 2,195 14,057

MAIN . . . . . . . . . . . . . 1,897 1,490 1,428 1,370 1,503 7,688

MAPP . . . . . . . . . . . . 1,029 1,112 1,102 1,090 1,020 5,353

NPCC . . . . . . . . . . . . 1,876 1,726 1,782 1,800 1,518 8,702

SERC . . . . . . . . . . . . 7,189 6,766 7,030 6,703 6,224 33,912

SPP . . . . . . . . . . . . . . 1,463 1,360 1,310 1,389 1,369 6,891

WSCC . . . . . . . . . . . . 5,870 4,784 4,504 4,565 4,886 24,609

Total . . . . . . . . . . . 27,485 24,645 24,112 23,290 22,239 121,771

SOURCE: EkctrIc Lgf)t & l%wer, “ElacIrw UtMas WIII Increase SpandIng Ptans Throtigh 1992,” vol. 66, No. 1, January 1988, p. 12,

Table 6-7—Average Retail Electricity Prices by Class

of Service and Region, 1986-87 (cents/kWh)

NERC region Residential Commercial Industrial

1987:

ASCC . . . . . .

ECAR . . . . . .

ERCOT ., . .

MAAC “ : : : : :

MAIN . . . . . .

MAPP . . . . .

NPCC . . . . .

PRTER . . . .

SERC . . . . . .

SPP . . . . . . .

Wscc . . . . .

.

:Fc . . . . . .

ECAR . . . . . .

ERCOT ... ,

HI . . . . . . . . .

MAAC . . . . .

MAIN . . . . . .

MAPP . . . . .

NPCC . . . . .

PRTER ... ,

SERC . . . . . .

SPP . . . . . . .

9.76

7.08

6.68

9.28

9.05

9.12

6.96

9.69

7.51

6.96

7.26

6.89

9.11

7.13

6.70

9.13

9.38

8.67

6.83

9.65

6.89

6.95

7.36

8.48

6.68

5.81

9.26

8,32

7.54

6.22

9.06

9.83

6.55

6.64

7.31

8.27

6.78

5.91

9.03

8.83

7.69

6.27

9.26

9.17

6.58

6.78

7.86

4.44

3.99

6.69

6.05

5.01

4.34

5.74

7.78

4.67

4.37

5.47

7.49

4.63

4.20

6.41

6.52

5.07

4.53

5.73

7.27

4,73

4.60 Wscc . . . . . 6.81 7.37 5.65

NOTES: Totals may not equal sum of components because of independent rounding.

SOURCE: Energy Information Mminmtrahon, Form EIA 661, “Annual Elecmc UtIIIty

Report, - prehmmary data.

Assessing

task. Given

transactions,

sion system

transmission constraints is a difficult

the dynamic nature of bulk power

the location and seventy of transmisconstraints often change. The ccmstraints that have been identified in various reports

differ in nature and are caused by a variety of factors,

as discussed in chapter 4. Because of these and other

factors, no comprehensive list of bottlenecks has

been developed. OTA has not investigated the cited

incidence of transmission constraints.

The 1986-1987 National Governors’ Association

(NGA) survey of NERC regional councils, for

example, identified a wide range of situations

creating transmission limitations. However, many of

these limitations may no longer be considered as

such because conditions have changed since the time

of the survey.

NERC has also listed impediments to transfer in

its 1984, 1985, 1986, and 1987 assessments. Over

that period some of those impediments have been

solved or eased, while other projects remain delayed

by regulatory actions. A 1985 ECAR/MAAC Coordinating Group report identified bottlenecks to the

transfer of power from ECAR to MAAC. The

primary restriction to ECAR-MAAC transfers, according to the report, has been voltage conditions in

MAAC and eastern ECAR. Also, parallel path flows

resulting from power transfers among utilities in the

Northeast are cited as another limiting factor.

An OTA survey of some 23 utilities conducted in

July 1988 found few cases of utilities having to

restrict bulk power transactions or limit economic

dispatch significantly because of transmission constraints. However, most respondents had to limit or

operate outside optimal economic dispatch occa-
Chapter 6--Regional Characteristics of the Electric Power Industry ● 167

Table 6-&The 10 Most Expensive and 10 Least Expensive Service Territories in the Continental United States

Average cost

Total

Company

cents/kWh

State bill 500 kWh” Rank

Ten most expensive service territories:

Consolidated Edison Co. of N.Y. . . . . . . . . . . . . . . . . . .New York $195.91 $0.131

San Diego Gas & Electric. . . . . . . . . . . . . . . . . . . . . . . .California $179.91 $0.120

Long Island Lighting . . . . . . . . . . . . . . . . . . . . . . . . . . . .New York $177.56 $0.118

Philadelphia Electric . . . . . . . . . . . . . . . . . . . . . . . . . . . .Pennsylvania $175.87 $0.117

Orange & Rockland Utilities . . . . . . . . . . . . . . . . . . . . . .New York $168.77 $0.113

Texas New Mexico Power . . . . . . . . . . . . . . . . . . . . . . .New Mexico $167.33 $0.112

Central Vermont Public Service . . . . . . . . . . . . . . . . . . .Vermont $166.80 $0.111

Delmarva Power& Light. . . . . . . . . . . . . . . . . . . . . . . . .Virginia $164.82 $0,110

Public Service Electric & Gas . . . . . . . . . . . . . . . . . . . .New Jersey $162.36 $0.108

Northern Indiana Public Service . . . . . . . . . . . . . . . . . .Indiana $162.09 $0.108

Ten Ieast expensive service territories:

Washington Water Power . . . . . . . . . . . . . . . . . . . . . . . .Washington $59.97 $0.040

Washington Water Power . . . . . . . . . . . . . . . . . . . . . . . .Idaho !$62.73 $0.042

Idaho Power ... , . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Idaho $63.17 $0.042

CP National Corp. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Oregon $65.85 $0.044

Pacific Power & Light . . . . . . . . . . . . . . . . . . . . . . . . . . .Washington $67.95 $0.045

Idaho Power . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ,Oregon $71.34 $0.048

Portland General Electric . . . . . . . . . . . . . . . . . . . . . . . .Oregon $72.84 $0.049

Pacific Power & Light . . . . . . . . . . . . . . . . . . . . . . . . . . .Montana $73.32 $0.049

Puget Sound Power& Light . . . . . . . . . . . . . . . . . . . . . .Washington $75.74 $0.050

Minnesota Power & Light . . . . . . . . . . . . . . . . . . . . . . . .Minnesota $79.48 $0.053

“Based on customar usage of 500 kWh per month.

SOURCE: NARUC, “1986 87 Winter Survey of Residerrtml Electric Bills, - E/ectrIc Ught & Power, March 196S, p. 3.

Figure 6-6-Planned Transmission Additions

(NERC-U.S.)

Circuit miles in thousands

‘Or______ ~

8

6

4

2

n

“ 230 kV 345 kV 500 kv +765 kV +250 kV DC

10-year forecasts (circuit miles) and ebwe

= 1985--22,62 9 = 1986--16,81 5

= 1987--13,663 ~ 1988--12,029

SOURCE: North American ElectrIc Reliabihty Council.

sionally. The utilities’ responses generally were that

the constraints were not significant enough to offset

the costs of correcting them.

1

2

3

4

5

6

7

8

9

10

191

190

189

188

187

186

185

184

183

182

Demand for Increased Transmission Access

Determining which regions and utilities are most

likely to request wheeling is a difficult task at best.

However, several factors, such as price differentials,

surplus generating capacity, and load diversity,

indicate that transmission access requests are likely

to increase in some regions. Among these regions

are MAPP, MAIN, WSCC, and NPCC. Both MAPP

and MAIN have abundant coal-fired capacity which

could be exploited by selling to utilities outside the

regions. MAIN also has substantial interregional

transfer capability. Because of load diversity, baseload capacity surpluses, and large fuel price differentials, the WSCC subregions are likely to continue to

take advantage of energy economy transfers. Also,

the NPCC region, with its fuel price differentials and

its growing reliance on Canadian generating resources, is more likely to seek additional transmission services.

A recent private consulting firm’s report on

wheeling indicated that if expanded transmission

access is allowed, some regions could become major
168 . Electric Power Wheeling and Dealing: Technological Considerations for Increasing Competition

power exporters, and the total cost of electric

generation and transmission in North America could

be cut by $1.65 billion a year. Among the potential

beneficiaries of an open transmission access environment could be the Rocky Mountain and the

Arizona-New Mexico subregions of the WSCC,

MAPP, and MAAC, according to the report.14

The NGA survey of NERC regional councils

indicated that expanded transmission access could

have an impact on reliability. ECAR and SERC

respondents cited numerous problems with open

access. These included scheduling generation and

transmission maintenance, load dispatching problems, a decline in cooperation among utilities, and

reliability impacts.

The responses differed among utilities within

regions, however, Those utilities that could actively

participate in competitive bidding were less resistant

to expanded access. Joint action agencies, regardless

of region, noted that open transmission access would

be beneficial for a number of reasons. Competitive

and economic opportunities were the two reasons

most often cited.

NONUTILITY GENERATION

Fuel use and costs, demand growth rates, and

regulatory policies determine the potential for nonutility generation (NUG) in any region.

Determining the amount of actual NUG capacity

on line or planned is difficult. There is no comprehensive and up-to-date source of information on

total megawatts for plants in operation, under

construction, or in the planning stage. While the

Federal Energy Regulatory Commission (FERC)

keeps records of applications for qualifying facility

status, l6 it does not track operational facilities.

Moreover, the Energy Information Administration

also has not collected independent information that

tracks the growth of nonutility generation. Consequently, little information on total NUG capacity is

available. Those attempting to determine capacity

often use different definitions, leading to further

variations in data.

Estimates of current and future NUG capacity

vary by region and by sector, as well as by estimator.

A number of reports have estimated current capacity

and a few have even made projections. These

include NERC, Edison Electric Institute, RCG

Hagler, Bailly, Inc., and the Gas Research Institute.

Estimates of Total Nonutility Generation

Capacity

Estimates of NUG capacity are being included, to

a varying extent, in the NERC regional forecasts. ]7

The decision of how to treat N UG capacity additions

rests with the local utility and regional council. NUG

capacity additions in the latest NERC projections

were notable in WSCC, SERC, NPCC, and MAAC

regions. NERC projected a total of 27,656 MW of

NUG capacity by 1997—about 22 percent of total

planned additions. Much of NERC’s projected NUG

capacity, however, is characterized as ‘‘unknown, ”

either as to location, fuel, or project. NERC estimates current NUG capacity to be 7,741 MW as

shown in table 6-9. 18 This NERC estimate most

probably understates the actual NUG capacity.

Based on a more extensive survey, the Edison

Electric Institute (EEI) also has calculated the

amount of nonutility sources of generation, both

used internally in industry (self-generation) and sold

to utilities (cogeneration). In 1986, EEI estimated

that NUG capacity reached 25,321 MW, a 10 percent

increase over 1985 figures. Cogenerators accounted

for about 73 percent of total capacity or 18,448 MW.

About two-third’s of the total cogenerated capacity

are qualified facilities under the Public Utility

Regulatory Policies Act (PURPA).l9 The industries

with the greatest cogeneration capacity are the

chemicals and paper and lumber industries, followed

by the oil and gas and metal industries. Table 6-10

14WEFA Group, “Power Wheeling in North America, ” Ele~strical World, vol. X)2, No, 3, March 1988, pp. 13-14.

IsOhio pub]i~ Utilltles Commission Staff, Summary of Utility Interviews, Aug. 12, 1988 (OTA contractor document).

]~he num~r ad size of puRpA QFs filed with FFRc has incrc~wdmarkedly in recent years. In ]980, FER(J reccivd 29 applications for 704 !VfW

of PURPA qualified capacity. But by the third quarter of 1987, FERC re-ccived 3,571 applications for 58,717 MW of nonutility capacity.

17 UlJ]lties dlffcr in how NUG Capal[y is coun[ed. Some util][ic~ rcpofl NUG faci]itics under total generating capacity, others treat [hc capaclly as a

reduction in load, while still others do not include NUG capacity at all in reporting system capacity and gcneraiion,

IU~RC, ]98/) Reli~blll~ A~$~,f~~~nt. The Future of BUlk Ele(trl~ ~),slern Rellablli(y in North Amerl~-a ]g~8-l$lgT, scpemkr lg~~, p, 15,

lgEdlson E]~lric Institute, capml~ and Generation of Nonutility Sources of Energ.v, 1988. p. 11.
Chapter 6--Regional Characteristics of the Electric Power Industry ● 169

Table 6-9-Actual and Projected Nonutility

Generation Capacity (summer MW)

Actual

NERC regions 1987 1988 1997

ECAR . . . . . . . . . . . . . . . . . . . .

ERCOT . . . . . . . . . . . . . . . . . . .

MAAC . . . . . . . . . . . . . . . . . . . .

MAIN . . . . . . . . . . . . . . . . . . . . .

MAPP . . . . . . . . . . . . . . . . . . . .

NPCC . . . . . . . . . . . . . . . . . . . .

SERC . . . . . . . . . . . . . . . . . . . .

SAP . . . . . . . . . . . . . . . . . . . . . .

Wscc. ... ...... . . . . . . . . .

148

2,956

183

0

0

874

961

31

2,588

192

2,536

2690

216

1,517

1,526

47

4,835

2,308

2,506

3,126

12

281

4,572

5,910

582

8,359

Total . . . . . . . . . . . . . . . . . . . 7,741 11,139 27,656

SOURCE: North Amerrcan Electric Rehalxhty CouncII, 1988 HecfrIcItY Supply arrd

Dernandfor 196897,0ctobar 1988,a~.A,p.20.

and figure 6-7 summarize EEI regional nonutility

generation data.

Another report by a private consulting firm,

“Profiles of Cogeneration and Small Power Markets,” 2

° indicated that 1988 cogeneration and small

power production capacity was 24,833 MW. An

additional 38,345 MW are under construction or in

design, according to the report. 21 Cogeneration

projects outnumber small power projects by a

margin of 3-to-I. And, in terms of capacity, cogeneration outnumbers small power by nearly a 5-to-1

ratio .22

The Gas Research Institute has been monitoring

nonutility generation, particularly gas-fired cogeneration. The GRI report, Impact of Cogeneration on

Gas Use, estimated cogeneration capacity at 19,000

MW in 1985. GRI expects 25,000 MW to be added

by the year 2000.

Nonutility Fuel Use

Natural gas has been the predominant choice for

NUG facilities. Recent lower prices and the availability of natural gas have contributed to its popularity among nonutility generators. Coal-fired and

wood-burning facilities also provide significant

amounts of NUG capacity. A large percentage of

natural gas-fired capacity is in ERCOT (Texas),

WSCC (California), SPP (Louisiana), and SERC.

The SERC region also has a concentration of

wood-burning cogeneration facilities. And MAAC

(Pennsylvania) and NPCC (New York) have significant coal-fired NUG facilities. Combined cycle

systems and boiler/steam turbine systems provide

most of the capacity.

Regional Nonutility Generation Potential

All regions of the country have some level of

nonutility generation. In the MAAC region, there is

considerable potential for development of nonutility

generation. NERC expects that nonutility generation

will account for more than 40 percent, or 2,860 M W,

of new capacity additions over the next 10 years.

According to a recent survey of qualifying facilities in the United States, cogeneration growth in the

Mid-Atlantic has surpassed that of the Pacific and

Gulf Coast areas.23 New Jersey, New York, and

Pennsylvania lead the nation with 13,262 MW of

potential qualifying facility (QF) power, followed

by the West South Central and Pacific regions.24

In its latest report Electric Power Outlook 1968-

2O04, the NYPP has indicated that a total of 2,577

MW of nonutility generation will be added between

1988 and 2002. This figure is more than twice the

1,081 MW predicted for the same period in NYPP’s

previous year’s report. Without these nonutility

generation additions, margins may not be adequate

by the mid- 1990s, according to the report.25

The importance of nonutility generation to meet

demand in New England has been voiced by both

NERC and the New England Conference of Governors. A recent New England Governors’ Conference

report indicated that cogeneration and small power

production must play increasingly important roles if

the New England States are to meet energy demand.26 Also, NERC has indicated that the develop20RcG H~gler, Bailly, Inc., Profiles of Cogenerarion and Smull Power Markets. l~H8 edition.

21 Energy User News, “Mid-Atlantic Area Forges Ahead in Cogcneration Development, ” vol. 13, No. 21, May 23, 1988, pp. 1, 8.

zzE/ectric urlii~> Week, “Cogcncration Dcvelopmcn( This Year Seen Off A Bit, But Still Active, ” Apr. 25, 1988, p. 12.

Z3Ewro. User News, supra note 21.

241bld,

25~/CCtT~(. Uti/~~ w~~~, “COgCnCra[l~n, DC[n~d Cu[, Nu~lcu seen NC~CSS~ TO (jc[ NYPP I(I ?()()4,” !V@ 30, 1%8, p, 1 ]

2Togeneran”on, “Big Role Ior Cogeneration in New England’s Energy Future, ” VOI. 4, No. 1, January-February 1987, p. 28.
170 ● Electric Power Wheeling and Dealing: Technological Considerations for Increasing Competition

Table 6-l Nonutility Generating Capacity by Region

NERC regions Percent

full/partially 1986 nonutility Percent

Region States

cogeneration

included capacity cogeneration qualified

New England . . . . . . . . . . . . . . . . .ME, VT, NH, MA,

CT, RI

Mid-Atlantic . . . . . . . . . . . . . . . . . .NY, NJ, PA

East North Central . . . . . . . . . . . .IL, IN, Ml, OH, WI

klkst North Central . . . . . . . . . . . .1A, KS, MN, MO,

ND, NB, SD

South Atlantic . . . . . . . . . . . . . . . .DC, DE, FL, GA,

MD, NC, SC, VA,

Wv

East South Central . . . . . . . . . . . .AL, KY, MS, TN

West South Central . . . . . . . . . . .AR, LA, OK, TX

Mountain . . . . . . . . . . . . . . . . . . . .AZ, CO, ID, MT,

NM, NV, UT, WY

Pacific . . . . . . . . . . . . . . . . . . . . . .CA, OR, VW

Alaska . . . . . . . . . . . . . . . . . . . . . .

Hawaii . . . . . . . . . . . . . . . . . . . . . .

Total . . . . . . . . . . . . . . . . . . . . . .

NPCC

NPCC, MAAC

MAIN, ECAR, MAPP

MAPP, SPP

MAAC, ECAR, SERC

SERC, SPP

SPP, ERCOT

WSCC, MAPP

Wscc

1,404 MW

1,552 MW

2,840 MW

661 MW

3,989 MW

1,104 MW

7,751 MW

420 MW

4,687 MW

644 MW

270 MW

25.321 MW

480/o (667 MW)

67°/0 (1 ,045 MW)

690/o (1 ,950 MW)

360/. (239 MW)

840/o (3,351 MW)

96Y0 (1 ,064 MW)

930/0 (7,231 MW)

5570 (233 MW)

38Y0 (1,816 MW)

10OO/o (644 MW)

770/0 (208 MW)

18,448 MW

61Y.

72%0

230/’

36?40

610/0

580/o

780/.

52%

97?40

—,—

SOURCE: Edison Electric Institute, Capacity and Generation ofiVon-UfdIty Sources of Energ~ July 1988, pp. 26.27.

ment of nonutility generation is important to ensuring the NPCC’s supply adequacy over the next 10

years. Between 1988 and 1997, nonutility generation capacity is expected to increase by 27 percent in

New England and by 44 percent in New York,

according to NERC.

ECAR expects nonutility generation to increase

from 168 MW in 1988 to 1,329 MW by 1991. West

Virginia is one of the States within this region that

is taking a hard look at cogeneration as part of its

long-range energy plan to make the State a regional

electricity exporter. However, the State’s cogeneration potential may be limited by overcapacity and

low avoided-cost factors and by limitations on

available transmission capacity to potential consumers in Northern States.27

ERCOT produces a great deal of nonutility

generation, almost all of which is gas-fired. NERC

projects that 2,537 MW or 5 percent of 1988 summer

peak capacity resources will be supplied by nonutility generators, mostly cogeneration. Without the

projected nonutility generation capacity additions,

the region’s 1997 capacity margin would decrease

from 17.8 percent to 14.2 percent, according to

NERC. Some of this cogenerated electricity was

wheeled to utilities other than the connecting utility.

NERC indicates that the figure maybe a.. high as 60

percent of NUG capacity under contract within

ERCOT.

Other projections also show that cogeneration

will make a significant contribution to capacity in

Texas. The Texas Public Utilities Commission

assembled a data base of State cogeneration projects

that were either in operation, under construction, or

being planned for service before the end of 1988.

The data showed that Texas should have about 9,500

MW of cogeneration capacity in 1988.28

The largest number of cogenerators in Texas are

in the oil, gas, and chemical industries. These

industries have great cogeneration potential, as well

as financial and political clout. Texas has taken steps

to increase cogenerators’ access to transmission

lines to move power to nonlocal utilities, but state

law explicitly prohibits retail or self-service wheeling.

SERC, the fastest growing region, expects about

6,200 MW of new nonutility generation by 1997.

According to NERC, nonutility generation will

continue to be an increasingly important source of

new capacity for some systems of SERC. While

nonutility generation is not expected to significantly

27Cogeneration, “In the States,” vol. 4, No, 3, May-June 1987, p. 55.

Z~R1, IWa.t @C08enerafiOn on Cm Use in t~ l~us~lalad lllertri~ !Jtilip Sector.y, J~uq 1986, p. ES-27.
Chapter 6--Regional Characteristics of the Electric Power Industry ● 171

-.

Figure 6-7-Nonutility Fuels, 1966

New Eng land

Mid- At I an t I c

East N. Central

West N. Central

South Atlantic

East S Central

West S Central

Mountain

Pacific

Alaska & Hawal I

o% 25% 50% 75% 1 00%

= Biomas s Hydr o = Ga s Oi l

Kxl coal El Wast e = Renewabl e ~ Othe r

Biomass includes agricultural waste, landfill, municipal solid waste, and wood.

Waste indudes anthracite culm, blast fumance gas, coke oven gas, digester gas, petroleum coke, refinery

combustion, waste gas, and waste heat.

Other includes nuclear, fuel cell, and projects which did not identify primary energy source.

SOURCE: Edisan Elactric lnstWa, 1966 Capaci?yand Grwration of Non-Ut#fySourcas of Energy (Wast@ton, DC: July 1988).

gas, refinery oil, sulfur

penetrate the TVA service area, it is expected to

contribute significantly to the Virginia-Carolina

Region’s (VACAR) capacity needs during the next

decade. For example, Virginia Power signed seven

contracts in mid-1987 for 1,181 MW of cogenerated

power. The utility expects that 75 percent of its new

capacity needs by 1990 must be met by cogenerated

sources.

29 In addition, in March 1988, Virginia

Power solicited bids for 1,750 MW of additional

capacity. The solicitations generated interest from

potential suppliers of about 27,000 MW, including

some cogeneration and coal waste projects.30 Detailed information on Virginia Power’s bidding

system can be found in box 5-B in chapter 5.

From 1988 through 1997, nonutility generation

capacity additions represent about 31 percent of

WSCC’s planned additions. NUG additions will

account for almost 5 percent of the region’s total

1997 resources, according to NERC.

Of the four WSCC areas, the California-Southern

Nevada Power Area is projecting the highest growth

in nonutility generation. California leads the WSCC

region in projected NUG additions. NUG capacity is

forecast to increase from 1,740 MW in 1987 to 6,768

MW by 1997. These estimates differ significantly

from those reported by the California Independent

Energy Producers (CIEP). Based on the cogeneration/

small project quarterly reports issued by California

29Cogenerah’on, “Virginia Power Deals for 1,181 MW of Cogcnerated Power for 1990 Delivery, ” VO]. 4, No. 4, July-Augusl ]%7, P. 18.

3°Energy Dady, ‘*Competitive Bidding: The 30%) Solution,” vol. 16, No. 99, May 24, 1988, p. 1
172 ● Electric Power Wheeling and Dealing: Technological Considerations for Increasing Competition

utilities, CIEP indicates that 5,218 MW of QF

generation was on-line in California, as of the end of

1987. An additional 11,964 MW are under contract

or in the discussion stage.31 The increase in NUG

facilities have been stimulated by the California

regulatory commissions’ interpretations of PURPA.

Most of these facilities are base-load in nature, and

many are small, low-voltage units. Because of the

oversupply of NUGS in the mid- 1980s, the California Public Utility Commission suspended long-term

contract offers. California has since developed a

bidding system for acquiring long-term energy and

capacity. (See box 5-C for more detailed information

on the California bidding system.)

In contrast, growth in NUG capacity has been

relatively slow in the Rocky Mountain Power Area.

This may be attributed to the substantial amount of

surplus coal-fired generating capacity available

within the area, which results in low avoided costs.

However, a recent flurry of QF proposals in Public

Service Colorado’s (PSC) service territory could

increase the region’s NUG capacity. PSC claims that

if all the potential projects enter service. it would be

buying 1,149 MW of nonutility generation by

1991—784 MW more than it had projected. This

situation led the Colorado Public Service Commission to suspend the signing of new QF contracts in

late 1987 for 60 days.32 Colorado has since approved

a bidding program for new supplies for PSC.

SPP anticipates nonutility generation capacity to

reach 582 MW by 1997, or 0.9 percent of total

capacity. Most NUG capacity is expected to develop

in the West Central subregion of SPP. The NERC

estimate probably understates current NUG capacity

for this region. EEI, for example, reported that

Louisiana alone accounted for 7 percent (1,972 MW)

of the total U.S. nonutility generating capacity in

1986.

The planned use of nonutility generation in MAIN

is modest compared to other regions. Nonutility

generation is included as installed capacity in 1988

and only 12 MW is projected by NERC in 1997. The

region’s substantial low-cost coal-fired and nuclear

capacity has dampened nonutility growth.

Nonutility generation also is a minimal part of

MAPP’s resource plans. NERC forecasts that by

1997, nonutility generation will represent less than

1 percent of total capacity.

Regional Experience With

Nonutility Sources of Power

The recent growth in NUG capacity has benefited

both utilities and customers, According to EEI,

electricity sales to utilities from nonutility sources

have increased six-fold since 1979. Almost all of the

sales have been to the investor-owned segment of

the industry. In 1985 and 1986, receipts grew at

annual rates of 46 and 44 percent respectively, EEI

reports. 33 But, this rapid growth has also raised some

concerns by NERC over reliability. Some of these

concerns include responsibility for reactive power

support, voltage control, and the additional requirements imposed on utilities for supply planning

uncertainty, transmission loading problems, and

integration into utility operations. NERC and purchasing utilities face new challenges in how to

handle the additional planning uncertainties of

possible nonperformance or noncompletion of

planned nonutility generation. To some extent, these

concerns will be alleviated as the industry gains

more experience in effectively integrating nonutility

sources of supply.

Some regions have considerable experience in

developing working arrangements for dealing with

NUG power, including bidding. long-term contracts,

pricing terms, and dispatchability provisions. For

example, California regulators can require new

cogeneration plants to follow load through the use of

power-purchase contracts and regulation. Recently,

the California Energy Commission has required that

new 50+ MW cogeneration units agree to cycle as a

condition of their siting permits. As of mid-1988,

two “dispatchable load” contracts were in place and

others were expected.34

According to NARUC, 24 States have adopted or

plan to adopt competitive bidding as a means of

procuring QF power. Among them are Massachusetts, Maine, and California. Nonprice factors, such

jlc~if~mia Inde~ndent Energy Producers, California Summary, Alternative Energy Projects (4th Qwwter !9~7).

JzElect~i[. uli[i~ Week, “Independent Power,” k. 28, 1987.

JJEdlWn E]~tric Institute, supra note 19. P. 1.

ldE/eCtrlC.a/ World, “CogeMration: Threat or opp~unity?’” v()]. 202, No, 7, JUIY 1988, p. 66.
Chapter 6--Regional Characteristics of the Electric Power Industry ● 173

as dispatchability, also can be considered in the bid

evaluation. Michigan and Vermont are considering

price-bidding systems. Washington State has proposed a bidding system for investor-owned utilities

as a means of securing supplies from QFs under

PURPA. Non-QF capacity would not be included

under the State’s new rule. The Washington proposal is modeled on the system in effect in Massachusetts. 35

Other States—Connecticut, Rhode Island, and

Virginia—have adopted or allow nonprice competitive systems. The nonprice systems are used for a

number of reasons, which include encouraging QF

development in States and avoiding the possibility

of conflict with the legal requirements of PURPA.

Several additional States are examining bidding

systems: Idaho, Nevada, New Hampshire, New

Mexico, Oregon, Pennsylvania, and Utah.

REGIONAL DIFFERENCES AND

INDUSTRY CHANGE

The impacts of proposed regulatory and structural

changes will differ for individual regions, States,

and electric systems because of the differences

among existing systems and the wide range of

possible conditions and reactions that must be taken

into account. Among the most significant regional

influences will be:

adequacy of electric power supplies to meet

demand;

transmission access including availability, adequacy, and pricing;

the regulatory climate;

the competitive environment; and

impacts on retail customers.

These regional variations will strongly determine

how well and how quickly proposals for change can

be implemented.

Adequacy of Supply

Utilities base their assessments of power supply

adequacy on past experiences and future assumptions about the interplay of electricity demand and

growth rates and available power supplies. Changes

in electricity demand are reflected in both net energy

for load and peak demand and are influenced by

weather patterns, economic activity, and the effectiveness of load management and conservation

strategies. Power supply considerations include

installed generating capacity, reserves margins,

capacity availability, and the potential for bulk

power purchases.

These assessments are inherently uncertain, and

to counter the risk of underestimating demand,

utilities in the past may have overstated potential

demand growth in establishing their capacity needs

(including a typical 15 to 20 percent capacity

margin). In recent years, however, some utilities

have tended to project 10-year demand growth rates

that trail actually experienced increases in electricity

use. At these lower demand growth rates, NERC

currently forecasts that all its regions will have

adequate electricity supplies through the mid 1990s.

But if demand growth rates are higher than forecast,

many regions could need additional capacity earlier

than forecast. According to various analyses, areas

with potential shortfalls in capacity margins at

annual average growth rates exceeding 2 percent

include MAAC, MAIN, MAPP, NPCC, SERC, and

SPP.36 The analyses were not in agreement on all

regions, however.

In addition to differences in demand growth,

various capacity availability factors can influence

whether existing or planned generating facilities can

be used to supply power when needed. In addition to

the routine unavailability for regularly scheduled

maintenance and the unpredictable but inevitable

random forced outages, system characteristics and

external events can affect capacity availability and

reduce system reliability. For example, under some

conditions regions that are heavily dependent on a

particular fuel or generating source could face

35&/e~tri~~ worf~, 6‘Bl&J1~~ sy~[~~s: who H* Them ~d why, ” “o]. zo~< No, ‘3, M~ch ]$)~~, pp. 15-1(I. B~ed on N~~iona] [ndcpendcnl Energy

producers report “Pricing New Generation of Electric Power, A Rcporl on Bidding.”

MSW for exmplc, us. ~p~enl of Energy, Dcputy Assistant Secretary fOr EncrU Emevxn~i= “Staff Report: Electric Power Supply and

Demand for the Contiguous Unikd States 1987 -1996,” DOE/lE-(Kll 1, February 1988; Amy Abel, “Canadian Electricity, the U.S. Market and the Free

Trade Agreement, ” Congressional Research Service Rcporl 88427 ENR, July 5, 1988.
174 ● Electric Power Wheeling and Dealing: Technological Considerations for Increasing Competition

capacity availability restrictions that exceed their

capacity margins because of unforeseen fuel shortages or new environmental or safety requirements.

This vulnerability may create a sudden need for

replacement bulk power sources.

In ECAR, MAIN, MAPP, and SERC, over half of

the installed generating capacity is coal-fired. In

ECAR coal plants accounted for over 90 percent of

electricity generated in 1987. If new environmental

protection requirements are legislated to reduce

emissions associated with acid rain and global

warming, many of these coal plants, particularly the

older ones, would be directly affected. In the

extreme, compliance with emissions reduction strategies could shut down some of these plants temporarily or permanently.

ERCOT, NPCC, and SPP are heavily dependent

on oil and gas generating capacity and would suffer

adversely in the event of shortages or rapid price

increases in oil and natural gas.

During 1988, drought and low flow conditions

reduced the availability of hydroelectric plants in the

West and South. Low flow conditions can reduce

availability of water for cooling steam plants leading

to a downrating of their capacity.

Safety considerations requiring the curtailment or

shut down of nuclear plants could seriously affect

plant availability in MAIN, MAAC, MAPP, SERC,

NPCC and WSCC, thus reducing the adequacy of

electric supplies for these regions.

Regions or systems with a higher proportion of

aging plants may suffer a decline in availability if, as

expected, the older plants require more frequent

maintenance. In ECAR, MAIN, NPCC, and SPP

more than a quarter of all installed capacity in 1995

will consist of fossil-fired plants that are more than

30 years old. These “geriatric plants” may, however, prove to be valuable resources as some may be

very cost-effective peaking units and others may be

suitable candidates for life-extending refurbishment

to provide power at lower costs than equivalent new

plants. Some nuclear plants may face more frequent

operating restrictions as they age.

Bulk power purchases may be an attractive

alternative to building new utility capacity for

systems with concerns over supply adequacy and/or

reliability. The existence of a range of competitive

suppliers and the availability of transmission services to move the power would seemingly offer

benefits to these systems and regions. If the benefits

offered are perceived to outweigh potential risks, it

is likely that utilities and regulators would be

receptive to proposals for a more competitive

industry structure.

Utilities in area.. without surplus capacity are

likely to be less resistant to competitive supplies

both because of the need for reliable least-cost

capacity and because the competition covers increments of new supply and does not directly threaten

the loss of existing markets. There also will be a

regional incentive to work out transmission access

and other difficulties. If, however, a region does not

need capacity but in fact has a surplus of generating

capacity, expanded competition could have potentially adverse consequences for traditional regulated

utilities and their ratepayers in loss of market share,

bypass, and additional purchase obligations. On the

other hand, competitive markets might provide a

mechanism to sell some of their existing surplus

power and capacity.

Transmission Access

Transmission access considerations include the

terms (including price) under which a party will be

permitted to move power over the grid and the

conditions that influence the availability and adequacy of the transmission system.

Although theoretically possible because the necessary physical connections are in place, it is not

always possible in practice to move large amounts of

bulk power between any two points in the United

States over the existing transmission system. This

situation is not likely to change in the near future for

several reasons. First, available transmission capacity is limited and much of this is committed under

long-term contract. The existing transmission lines

in most areas of the country are already heavily

loaded with firm and economy energy transactions

according to utility industry sources. Second, the

United States is not physically integrated on a single

grid. The lack of extensive interties between the

three separate interconnections (not to mention

Alaska and Hawaii) will limit the extent of any

competitive markets that may evolve. This means,

for example, that surplus power from Texas (ERCOT)
Chapter 6-Regional Characteristics of the Electric Power Industry ● 175

will not easily be able to compete in markets in

Arkansas, Louisiana, and Oklahoma (SPP-SERC),

or in New Mexico-Colorado (WSCC). Third, transmission capacity usually cannot be added quickly. It

takes time to design, site, and build new or expanded

transmission facilities, and sometimes local opposition is intense. In extreme cases, it can take several

years or more to put a new line in place once a need

and cost effectiveness have been clearly established.

Finally, the as yet unestimated costs of building and

maintaining national or regional grids with ample

excess transmission capacity to accommodate a

broader range of potential power transfers are likely

to be high, and perhaps unnecessary for most needs.

In areas where the transmission system is already

heavily loaded, it has been asserted that at times

desirable bulk power transactions could not be

accommodated without exceeding minimum system

reliability operating guidelines. Comprehensive assessments of the locations and the extent of such

constraints have not been undertaken, nor are any

estimates available of the potential savings foregone. A frequently cited example of transmission

constraints is that surplus coal-fired power from the

Midwest cannot easily move to Northeast and

Southeast utilities that may be looking for additional

supplies because of transmission constraints or

bottlenecks in ECAR and MAAC. These constraints

have been partially attributable to the heavy use of

lines under long-term ‘‘firm” energy commitments,

power pool transactions, and parallel flows from

Canadian-U.S. transfers in NPCC.

Even if transmission capacity is available, without some sort of provision for assuring transmission

access, some line owners may be unwilling to open

up the grid to wheel power for others. The possible

reasons for refusals are many and include: to reserve

available capacity for the line owner’s opportunities

to sell or buy power at attractive prices; to maintain

redundant transtnission capacity to enhance system

reliability and flexibility; to restrict access to its

market area and customers by actual or potential

competitors; and/or an unwillingness to undertake

the burdens of additional regulatory, accounting,

and operating requirements that may be involved in

opening up the system. Some analysts note that lack

of effective economic incentives for wheeling services or adding transmission capacity under the

existing institutional and regulatory treatment of

wheeling arrangements is a major impediment to

increasing transmission access. 37

Existing regional transmission relationships among

utilities through power pools, coordination agreements, and Federal power marketing systems could

help the development of an effective transmission

access system. These ongoing relationships could

become the foundations for the essential institutional structure, precedents, and arrangements for

executing wheeling transactions to move power and

make deals. Without the necessary institutional

protections, greater competitive pressures and the

attractiveness of profitable off-system bulk power

sales could lessen the characteristic cooperation of

joint operations and power pools. Growing rivalry

among regional utilities could discourage sharing of

information and generating and transmission resources, adversely affecting reliability and power

pool operations. Competitive pressures could yield

lower capacity margins and reduced maintenance of

facilities in an effort to cut costs. But, at the same

time, generators would continue to share a common

direct interest in maintaining optimum system operations, which perhaps could counter behavior that

might imperil current reliability levels.

The extent to which interregional or intersystem

transmission access or availability will become

more or less critical in the future cannot be predicted

with any certainty. The existing demand for and

interest in transmission services are the result of

several conditions:

. current capacity surpluses and shortages,

. differences in bulk power prices/costs,

. relative locations of load centers and generating

plants,

● availability of and eligibility for wheeling

services, and

● industry structure and practices.

Because many of the above conditions can change

over time, a significant share of the present demand

for transmission services could be transitory and

could disappear in a shorter time than that needed to

JTNatlona] Rewlat~~ Re~~~h ]nstltu[e, Some E(,ono~’c PrinclP/~s for prl~lng w~e?~e~ Power (NRRI-87-7) AUgUSt 1!)87; National Regulatory

Research Institute, Non-Technicul Impediments m Power Trun$ers (NRRI-87-8) !kptember 1987.
176 ● Electric Power Wheeling and Dealing: Technological Considerations for Increasing Competition

Photo credit: Casazza, Schultz & Asao@ates, lnc.

A high-voltage transmission corridor

plan for and recover investments in additional Changes in fuel costs could eliminate much of the

transmission capacity. bulk power price differentials driving many wheeling transactions. For example, when oil prices were

For example, if new generating sources locate

close to load centers and within the local transmission grid or service areas of customer utilities, the

need for some long-distance firm and economy

power transfers would be reduced and the transmission system could at least in part revert to its role as

a means of providing emergency power. There is

some evidence that utilities are giving preference to

generating capacity additions that reduce demands

on the transmission system.38

very high, a transmission interface was built to tie

the surplus coal-fired generation in the Southern

Company system to oil and gas-fired utilities in

Florida. With lower oil prices and new generating

capacity on line, power purchases from the Southern

Company are sharply down and the interface is

loaded far below its previous levels (one of the very

few examples of acknowledged surplus capacity).

While some portion of transmission demand

could be transitory, the electric power industry’s

38~x&~ Uti]ities is ~ding combustion twbines t. its system ~[ rem~[c sy~tcm p~jn[s r~thl~r (h~ at ~ Cenud location in order IO avoid thc need for

additional transmission, Electrical World, tel. 202, No. 7, July 1988, p. 31. l.mation has frequently been ackrwwlcdged as an important “nonpriee”

factor in evaluating competing bid$.
Chapter 6--Regional Characteristics of the Electric Power Industry 177

structure and practices assure that the extensive

transmission network will continue to be needed

under various future scenarios. Joint operations and

power pooling arrangements are motivated by reliability and economic concerns. Strong transmission

networks are needed to move power to load centers

from distant generating sites. Long-term contracts

and other arrangements are in place to move power

from coal plants in Arizona and New Mexico west

to California, and from hydroelectric projects in

Quebec south to New England and New York. Other

agreements exist to take advantage of seasonal load

differences, such as the current and planned 1ongterm power contracts to move power south from the

Pacific Northwest in summer and north from California in winter. These transactions will be of

concern not only to the parties involved but also to

other utilities on the interconnected systems because

of their inevitable influence on the grid.

Many utilities, particularly in the public sector,

rely on bulk power purchases to supply all or part of

their requirements. These utilities (or distributiononly utilities under some competitive scenarios)

would still seek lowest cost supplies for their

customers and will press for wheeling services so

that they are not necessarily tied to a single

monopoly supplier.

Transmission concerns will remain even if the

extent of economy transfers diminishes, growing

demand absorbs surplus capacity, and new generating capacity is built. Utilities, generators, and

customers will share a common interest in the

reliability and security of electric power supplies.

New patterns of bulk power transactions and the

entrance of nontraditional power suppliers have

accelerated the breakdown of the old model of the

regionally isolated integrated system generating and

transmitting power solely within its exclusive territory to serve the needs of (captive) customers.

The Regulatory Environment

The regulatory environment created by State and

Federal policies could advance or hinder a shift to a

more open, competitive electric power industry. A

number of States have already allowed utilities

under their jurisdiction to use competitive bidding or

negotiation to secure new power supplies and to

establish avoided costs—thus advancing competition.39 The Federal Energy Regulatory Commission

(FERC) has proposed rules to allow the use of

competitive bidding to set PURPA avoided-cost

capacity payments and to encourage the entry of

independent power producers. Both of these measures are intended to encourage competition. However, some State regulators have criticized the FERC

proposals as actually hampering and delaying the

growth of competition by preempting State initiatives in the area and requiring extensive changes to

many State regulatory programs. State regulators

and others have criticized the lack of explicit FERC

guidance or rulemaking on transmission access and

pricing issues as constraining the growth of competitive markets by shutting out potential buyers and

sellers.

Some options for reform of the existing system

could impose additional burdens on regulators,

consumers, and State jurisdictional utilities (such as,

for example, the proapproval process in scenario 1

and the needs determination and bidding programs

of scenario 3). The increased involvement of regulatory agencies is a necessary component of the

reforms intended to avoid the risks of regulatory

disallowance under existing law.

New Federal initiatives could also diminish the

effectiveness of State and local programs in consumer representation and protection, siting, alternative energy technologies, conservation, and energy

efficiency.

The most significant area of regulatory policy is

establishing the appropriate and respective roles of

State and Federal regulators. This task has been

made more difficult by recent FERC actions and

J~Al IeUt 24 states have adoplcd or are &VC]Oplng varia~lons of compctilivc procurement programs for some Or al! of rC@attXl Ulillllcspower needs.

Among the Stales that have adopted bidding programs arc: Vlrgmia, Connectwut, Maine, Massachusc[ts, Ncw York, Calilomia, Texas, and Colorado.

Some have imposed wheeling requirements on instate utihtics m conJunciwn wilh PURPA implementation. Many S[atcs htwc iilrcady moved 10 correct

early difficulties with PURPA avoided costs. Slates’ an[icipa[ory ovcrslgh[ of utilitlcs generation and uansrnis$ion rcsourcc planning incrcusingly

encourage consideration of compctnlvc and rcjymal needs. Scc Mary Nagclhoul, ‘‘Compctitlvc Bidding In Electric Power Procurcmcnt: A Survey of

State Action,” Public Utlllfies Forfmghtl), Yol, 121, No. 6, Mar 17, 1988, pp. 41-45.
178 ● Electric Power Wheeling and Dealing: Technological Considerations for lncreasing Competition

U.S. Supreme Court decisions.40 The split jurisdiction over utility regulation has long been an area of

tension and source of uncertainty. Recent State

efforts might be stymied by Federal preemption of

their regulatory programs if existing initiatives were

not grandmothered under new Federal rules. The

limited State jurisdiction over transmission access

also tends to undercut State implementation of

competitive strategies. As noted in chapter 3, it is

possible under some alternatives to delegate to the

States certain responsibilities for transmission jurisdiction now resident at FERC. This could perhaps be

coupled with a right of appeal to FERC or the

Federal courts. One advantage of such an arrangement is to move decisions on system use, retail

wheeling, and prudence back to those who must

weigh competing local interests in approving resource plans, siting, and retail rates. In cases

involving interstate transactions, there might be

some mechanism for consultations between States

or referrals to FERC. This could foster more

comprehensive State and regional cooperation on

transmission issues.

The confidence of the affected parties in the

decisions of regulatory authorities or in the mechanisms that substitute for the operations of the

regulatory system will be very important for the

success of initiatives for a more competitive system.

If, for example, consumers believe that their interests are not adequately protected, or perceive that

utilities or independent power producers are unduly

enriched by the new arrangements, their political

opposition to the alternative may well doom its

long-run success.

Competitive Environment

The competitive environment in a utility system

or region will be a major influence in how rapidly

and successfully any shift toward a market-based

sector will proceed. There are many tangible and

intangible factors that will shape the competitive

environment, and these will likely be tied to

site-specific and regional conditions,

The existing power system infrastructure and

institutional arrangements could either help or

hinder market entry and competition in a State or

region. If there are one or more dominant utilities

with control of critical facilities, such as low-cost

generating facilities, distribution companies, or

transmission systems, new entrants could be deterred from competing in that market area. If most

bulk power supplies are already committed under

long-term contracts or there is a surplus of existing

low-cost power, opportunities to compete for new

power supplies could be limited. But a demand for

power or a specialized niche for potential competitors can create market opportunities that attract

competitors. In the Northeast, with the support of

State regulatory commissions, many utilities are

actively soliciting bids for capacity increments from

QFs and other suppliers, In four States (Connecticut,

Maine, Massachusetts, and Virginia) that have

completed competitive solicitations, the bids far

exceeded the amount of power sought.

The availability of sufficient transmission capacity to support the growth of a competitive regional

bulk power market is also important. Mandatory

wheeling authority would not be of much help to

guarantee transmission access if the system is

already fully loaded.

Impacts on Retail Customers

Impacts on retail customers will ultimately determine the acceptability of any electric power industry

structure and its longevity. The most significant

effects will be in retail electricity prices and changes

in reliability or quality of utility services. Local

experiences and perceptions will be different. In

some regions, a move to a more competitive

structure may be perceived as a net benefit, in others

it may become the focus of all dissatisfaction with

electric power system operations and prices. If the

latter is the case, consumers will pressure their

elected officials to reform the system.

In weighing various proposals for change, regulators will have to deal with a range of equity

considerations in the areas of public service and

accountability, distribution of costs and benefits,

and system reliability. Often there will not be

adequate information available to respond fully to

q~hc recent expmsion of F~dCr~l preemptionis Wcn in the FERC decision in Orange itnd RoCkl~d U{ilitics, lnc,, 92 PUR 4th 1988, ~d the U.S.

Supreme Court’s decision in Mississippi Power& Light (-o v. Mississippi ex rel, MOOII t4ttorney Gvneral of Mississippi et al , No. 86-1970, June 24,

1988.
Chapter 6--Regional Characteristics of the Electric Power Industry ● 179

these concerns and the determination will rest on the

best judgment of decisionmakers.

OTA SCENARIOS AND REGIONAL

IMPLEMENTATION

The impacts of OTA’s scenarios, as with similar

proposals, will depend on the characteristics of the

individual utility systems and State regulatory

bodies. The detail required to analyze and predict

these potential impacts lies well beyond the scope of

OTA’s review of the technical feasibility of implementing the scenarios. Nevertheless, the local impacts will create significant considerations for policy makers. It is notable that none of these impacts

has been examined in any systematic, comprehensive way in the various proposals that OTA used in

developing these scenarios.41 Even FERC did not

provide any substantive analysis of the potential

impacts of its recent Notice of Proposed Rulemaking

(NOPR) beyond its assumed “worst case” environmental impacts analysis, which was driven by

arbitrary assumptions on fuel use, technology

choice, and generation by independent power producers .42 A further confounding problem in ascer- .

taining potential impacts is uncertainty over how

wheeling transactions will be priced. Although

transmission pricing was outside the scope of this

assessment of technical feasibility, it will be highly

determinative in shaping the extent of and participation in competitive markets under all scenarios.

Scenario 1

Scenario 1 would modify the existing State

regulatory programs to require State proapproval for

construction of new utility capacity with prudence

determinations at strategic milestones in each proj ect 43 The S . cenm o would also include Federal and

State regulatory changes to remove some of the

problems encountered in early implementation of

PURPA, such as limiting the categories of eligible

facilities and bringing PURPA energy and capacity

payments more into line with utilities’ actual

avoided costs.

Under this scenario. as in others, major impacts

will be local and utility-specific. The reduced

regulatory risk of disallowance may provide an

incentive to reluctant utilities to identify and construct needed capacity earlier than they might

otherwise plan under a risk aversion strategy. It is

not known how many utilities, if any, would fall into

this category. where they are located, and how much

needed capacity would be affected.

Scenario 1 would affect the regulatory systems in

all States,44 although the potential disruption of State

programs may be tempered somewhat by the fact

that many States already have incorporated elements

of scenario 1 in their State programs.45 These key

elements include prior review and certification of

need for new capacity and review and approval of

utilities’ resource plans. The existing precedents of

regulatory standards for prudence could be applied

in a periodic milestone review. Most States have

allowed recovery of prudent investment on abandoned plants.

Although no State has adopted the equivalent of

scenario 1, Massachusetts recently established a

proapproval process for new non-QF capacity that

would, among other things, set the allowed rate of

4 I ~ne ~xccp[lon t.~c general 11’~ of&(ailcdan~]ysis of lhc more pOpU]M schemes for change is found in the rcvlcw of various dcrcgu]ation ScCnWIOS

by Paul L. Joskow and Richard Schnlalcn=e, Markets for power” An A~iysi.$ @Ele~”trical~~tilir?’D ere@ution~ (Cambridgct MA: The MIT press. 1~~~)

They mo were somewhat hampered by the unavailability of data with which to conduct any detmlcd analysis.

‘$zFedera] Energy Regulatory commission, Draft Environmental Impacl !Malemcm on Regulations Govcming lndcpcndcnt Power Producers

(RM88-4-O(KI) and Regulations Governing Bidding Programs (RM88-5-000), June 1988.

431[ is conceivable that F~era] legisla~ion ( Iikc ~uRpA) ~Ould require States to adopt a proapproval S~CtUrc within FERC guidCllnCs, but ICaVC? the

details of implementation to the States. Legislation could also rcqulrc that FERC folh)w Stulc planning and preapprovaJ proccsscs or confer with State

regulators in considering rate requests and rates of rctum for FERC jurl.sdictional utiliues.

44 Except ~rhaps Nebraska which rclles so]ely on public power and has no Statewide ratcsctting bdy. Texas, Alaska, and }+iIwaii uc a]so Stales where

the impacts on existing regulatory programs are unccrtam because dtcy arc not generally connc~tcd K) Lhc rest Of t.hc intcrslalc electric power systcms

and thus are not fully under FERC jurisdictmn. nc changes in PURPA rules would, however, afiecl Slalc pLJRpA rc~lalo~ programs and unregulated

utilities.

45&e discussion inch, ~ ~d ‘‘Transmlssi~n Lln~ c’cflifi~~[i~n and Siting procedures and Encrb~ p!artnin~ prOCCSWS: SutIMtWy Of StalC Govcmmcnt

Responses to a Survey by the National Govcmors’ Associwon Task Force on Elcctriclty Transmission, ” prepared by staff mcmbcrsof the Public Utilities

Commission of the Slate of Ohio and of the West Virginia Public Scrvicc Commission, OTA contrmlor report, July 1988 (hcnxtftcr State Gowmmcnt

Survey responses).
180 ● Electric Power Wheeling and Dealing: Technological Considerations for increasing Competition

return in advance of project construction.% More

than half the States have a least-cost planning

program in place or under development. Most States

require utilities to submit long-range plans for

generation and transmission requirements.47 More

than 24 States already have approved bidding

programs and others currently are considering them.

Most State programs provide for regulatory review

and approval of resultant utility contracts. (Some

specifically defer decisions over the prudence of the

power purchase arrangement until the time of power

delivery, however.)

To accommodate this multi-stage regulatory process, State agencies will have to increase staff and

budgets or divert resources from other activities.

Utilities also would see some increase in their

regulatory activities. The greatest regulatory impacts would be felt in States in the West and

Southeast that typically have State regulatory programs with a more traditional, reactive approach to

ratemaking and that do not have much involvement

in anticipatory oversight or review of utilities’

resource planning.a

The scenario would give States the flexibility to

allow experiments in competition for bulk power

supplies as they wished. Under scenario 1, transmission access remains largely voluntary under existing

law. Depending on whether or not FERC addresses

the issue. the lack of effective transmission access

remedies could hinder further development of competitive markets.

The fine-tuning of PURPA avoided cost and QF

eligibility requirements might reduce avoided cost

payments and the amount of available QF power in

States such as California, Texas, and Colorado

where high avoided cost rates or high QF capacity

potential have provided an initial abundance of QFs

seeking contracts with local utilities.

Scenario 2

Scenario 2 would expand QF eligibility criteria

under PURPA and provide greater access to wheeling services for wholesale and retail customers. This

scenario could have significant local impacts. On the

one hand, scenario 2 could expand the current

abundance of QF power in some regions. On the

other hand, the influx of additional QF power could

drive QF avoided cost payments down, providing

some financial relief to host utilities and their

ratepayers. (This would be of only limited value if

high cost QF capacity is already under long- term,

fixed-price contracts.) Availability of wheeling could

allow QFs, independent power producers (IPPs), and

utilities greater access to potential customers for

their power and could reduce the purchase obligations of some host utilities. The wheeling of QF

power from the host utility’s service area to utilities

with higher avoided cost payments, who must then

purchase the offered power, is an option under

existing law, but there is no mandatory transmission

access under PURPA.

The scenario could favor large fossil-fueled QFs

and IPPs that enjoy some economies of scale and

discourage the smaller alternative generating technologies originally targeted in PURPA, unless the

smaller facilities could match competitive prices. It

could also result in different local environmental

impacts than would arise from the plant mix under

the existing system.49

Scenario 2 would require Federal legislation and

complementary changes in State regulatory systems.

If States were given authority over retail wheeling

requests, States could make the public interest

determinations associated with problems of bypass

and interclass allocations of system costs in the

ratebase. The availability of retail wheeling would

mean that utility systems with higher retail prices

than other systems in their regions could see

increased vulnerability to bypass, and loss of cus4ti*4A Rc~ M~S~h~ttsMir~le,” p~fic. U/i/ifiesFor/ni~h//y,vo].]21, No. 15, .lu]y 2],l!)~~, pp. 6-7; Massachusetts Dcpartmentof Public Utlhtk,

“pricing and Rate-making Treatment to Be Afforded New Electric Generating Faeilitics Which Are Not Qualifying Facdities, ” D.P.U. 86-36-C, May

12, 1988.

4TS[ate Government Survey Responses, supra note 45.

481bido

4-~Cdaft EIS ~sumes that cxp@Cd p~icipa[ion of ~ps wi]l di@~e QF capwi[y (coal, oil, gas, and was(c), See DEIS ch. 4, supra nolc

42. See also the discussion inch. 7 of this report.
Chapter 6--Regional Characteristics of the Electric Power Industry ● 181

tomer load and revenues.50 Under scenario 2 bypass

could be exacerbated not only among retail customers, but also, more significantly, among wholesale

requirements customers.

The additional transmission incentives under

scenario 2 could include more explicit consideration

of State and regional transmission needs in energy

planning and ratemaking decisions. State or regional

entities might offer to mediate arrangements for

compensation and/or mitigation with affected property owners and localities, for example, to assist in

resolving conflicts that might hamper needed transmission facilities. Regulators would be more involved in oversight of transmission. Federal and

State regulators might encourage a greater willingness for voluntary provision of transmission services

through experiments in pricing wheeling transactions and incentives for expansion of transmission

capability.

If transmission prices and interconnection conditions are not so onerous as to render transmission

access provisions ineffective, the stresses on already

heavily loaded transmission systems will increase

and create even more pressure for additional capacity. If scenario 2 results in a large net increase in

system demands, areas in ECAR, MAAC, NPCC,

ERCOT, and WSCC are likely to see the most

serious effects. Scenario 2 could result in utilities

being ordered by States or FERC to construct

additional transmission capacity to provide wheeling services. Scenario 2 would not preempt local and

State authority over siting approval, however. This

result would also occur under scenarios 3, 4, and 5.

Scenario 3

Scenario 3 is similar in some aspects to FERC’s

competitive bidding NOPR, but requires that all

States use competitive bidding and also includes 51 The responsibili- mandatory wheeling authority.

ties and administrative burdens carried by State

regulatory agencies would increase markedly under

this scenario, most noticeably in States with more

modest traditional regulatory programs and in those

States with high growth in electricity demand.

FERC’S administrative caseload would also increase. Under scenario 3, regulatory proceedings

would probably involve more parties as competitive

power suppliers joined utilities, regulators, and

consumers in needs determinations and in the review

and awarding of new source contracts.

The participation in all source competitive bidding in areas needing capacity would depend on how

the solicitation is structured and the weighting of

nonprice considerations. In particular, many traditional QF cogenerators and small power producers

could be discouraged from competing in a highly

structured bidding program against larger and more

sophisticated IPPs and utility affiliates. Similarly,

conditions such as wheeling requirements or protections against self-dealing could constrain utility

participation both inside and outside their service

territories. In its draft Environmental Impact Statement (EIS), FERC projects that its proposed rulemakings on competitive bidding and LPPs might

result in significant displacement of incremental

utility and” QF capacity, including some renewable

energy technologies. Additionally, the draft EIS

concludes that the locations of new generating plants

and transmission loading patterns could be shifted

among various regions.52 It also expresses doubt that

real impacts would be felt until the mid to late 1990s

at the earliest because of existing capacity abundance. In the limited experiences with competitive

solicitations that have taken place, there has been a

mix of IPPs, utility affiliates, and cogeneration

projects proposed, but it is still too early to

determine what would happen if all source competitive bidding were to replace the existing alternatives

of utility construction, negotiated purchases, and

required QF purchases.53

The availability of wheeling might encourage

wholesale requirements customers to seek alternative power suppliers, possibly exacerbating the

problems of ‘‘stranded investment” and bypass on

SOM~y high.cost ~ti]ities a]~ady f~e problems ~au~ of con~rvation, self-generation, and or phml-ciosings, Wheeling, ~d in particular rclal]

wheeling, would give their customers another means of avoiding the high prices of local utilities. This problem would exist under scenario 3, but withoul

the additional strains of retail wheeling.

51 ]t hm ~n ~w~ that tic effWtlve resu]t of tie three ~RC NopRs is lo irnposc a]] source Compelitivcbidding 011 Sta[es, since COmpkUICC With

requirements for administrative avoided costs would be unduly burdensome so that regulators and utilities would rely on bidding.

52DEIS, supra note 42, ch. 4.

53see dlscu~slon in ~h, S on the Ca]lfomia, Maine, ~d Vlr@nia Comw[i[ive bidding ~ystcms and in ch. 7 on ~~ Massachuse~[s bidding system,
182 . Electric Power Wheeling and Dealing: Technological Considerations for Increasing Competition

high-cost utility systems. The departure of existing

customers could leave the remaining ratepayers with

the burden of paying for a system that is larger than

required unless regulators shifted a sizable portion

of the losses to the utility and its shareholders.

Because there is no retail wheeling under scenario 3,

its impacts on the transmission system might be less

than those of scenario 2, at least initially. More lines

might eventually be built in scenario 3 than in

scenarios 1 or 2 to support the competitive system

and to open up new markets as the industry shifts

away from the old model of self-sufficient integrated

regional utilities tied together for enhanced reliability.

According to some proponents, the expanded

competitive market and availability of wheeling

could theoretically dampen the discrepancies in the

prices of power within and among regions as

lower-priced power is bid up and higher-cost/higherpriced producers are forced to cut costs or be

displaced. Because electric power would typically

be committed under long-term contracts, it is not

clear how long this will take and how great the

impacts will be on consumers and electric supplies

over the period needed for market forces to accomplish this result.

Scenario 3’s success will in large part depend on

local characteristics. The early impacts and experiences will come in areas that need generating

capacity from 1995 through 2000. In some areas,

however, the power solicitations might not draw

enough competitive interest to rely solely on bidding

results to set power prices. Reliance on competitive

awards might make some areas heavily dependent

on NUG power with potentially greater risks of less

flexibility in control of generating resources as

discussed in chapter 5. Whether this results in

lowered reliability for the power system will depend

on the adequacy of alternative protective arrangements to compensate for changes in the resource

base and system operations. Utilities could offset at

least some increased risk by building or contracting

for higher levels of reserves than they would under

a traditional cost of service system.

Over the long term (20 to 30 years and more),

scenario 3 would move the industry toward a

competitive generation sector within a regulated and

integrated utility structure. This evolving structure

will eventually raise some of the same issues

presented by scenario 4 about the preservation of

competition as an alternative to traditional cost-ofservice regulation/pricing, fairness to ratepayers in

treatment of proceeds from use of ratebased facilities

and intangible assets in promoting competitive

activities, and the long-term bargaining power and

viability of regulated transmission and distribution

sectors.

Of concern under both scenarios 3 and 4 is that

some regions may not initially have enough viable

suppliers to sustain a competitive market that could

be relied upon to set prices in lieu of regulation. This

possibility is created in large part by the existing

patterns of regulated utility holdings and franchise

territories.54 This may be a particular problem in

regions where very large integrated private utilities

and holding company systems occupy strategic and

dominant positions in ownership of generation and

transmission resources. New entrants could be

intimidated in situations where utility control of

transmission facilities and the uncertainty of gaining

a wheeling order combine to restrict access to

potential customers.

Scenario 4

Scenario 4 would create an all competitive

generating sector over a moderately short transition

period (of 5 to 10 years for example as compared to

the evolutionary approach in scenario 3). New

segregated generating subsidiaries or spinoffs of

existing integrated utility companies would initially

control an overwhelming share of generation resources under the new system. All generators would

be able to sell power and would be eligible for

transmission services. The transmission and distribution segments would consist of the segregated

transmission and distribution operations of formerly

integrated utilities and wholesale/requirements customers. Transmission and distribution utilities would

remain regulated and would retain an obligation to

serve. There are a number of major uncertainties in

how scenario 4 will be implemented that will

strongly influence its outcome. The major regional

impacts/uncertainties of scenario 4 focus on the

viability of competition and the role of State

regulation.

54S= Joskow and !khmalensec, supra note 4 I.
Chapter 6-Regional Characteristics of the Electric Power Industry ● 183

Under scenario 4 there is the possibility that

newly independent local generators will use access

to transmission to flee existing service territories for

more lucrative markets, leaving ratepayers and

distribution utilities without adequate suppIies and

facing substantial rate increases.

The existing regulated industry structure will not

provide an initial level playing field for creating a

new competitive industry. Existing franchise territories and generating resources as well as the considerable financial strengths of some utilities will create

competitive advantages. Other utilities may start at

a competitive disadvantage. As a result higher-cost

producers that once enjoyed the protection of their

government-franchised territories could be driven

from business under a market-based system, and

there could be a marked trend toward consolidation

in the generating sector. Some transmission and

distribution utilities would also become candidates

for mergers or acquisitions.

Regions and States with extensive existing transmission arrangements through power pools, coordination agreements, and Federal power marketing

systems might have an advantage in creating the

necessary institutional infrastructure for separate

transmission utilities under scenario 4.

If all bulk power supply arrangements fall under

exclusive Federal jurisdiction because they are

‘‘sales for resale, ” State and local regulators with

jurisdiction over distribution companies face the

loss of any effective influence over generators, thus

imperiling the adequacy of their regulation of

transmission and distribution. New Federal and

State policies may be needed to protect the interests

of ratepayers and the public under a changed market

and regulatory structure.

Scenario 4 has a very high potential for substantial

impacts on consumer electric prices in many regions, if the transfer from regulated rate-based assets

and service territories to unregulated competitive

generators and open markets is not handled equitably. In the transition, utilities could gain windfalls

from the sale of low-cost power produced by older,

depreciated plants or from the sale of those plants.

The profits could be transferred to or retained by

their new unregulated generating companies. Policymakers could limit this potential by requiring that

rate-based assets from the predecessor integrated

utility be transferred at either replacement or market

cost with the proceeds going to the successor

regulated distribution utility and its ratepayers.

Additionally, communities and ratepayers with low

retail rates may lose many of the financial benefits

of past sound and prudent utility management and

regulatory oversight as the owners of newly liberated generating plants rush to sell their power at the

highest price.

Scenario 5

Scenario 5 also involves the dramatic revamping

of the electric power industry and the transfer of

billions of dollars in ratebase assets; it differs from

scenario 4 in two respects. First it would involve the

actual disintegration and divestiture of utility assets

into separate legal and financial entities, while

preserving the ongoing viability of integrated operational functions through the creation of new entities

and new institutional arrangements. Second, its

common earner transmission entities would provide

wheeling services for retail customers.

Scenario 5 shares almost all of the concerns over

industry concentration, preservation of competition,

and reliability as scenario 4 plus the additional

challenges and complications of creating a commoncarrier transmission system that will adequately

serve the needs of utility and nonutility customers.

To be an effective entity, the common carrier

transmission company would likely be involved in

multistate operations and would thus create additional challenges to Federal and State regulation and

oversight of rates, planning, and siting activities.
184 ● Electric Power Wheeling and Dealing Technological Considerations for Increasing Competition

REGIONAL PROFILES55

The East Central Area Reliability Region

(ECAR)

Voting membership in

ECAR is open to those

members that meet three

criteria. They must: own

an electric utility system

engaged in the generation, transmission, and PENNSYLVANIA

sale of power in the INDIANA

region; operate in synchronism with two or

more members in the

Agreement; and have a

significant impact on reliability. Nonvoting members are those systems that do

not have a significant impact upon reliability but share

concerns relating to the reliability of bulk power supply.%

Fuel Use

ECAR is heavily reliant on coal and is expected to

continue this reliance well into the 1990s. Nuclear is

projected to increase slightly its share of total electricity

production from 8.7 percent of the total in 1988 to 9.3

percent in 1997.

Capacity

According to NERC, installed capacity will increase by

about 7,100 MW by 1997. only three major unit

additions, totaling 3,095 MW, are scheduled during the

1988-1997 period. Very little new capacity is scheduled

for operation after summer 1991.

Average annual growth for the period 1988 to 1997 is

projected to be 1.6 percent for summer and 1.7 percent for

winter. ECAR is expected to be summer peaking throughout the period.

Transmission

ECAR has an extensive system of intrasystem, intraregional, and interregional connections ranging from

115 kV up to 765 kV. According to NERC, current plans

for the 1988-97 period call for an additional 100 miles of

500 kV and 200 miles of 345 kV transmission lines.

Transmission networks in the eastern part of the region

provide connections with Southeastern and Northeastern

areas of the United States. Networks in the western part

of the region provide interregional connections with

MAiN. These ties result in substantial interregional power

transfer capacity. The American Electric Power Company

owns about 40 percent of the high-voltage capacity in

ECAR.57

In recent years, ECAR’S extensive transmission network has experienced numerous large-scale economy

transfers, which are created by fuel-cost differentials.

These intraregional and interregional economy transfers

have caused power flow patterns that were not anticipated

when the system was planned. To continually ensure

transmission system reliability, ECAR and neighboring

regions conduct performance evaluations before each

summer and winter peak load season and annually.

Bulk Power Transactions

Within ECAR, bulk power transactions to other

regions, especially the PJM Interconnection and Virginia

are based on load diversity and fuel cost differences.

American Electric Power and Allegheny Power Systems,

two large holding companies in the region, dominate sales

transactions 58 and control much of the transmission grid.

ECAR utilities surveyed by NGA reported the smallest

amount of bulk power purchases-3 contracts for 188

MW. On the other hand, ECAR utilities reported contracts

to sell about 3,6(M) MW, second only to SERC in terms of

sales. The length of the contracts ranged from 6 months

to 3 years.

Coordination

Coordination in this region ranges from tight holding

company pods, to less integrated pools, to individual

utilities that do little coordination. Generally, the region’s

holding companies and power pools coordinate very

●

Reliability

According to NERC, the existing and planned electric

power supply in the ECAR region will satisfy the region’s

reliability criteria if generating equipment continues to be

available at present levels and load and capacity conditions are as projected. Even a small decline in generating

equipment availability and/or a slight increase in load

55R~giO~ ~ofi]es wc b~ primarily on NERC dOCUJIRnUA u~~ *i*

Ss’’Rcliability Council Survey Responses,” SUpra tic 2, P. 5.

STFERC, Power Pooling, December 1981. P. 96.

58~E, ~nlemtlli~ ~~k power Tr~~~~ . f)eS@~O~, &O&S, ad Data. October 1983, p. 41.

59FERC, supra note 57, p. 97.
growth could quickly reduce the future power system

reliability to unacceptable levels.

NERC expects capacity margins to decrease over the

next decade, from a current level of 23 percent. As

capacity margins decrease, generating units will be

utilized more intensely. Placing greater demand on these

units may be increasingly difficult as plants get older. By

1997,42 percent of all generating units in this region will

be 30 or more years old.

Furthermore, because of its dependence on coal to

generate electricity, ECAR is especially vulnerable to

acid rain legislation. Strong new pollution control equipment requirements could affect the availability of coalfired generating capacity in the region, possibly reducing

reliability.

Electric Reliability Council

of Texas (ERCOT)

Membership in

ERCOT is open to any

entity that owns, controls, and operates an

electric power system in

Texas. Members’ votes

are weighted on the basis

of the average number

of kWh handled through

the intrastate system for

the preceding 3 calendar

years. Each entity is assured at least one vote.60

Fuel Use

ERCOT utilities rely heavily on coal and gas to

generate electricity. NERC projects that by 1997 coal will

increase its share to 44 percent, and gas use will decrease

from a 45 percent share to a 33 percent share. Nuclear will

account for about 11 percent of the total.

Capacity

ERCOT is expected to increase its installed capacity by

about 12,500 MW between 1988 and 1997. Member

utilities indicate an average annual growth rate of 2.4

percent (summer peak) for this period, which is a

reduction from the 3.9 percent rate projected in 1987.

Winter peak demand is forecast to grow at 3.2 percent for

the same period.

Transmission

in recent years, ERCOT has experienced increases in

both firm and economy energy transfers. At the same

time, transmission additions have not come on line as

quickly as anticipated. Moreover, planned additions have

been reduced. ERCOT expects to install about 931 miles

of 345 kV lines during the next 10 years. This figure

represents a 29 percent reduction from the 1()-year

projections made in 1987. In 1987, ERCOT had 6,871

circuit miles of 230kV and above transmission lines.

Bulk Power Transactions

Because ERCOT utilities are isolated from the Eastern

and Western Interconnected Systems, bulk power transactions based on generation diversity are 1imited. Even so,

the average ERCOT utility has about the same volume of

transactions as does the average L’. S. utility, according to

DOE. 6l This may be due, in part, to the wheeling of QF

power from large cogenerators in the region, The NGA

survey found that ERCOT utilities had contracts to buy

1,760 MW and sell 3,200 MW.

Coordination

The Texas Interconnected System (TIS) is the umbrella

coordinating group in ERCOT. Its primary focus is on

bulk power supply reliability, through coordinated planning and operation. Bilateral agreements form the core of

existing coordination.62

Reliability

NERC expects planned capacity resources to be

adequate during the 1988-97 period. The projected

capacity margins range from 21.3 percent in 1988 to a

high of 23.6 percent in 1990 and to a low of’ 16.4 percent

in 1996. These margins exceed The planning guidelines

adopted by the region. Nonutility generation will supplement ERCOT’s short- and long-term capacity needs.

On the other hand, transmission system reliability is of

some concern to ERCOT. Increases In economy and firm

interchanges have placed a strain on portions of the

system. NERC expects further increases in transmission

system usage to continue because of wheeling for utilities

and nonutility generators. According to NERC, during

1986 wheeling of firm electric power amounted to 2,148

MW of capacity —..55 percent of regional peak demand.

Contributing to this situation is the fact that transmission improvements have not proceeded as planned. One

major concern is the recent decision of the Austin City

~’ ‘Rc][abili(y co~~i] SUIVCy Response, ” SUPHI nOIC ~, P. ~.

61DOE, supra no~c 58, PI 42

~zFERC, supra nOtc 57, p. ] 32.
186 ● Electric Power Wheeling and Dealing: Technological Considerations for Increasing Competition

Council to cancel construction of several 345 kV lines that

were originally scheduled for service in 1988. Concern

about possible health effects of electric and magnetic

fields was one of the reasons given by the Council for

canceling construction. In addition, the Texas Public

Utility Commission rejected the proposed Salem-Zenith

interconnection. The decision is currently being appealed

to the courts.

Another reliability issue is the region’s reliance on

natural gas as a boiler fuel. The long-term availability and

price of this fuel will impact reliability in the future, but

to a lesser extent than in other areas as Texas is a major

gas producer.

Mid-Atlantic Area Council (MAAC)

MAAC voting members must meet three

criteria. They must be

directly interconnected

and operated in parallel

with one or more MAAC

members; their operations must significantly

impact the reliability of

the bulk electric supply

systems of MAAC members; and they must abide

MAAC

by the rules of the Executive

Board. Nonvoting members-may include any municipal

systems, rural electric cooperatives, or small investorowned utilities that are served by MAAC members and

agree to the principles of the MAAC agreement.63

Fuel Use

MAAC relies on coal and nuclear-powered generation.

By 1997, NERC indicates that coal’s share of electricity

production will decrease, while nuclear, oil, and hydro use

will remain essentially the same.

Capacity

From 1988 to 1997, installed capacity (summer peak)

in this region is expected to increase by about 6,730 MW.

Included in this total are about 2,860 MW of nonutility

generation and other small unit additions. Also during this

same period, 830 MW of existing generation will be

retired or derated.

Summer peak demand is expected to grow annually by

1.3 percent, while winter peak demand increases by 2.0

percent annually. MAAC has traditionally been summer

peaking, but will convert to winter peaking after the turn

of the century if the present trend continues.

Transmission

The MAAC transmission network consists of about

6,500 circuit miles. From 1988 to 1997, an additional 110

miles of 500 kV lines and 400 miles of 230 kV lines are

planned for the region. According to NERC’s 1988

Reliability Assessment, transmission capability is a

concern in MAAC. The increasing use of transmission

lines has resulted in heavy loadings on critical lines

affecting interregional transfer capability.

NERC reliability reviews indicate that the primary

transmission constraint in the area is the major west-toeast transmission path. During 1987, the PJM system was

loaded to the limit of its west-to-east transfer capability

%.8 percent of the time.64

A 1984-85 study by ECAR/MAAC for DOE cited loop

flow from the New York Power Pool and New England

Power Pool and weaknesses in the MAAC system and

eastern ECAR as limiting the potential for the west-toeast transfer of coal-fired power to back out oil-fired

generation in the East. However, the study asserted that

the existing transmission system already provided about

90 percent of the economic benefits that could be realized

if the existing transfer capacity were doubled.65

An increase in nuclear capacity in recent years and the

declining differential in oil/gas and coal prices have

reduced the overall transfer of economy energy from

regions west of MAAC, particularly ECAR. But, internal

transfers of energy along the west-to-east transmission

path have remained high. This is especially true during

daily peak load periods. Because transmission flow

patterns in this region are very dependent on oil price

fluctuations, future changes in flow patterns will be

difficult to predict. Relatively high oil prices would tend

to increase the need for west-to-east transfers.66

Bulk Power Transactions

MAAC utilities report a relatively low volume of

transactions, according to DOE. There may be several

reasons for this low volume:

1. MAAC’s transmission capacity may limit transactions even when generating capacity is available;

63’’ Rc]iabiliIy council Wrvey Responses, ” supra nOle 2, p. 6.

cMOTA con~~lm rcpo~, “Case Studies on Increasing Transmission ACCCSS. ” Casazza, Schultz& Associates, Mar. 18, 1988, Appendix A, p. A-1,

65*IfjC~.M~C lnleflcglon~ power ‘Tr~~f~r,” as re~flcd in OTA c~n~~t~ re~rt, Ohio Public Utilities Commission, supra note 2, p, 302.

wTA contractor report, Casazza, Schultz & Associates, supra note 64, p. A-1.
Chapter 6--Regional Characteristics of the Electric Power Industry ● 187

2.

3.

the joint ownership of several large coal and nuclear

power plants can complicate the reporting of a

utility’s share of a transaction; and

the existence of a tight power pool with central

dispatch in the region may reduce the need for many

intraregional bulk power sales among members.67

The goal of central dispatch in MAAC is to reduce

costs by using the most economically efficient available

generation to meet load. Coal plants are used to back out

expensive oil generation. These transactions are conducted both within PJM Interconnection and with other

regions, especially ECAR.68 The NGA survey indicates

that MAAC contracted to buy about 3,700 MW of power

and to sell 1,300 MW.

Coordination

MAAC has one of the most highly integrated power

pools in the country. PJM has strong internal interconnections, especially a strong west-to-east transmission system, which transfers power from minemouth plants in

western Pennsylvania to load centers in the East, and

interregional connections with ECAR, NPCC, and SERC.69

PJM operates under a formal agreement that provides

for the coordination of planning and operation, reserve

sharing, and rates. Coordination in MAAC is handled well

and may be better than any other region in the country,

according to FERC.70

Reliability

A number of factors may affect MAAC’s future

reliability. These include a higher than projected load

growth, inadequate performance of load management

programs, delays in generation additions, limited transmission import capability, and decreased availability of

existing generators.

The most critical of these factors, according to NERC,

is a higher than projected load growth. Peak load growth

is forecast at 1.3 percent annually for the 1988-1997

period.

Capacity margins are forecast to range from about 19

percent in 1988 to 20.3 percent in 1997. MAAC expects

these margins to provide sufficient generating capacity

over the next decade, However, if load growth increases

beyond projections, margins may be inadequate by the

mid 1990s, even if all planned capacity is installed on

schedule.

Another potential adverse impact on reliability involves increases in loading on MAAC’S transmission

system. Heavy power flows can also increase loading on

other utilities’ systems not party to the transactions, as

well as decrease reliability and limit economic benefits

from internal energy transfers. NYPP’s importation of

hydropower from Canada has affected MAAC’S transmission system. To counteract this, the New York Power Pool

(NPCC) and PJM have agreed on what constitutes normal

and excessive use of each others’ transmission system.

The agreement includes an arrangement to purchase and

install phase shifters in 1988. Phase shifters change the

way power flow divides along different paths—

decreasing flows that are too high and increasing those

that can safely be increased. (See box 6-A on OTA’s

transmission case study-” Importing Power From Canada to New England.”)

Still another potential source of adverse impact is

disturbances caused by sudden loss of generation in

regions outside MAAC. A loss of generating sources to

the north and east of the MAAC region will cause a

significant increase in power flows from the west to the

east—ECAR to MAAC. This west-to-east power flow

could adversely affect the reliability of the MAAC

system. According to NERC, MAAC and neighboring

regions participate in coordinated planning and operation

to ensure that adequate reliability is maintained.

Because of its reliance on coal-fired power plants,

MAAC maybe affected if stringent new pollution control

requirements are adopted as part of acid rain legislation.

Compliance could require that some older plant.. be

retired and that output be reduced at other plants, If plant

availability is reduced, regional reliability levels could be

affected. The potential for power purchases by MAAC

utilities from coal plants in ECAR could also be limited

by constraints on capacity availability in that region.

Finally, in the late 1990s MAAC will increasingly

depend on nonutility generation additions to offset

capacity shortfalls. NERC has estimated that over the next

10 years about 2,860 MW of cogenerated power will be

installed, bringing the total to 3,126 MW by 1997.

6?DOE, supfa note 58, p. 43.

balbid.

@FERC, supra nOtC 57, p. 72.

701bid, p. 78.
188 ● Electric Power Wheeling and Dealing: Technological Considerations for Increasing Competition

Box 6-A—Transmission Case Study: Importing Power From Canada]

To meet rapidly growing load as well as displace expensive oil-fired generation, New England utilities are

pursuing a variety of new supply options. One seemingly attractive option is to import power from neighboring

Hydro-Quebec, a Canadian utility. Unexpected low load growth combined with excellent hydroelectric facilities

give Hydro-Quebec a large surplus of low-cost power. However, the transmission systems of Quebec and New

England are not synchronized and can only be linked by high-voltage direct current (HVDC) ties. At present, the

Hydro-Quebec system is connected to the Eastern Interconnection through five HVDC ties with a capacity of 2,590

MW. A power purchase agreement called the Phase I Project was developed to make full use of the existing facilities.

Phase I Project

The Phase I Project consists of a formal agreement for the sale and transmission by Hydro-Quebec to NEPOOL

of 33 million MWh of surplus hydroelectric power over an 1 l-year period, beginning in 1986. This energy purchase

agreement does not guarantee that NEPOOL will obtain any specified amount of power at the time of its critical

needs. However, NEPOOL does treat this agreement as reliable enough to justify not building 600 MW of capacity.2

At present, imports are constrained by 1) limited capacity of existing AC-DC converters at two locations-Des

Cantons and Comerford; 2) limitations in the AC systems in New England; and 3) lack of agreement to transfer more

power. An expansion of transmission facilities, called the Phase 11 Project, has been proposed to eliminate these

bottlenecks.

Phase 11 Project

The Phase 11 proposal calls for a total additional firm energy purchase of 70 million MWh over a 10-year period,

beginning in 1990, and for the building of necessary transmission facilities for its delivery. In general, NEPOOL

will be entitled to schedule deliveries in any hour up to the 2,000 MW capacity of the tie. There are limitations on

the rate of change of deliveries from one hour to the next, and Hydro-Quebec may interrupt deliveries during limited

periods of time. NEPOOL considers the Phase 11 agreement a reliable source of 900 MW. Thus, the combined Phase

I and II will replace 1,500 MW of additional installed capacity in New England.3

Transmission limitations will be resolved by adding both HVDC and AC components. In Canada, the HVDC

components consist of a new 700-mile HVDC line and an AC-DC convertor rated at 2,000 MW. In the United States,

the Comerford-Sandy Pond line will be extended by 133 miles. The NEPOOL AC system also has to be expanded

to absorb the additional Phase II power and distribute it to various load centers in New England. The AC expansion

consists of constructing two new 345 kV AC transmission lines, totaling 51.8 miles, along existing transmission

rights-of-way. In addition, substantial substation reinforcements are required.

While these new facilities would allow increased transfers without overloading the New England and

Hydro-Quebec systems, the project could create increased costs and transmission constraints in neighboring

regions. These effects underline the importance of considering the impacts of one region’s changes on other regions.

Interregional Impacts

Increased imports as well as reliability concerns have an impact on the operation of other regional systems.

Because NEPOOL, NYPP, PJM, ECAR, and other systems that make up the Eastern Interconnection are all

interconnected and operate synchronously, serious disturbances could be propagated from one of the systems to its

neighbors and even to more distant systems, This is particularly important given the large size of the Canadian

transfers. The loss of the Phase 11 transmission system would result in a disturbance much worse than the loss of

the largest generator in the Northeast.

When the power supply in New England is suddenly reduced by 2,000 MW, the maximum that can be lost due

to any contingency, this loss is immediately replaced by power generated in New England and in all the areas

connected with New England, from the Rocky Mountains and the Gulf Coast to Nova Scotia. Most of this power

is generated in areas to the west of New York and PJM, and passes through these on the way to New England.

l~ls rna[eria] is tiwn from an OTA contractor reporr, Casazza, Schultz & Asadate% ~c., “Case Studies of Transmission 130tdcnecks, ” Nov. 30, 1968.

2’$NCW Eng]an@ydro (&c&c 405 kV Transmissi(m Line Interconnechon---phase 11,” Fmsl Envi ronmemal Impact Statement, Econorrw Regulatory

Administration, Office of Fuel programs, DOE, Augus[ 1987.

3New figl~d 14ydro-Transrnission Ekxtric CO., ‘‘Amendment to Supplement 2C to Long-Range Forecast 2 for the Ten-Year Pertod 1%4- 1993, ” submitted

to k! MttssachuseUs Energy Facilities Siting Council, November 1984, vol. 1, p. 4.
Chapter 6--Regional Characteristics of the Electric Power lndustry ● l/19

These large power flows are added to the predominantly eastward economic power flows in the PJM and NYPP areas

from ECAR and other midwestern areas. The very large combination of the eastward power flows through PJM and

NYPP can cause thermal overloads, inadequate voltages, and possible instability on heavily loaded circuits.

The MEN Study Committee, a group representing PJM, ECAR, and NPCC, found that Phase 11 imports of less

than 1,500 MW do not require PJM or NYPP to restrict their power transfers more severely than they must for

contingencies in their own system. Larger imports, up to 2,000 MW, would affect PJM restrictions but not those

of NYPP, according to the MEN Study. PJM would have to restrict its imports from ECAR more severely—to 3,250

MW or less—than if it were responding to a contingency in its own system, or risk severe voltage problems if

NEPOOL lost its Phase 11 imports. Therefore, Phase II imports may not be increased to 2,000 MW unless PJM is

importing 3,250 MW or less from ECAR.

An alternative to restricting imports would be to install additional transmission facilities on either the PJM or

NYPP systems. Technical details and costs of such changes have not been determined, and the allocation of any

costs would have to be negotiated among the parties involved.

Economic (consequences

Some consideration has been given to what transmission reinforcements would be necessary to remove

existing limitations on the ECAR-to-PJM and NYPP transfers. The exact nature of these reinforcements, their cost,

and the amount by which these limitations would be relieved are not available because studies have been, for the

most part, informal and preliminary. The informal general consensus among system planners in the region seems

to be that the cost of increasing transfer capabilities by substantial amounts is likely to exceed the economic gain

produced by these increases, at the present cost differentials.

The Phase II power imports agreement is estimated to produce capacity and energy cost benefits with a present

worth of $1,849 million at an estimated cost of $948 million. These benefits will be reduced somewhat by the need

to limit the total imports to less than full capacity of the HVDC ties, whenever increasing imports would threaten

the reliability of systems in NeW York or Mid-Atlantic areas.

Mid-American Interconnected Capacity

Network (MAIN) NERC anticipates installed capacity to decline slightly

Voting membership is over the next 10 years. The recent addition of 4,310 MW

open to al I but one of the

MICHIGAN should be adequate to maintain reliability through 1997.

original signers of the MAIN No major additional units are planned during the 1988-

MAIN agreement and to 1997 period.

any other power supplier that has a 115 kV Annual summer and winter peak demand are projected

or higher interconnec- WISCONSIN to increase 1.6 and 1.9 percent respectively during this

tion with a regular mem - period.

ber, whose operations

have a significant im- Transmission pact upon reliability, and

who undertakes the ob- NERC indicates that the region’s transmission system

ligations of the MAIN is adequate for reliable operation of both internal and

Agree ment.71

interregional transfers. Interconnections to the east and

southeast provide substantial capability for interregional

Fuel Use transfers from MAIN to other regions. Several new lines

MAIN relies heavily

are scheduled for service within the next few years.

on coal and nuclear power To assure adequacy, MAIN conducts studies on a

to generate electricity. regular basis. Also, MAIN participates in two interBy 1997, NERC predicts coal’s share will increase regional reliability coordination agreements. One inslightly and nuclear’s share will decline. eludes MAIN, ECAR, and the Tennessee Valley Authorq 1‘ Reliability CouncI! Survey Responses, ” supra note Z p. 7
190 ● Electric Power Wheeling and Dealing: Technological Considerations for Increasing Competition

ity (TVA) subregion of SERC. The other includes MAIN,

MAPP, and SPP.

Bulk Power Transactions

According to DOE, MAIN has a low volume of

reported transactions. One reason may be that the largest

utility in the region-Commonwealth Edison—uses most

of its coal and nuclear capacity in its own heavily loaded

service territory. Also, the lack of established transmission access agreements may limit large-scale purchases

and sales.72

Those utilities that have abundant coal capacity sell to

or interchange power with those that are dependent on oil

and gas or need additional capacity to meet load.73 The

NGA survey respondents contracted to buy only 213 MW

and to sell 585 MW.

Coordination

Individual bilateral agreements appear to form the core

of coordination within this region. For example, coordination between MAIN and MAPP is established through a

bilateral agreement. Interregional coordination with several other contiguous regions is pursued through bilateral

agreements. FERC has indicated that expansion of a

power pool or coordinating group within the region,

rather than dependence on individual bilateral agreements, could improve coordination which in turn could

improve bulk power supply economy .74

Reliability

A couple of factors may affect the region’s reliability

in the future. They are acid rain regulations and a higher

than projected peak demand. Because coal is the predominant boiler fuel in the region, new regulations to further

reduce sulfur dioxide and nitrogen oxides emissions may

affect generation. Older units may have to be retired while

others would be retrofitted with emissions control equip

ment. The cost and lead times to retrofit and/or replace

capacity could prove significant and may affect reliability

by cutting plant availability.

NERC projects a capacity margin of 15.2 percent for

1997. if loads grow faster than anticipated, additional

capacity will be required by the mid 1990s. According to

NERC, MAIN utilities may encounter difficulties in

adding new generation and capacity in a timely manner.

Mid-Continent Area Power Pool

(MAPPJJ.S.)

MAPP operates as a

formal power pool. Its

voting members are electric utilities that own/

lease and operate one or

more generating units to

meet all or part of the MICHIGAN

NORTH

system load; are directly M ONTANA DAKOTA N

interconnected with one

or more participants in

order to meet obligations of the MAPP Agreement; operate or participate in a 24-hour dispatch

MAPP communication network; and maintain Accredited

Capability75 during each month.7G

SOUTH WlSCONSIN

DAKOTA

NEBRASKA lOWA

MAPP-U.S.

center with a terminal on the

Fuel Use

MAPP relies heavily on coal and nuclear power for

electricity generation. Coal use, which now accounts for

little more than two-thirds of electricity generated, is

expected to increase to 70.8 percent by 1997. Nuclear’s

share is expected to decline to 17.5 percent, and hydro’s

share will decline slightly.

Capacity

Between 1988 and 1997 installed capacity is projected

to increase by only 740 MW. This increase consists

primarily of a 400 MW coal-tired unit and the return of

retired units to service,

Summer peak demand is expected to grow by 1.5

percent annually and winter peak by 1.6 percent annually

for the forecast period. MAPP utilities are actively

pursuing various load management programs to reduce

growth in peak demands.

Transmission

MAAP has experienced increased internal and interregional use of its transmission systems for economy and

emergency energy transfers, For example, NERC reported that in 1986 transfer capacity between MAPP-U.S.

and MAPP-Canada was utilized at 71 percent of maximum capacity; interregional energy transfer capacity

between MAPP and WSCC was almost 87 percent.

72MM, supra nole 58, p. 43.

731bid.

74~Rc, supra note 57, p. 1~.

75N~~ ~ewating Capability p]us pur~h~~ p)w~r ~xcluding ~onomy Ctwfl, minus CotlllTlltrnCnlS,

Tb’’Rc]iability co~~il Survey Rqxmses,” supra nOte 2, p. 8.
Chapter 6-Regional Characteristics of the Electric Power industry • 191

Furthermore, interregional transfers from MAPP to MAIN

and SPP have been increasing annually since 1976 and are

expected to continue over the next decade. According to

NERC, improvements currently underway or planned

should help alleviate concerns. NERC expects the region’s transmission facilities

1997.

Bulk Power Transactions

to be adequate through

MAPP utilities take advantage of their significant

coal-fired capacity by selling to utilities in other regions.

Bulk power transactions within the region are based on

least-cost generation, But. the region’s lack of generation

diversity may limit the potential for large-scale purchases

and sales.77 The NGA survey indicated that MAPP

respondents contracted to sell 1,900 MW and to purchase

2,470 MW.

Coordination

MAPP consists of the Upper Mississippi Valley Power

Pool, the Iowa Power Pool, and the Nebraska Public

Power Systems. Pool agreement provisions cover capacity and transmission plans and requirements and daily and

seasonal operations. However, the pool agreement does

not oblige members to provide bulk power supplies to

other members over a long period of time. Individual

utilities would have to independently arrange for their

power needs.78

Reliability

Capacity margins for summer peak periods in MAPP

are projected to decrease from 27.6 percent in 1988 to

21.4 percent in 1997. Although capacity margins will

decrease during this period, NERC expects that they will

meet reliability criteria and should therefore be adequate.

Some of MAPP’s coal-fired generation could be

affected by additional pollution equipment requirements

to control acid rain precursors. The available power from

these units could be reduced, which in turn, would have

a negative impact on the region’s reliability. But, the

impacts in this region are expected to be much less than

in ECAR and .MAIN.

Northeast Power Coordinating Council (NPCC)

NPCC includes members in the United States

and canada. Member systems in New England

form the New England

Power Pool (NEPOOL),

and member systems in

New York form the New

York Power Pool (NYPP).

Memberships available

to electric systems which

have a substantial effect

on the service reliability

NEW YORK

NPCCU.S.

of the Northeast interconnection.79 The discussion in this

section refers to the U.S. portion of NPCC unless

otherwise noted.

Fuel Use

NPCC member utilities rely most heavily on nuclear

and oil, followed by coal and hydro to produce electricity.

NERC projections for 1997 show that nuclear’s share is

expected to increase; oil and coal use will decrease.

Capacity

NPCC installed capacity is projected to grow at an

annual rate of 1.2 percent from 1988 to 1997. During this

same period, annual summer and winter peak demand are

expected to grow at 1.9 percent and 1.3 percent respectively. NERC projects that about 6,000 NIW of new

capacity will be added by 1997. The only major utilityowned capacity addition scheduled for service in New

England over the next decade is the Seabrook I nuclear

plant. The Ocean States Power Project, an independent

power project which is owned jointly by several utilities

and a Canadian gas pipeline company, also is expected to

contribute 470 MW of capacity.

Transmission

NPCC transmission systems have experienced dramatic increases in power flows over the last 10 years. The

increases have been due to fuel price differentials, the

need to locate generating resources farther from urban

load centers, and the growing reliance of NPCC systems

on generating resources in Quebec. NERC expects heavy

flows to continue in the future. Construction of several

new transmission lines from HydroQuebec and upstate

New York to load centers in southeastern New York and

New England will provide additional sources of genera771)OE, supra note 58, p. ~.

7~17ERC, supra note 57, p. 110.

T~. ‘Re]labllity co~cil survey Rcyxmses,” SupUi nOIC ~, p. ~.
192 ● Electric Power Wheeling and Dealing: Technological Considerations for Increasing Competition

tion and improve reliability. These imports will require

the continued use of special protection and control

systems to maintain transmission reliability in NPCC and

adjacent regions.

Bulk Power Transactions

According to DOE, most of the bulk power transactions in this region are based on reducing costs at the

margin by taking advantage of load diversity and

operating differences. The biggest purchasers of electricity, according to DOE, are the utilities that have coal-fired

capacity. These utilities also tend to be the largest utilities

with the heaviest loads.80

Determining NPCC’s volume of bulk power transactions is difficult for a couple of reasons. One reason is the

different methods of reporting within NPCC. (NYPP

utilities report their pool transactions as purchases and

sales, while NEPOOL reports their transactions as interchanges.) Another reason is that joint ownership of power

plants in the region tends to complicate reporting of

purchases and sales.81

The NGA survey indicated that NPCC utility respondents engaged in a relatively low volume of bulk power

transactions, compared to other regions. Utility respondents contracted to sell about 1,091 MW of power and to

buy 2,356 MW. Like MAAC, the existence of the two

tight pools in NPCC may obviate the need for a lot of

intraregional transactions among members.

Coordination

NEPOOL and NYPP are two of the most integrated

power pools in the country. Both have strong interconnections that provide for substantial interpool and interregional transfer capability including imports from Canada. 82

Both pools operate under formal agreements that

provide for joint organization, planning, and operation.

Because NEPOOL’s membership is more diverse, its

agreement is more complex and comprehensive than

NYPP’s. 83 In addition to the pool agreements, the utilities

are tied together through dozens of bilateral agreements.

Reliability

According to NERC, supply adequacy will depend on

the installation of both utility and nonutility generation,

the success of demand management and life extension

programs, and large-scale power transfers. In NPCC,

supply adequacy is also very dependent on demand not

exceeding projected growth rates for the 1988-1997

period.

NERC indicates that projected capacity resources in

New York are adequate to meet forecast demand through

the next 10 years. This projection assumes that generation

additions, including the Shoreham nuclear unit, are

realized and demand management and life extension

programs are successful. For NEPOOL, NERC estimates

capacity should be adequate through 1992/1993. Beginning in 1993, NEPOOL’s resources are expected to fall

below NPCC’s reliability criteria. NERC’s current projection for this region differs from that reported in its 1987

reliability assessment, which expected capacity resources

to be adequate through 1996.

Oil-fired units represent about half of total New York

and New England generating capacity. This heavy

dependence on oil and the future availability of adequate

oil supplies are major reliability concerns to NPCC

utilities. The availability of the region’s nuclear capacity

is also important. Boston Edison’s Pilgrim nuclear unit

has been shut down by the Nuclear Regulatory Commission (NRC) because of safety considerations. The NRC

has given approval to restart the unit but the Commonwealth of Massachusetts is opposing that decision based

on its concerns over the feasibility of developing adequate

emergency evacuation procedures.

Southeastern Electric Reliability

Council (SERC)

Voting membership in

SERC is open to any

power supply entity operating or responsible for

operating facilities connected to the interconnected power system,

which is located in the

SERC membership area

and which provides bulk

power supply with a normally connected generating capacity of 25 MW

KENTUCKY

C:ROLINA

GINIA

A

MISSISSIPPI

or more. Non-voting membership is open to four representatives on a sub-regional

basis for each of two categories: 1) municipal or other

SCIDOE, supra no{c 58, p. 44.

El Ibid, p. 45.

BZnRC, supra note 57, p. 73.

gqlbid, p. 74.
publicly-owned systems: and 2) rural electric cooperatives. 84

Fuel Use

SERC members rely on coal and nuclear power, and to

a much lesser extent on hydropower, to produce electricity. In 1988, NERC expects coal to account for almost 60

percent of electric power production, and nuclear about

one-fourth. By 1997, NERC projects that coal’s share will

decrease slightly and nuclear will increase.

Capacity

The SERC region will experience the largest growth in

installed capacity. NERC expects that about 17,236 MW

of new capacity will be added between 1988 and 1997. In

addition, about 6,200 MW of nonutility generation are

projected for this period. Based on these projections, the

annual growth rate will be 1.8 percent through 1997. At

the same time, both winter and summer peak demand

growth are projected to increase by 2.4 percent annually.

Transmission

The existing SERC transmission system includes

about 27,000 miles of 230 kV+ powerlines. SERC is

interconnected with transmission systems in four other

regions: SPP, MAIN, ECAR, and MAAC. During the

1988 to 1997 period, over 600 miles of 500 kV and 1,700

miles of 230 kV lines are expected to be added. Included

in SERC’s plans are two major 500 kV interconnections

between SERC and SPP and one major 500 kV transmission interconnection between SERC and ECAR.

NERC expects that existing and planned facilities will

provide adequate energy transfer capability between

SERC and other regions, and among SERC subregions.

Certain portions of the system, however, are experiencing

and will continue to experience heavy use, Because of

this, several key tie lines between utilities, subregions,

and regions are closely monitored. These include the

TVA- MAIN Interface near Paducah, Kentucky; SouthernVACAR Interface near the Savannah River; TVA-SPP

Interface near Memphis, Tennessee; and the Southern

Co.-Florida Interface.

Bulk Power Transactions

SERC has abundant and diverse generating capacity.

The availability of coal-fired and hydro capacity, especially in the Southern Company service area, and the

Carolinas, affects the volume and type of bulk power

transaction within the region. Transactions are also

influenced by the amount of oil capacity in Florida and

Virginia. For example, Florida and Virginia utilities buy

coal-generated electricity from Southern utilities to back

out oil capacity. Most of these transactions are used to

obtain marginal co~t reductions by exploiting load

diversity. ss

Also, there are substantial transactions between SERC

and ECAR that involve the sale of coal-generated power

to utilities that depend on oil capacity .X6 According to the

NGA survey, SERC accounted for the largest volume of

bulk power tranwtions in both sales and purchases.

SERC has contracts to buy more than 12,750 NIW. Sales

contracts total over 7,480 MW.

Coordination

SERC is divided into four subregions: TVA, Southern,

VACAR, and Florida. Strong interconnections exist in a

north-south direction between TVA and Southern Companies and in an eust-west direction between Southern and

VACAR. Interconnections between TVA and VACAR

are limited.%7

Coordination among the four subregions is achieved

primarily through bilateral agreements. Southern Co.

affiliates are tied together in the holding company pool.

The Florida utilities participate in an energy broker

system, which provides some of the benefits of a formal

pool arrangement. VACAR and I“VA use bilateral

interchange agreements to coordinate bulk power transactions.nn

Reliability

NERC expects that generating capacity margins in this

region should be adequate during [he 1988-1997 period,

provided capacity additions and peak demand are as

projected. NERC also expects that SERC transmission

systems will provide adequate emergency transfer capacity between SERC and other regions and among subregions.

~~’ ‘Re] iabi]ity Council survey Responses, ” Wpra nOIC ~, p. 9.

xfDOE, Supra note 58, p. 45.

‘Ib]d.

~7FERC, supra nolc 57, p. 83.

g~lbid, p. 85.
194 . Electric Power Wheeling and Dealing: Technological Considerations for Increasing Competition

Southwest Power Pool (SPP)

Voting membership in

SPP is open to any system that: is interconnected at 115 kV or

above with any SPP member; owns and controls a

115kVorhighertransmission line in synchronous

operation and with an

installed total capability

of 100 MW or greater;

owns or controls not less

SPP

4

KANSAS

OKLAHOMA ARKANSAs

‘\

\ LOUISIANA

NEW MEXICO

than 300 MW of installed generating capacity with the

SPP area; makes a significant contribution to overall

reliability in SPP; generates on a 24-hour basis; and has

a 24-hour dispatch center or has contractual arrangements

with a load control area to fulfill that function. Nonvoting

membership is open to utilities which serve 25 MW of

load and control not less than 25 MW of operable

generation in synchronous operation of a transmission

interconnection with an SPP member.89

Fuel Use

SPP members rely heavily on coal and to a lesser extent

on gas and nuclear power to produce electricity. Over the

1988-1997 period, the fuel mix will remain fairly

constant.

Capacity

Between 1988 and 1997, NERC expects that installed

capacity will increase slightly by 2,538 MW, which

translates into an annual growth rate of 0.4 percent.

Summer peak demand is expected to grow 1.9 percent

annually, and winter peak demand to grow 2.2 percent

annually.

Transmission

The SPP region has an extensive transmission network

that includes three direct interconnections from SPP to

other regions. In the next decade, SPP plans to install

about 1,500 miles of transmission lines, 230 kV and

above. Also, two additional interregional circuits are

planned to include an interconnection with SERC (TVA)

and another dc interconnection with ERCOT

Interties to the east and northeast provide substantial

interregional transfer capability between SPP and SERC

and between SPP and MAIN. Interregional transfer

capability also exists between SPP and MAPP, but on a

smaller scale. Interconnections between SPP and ERCOT

are limited because the Texas system is not synchronized

with the Eastern system. Similarly, the lack of ties

between SPP and the Western United States precludes

significant direct emergency power transfer,w

According to NERC, SPP’s transmission system and

interconnections with other regions are adequate and no

lines present significant bottlenecks to economy or

emergency energy transfers for the 1988-1997 period.

Bulk Power Transfers

Each of SPP’S three distinct regional groups—Middle

South Group, the Missouri-Kansas Power Pool (MOKAN),

and the Oklahoma Group--relies on a different generating capacity mix. Because of these differences in generating capacity, each group engages in different types of bulk

power transactions. For example, Middle South engages

in substantial purchases and sales and to a lesser extent

interchange; MOKAN emphasizes interchange transactions; and the Oklahoma group has more sales than

interchanges. 91

Generally, the utilities that depend on natural gas

generation use bulk power transactions to reduce marginal costs, while utilities with coal-fired capacity are

either using the transfers to meet native loads or selling

coal-generated power to other utilities with oil and gas

capacity. 92

Coordination

Planning and operating coordination is accomplished

primarily through the three regional groups. Multiparty

pooling, coordination agreements, and bilateral agreements form the core of coordination within SPP.93

Middle South Utilities (MSU) is fully interconnected

and coordinated. It operates under a formal agreement to

which all operating companies and the service company

are signatories. MOKAN members individually dispatch

their own generating resources. While MOKAN does not

practice central dispatch, the systems have arrangements

for the economy energy exchanges. Many MOKAN

members participate in one or more joint agreements to

build transmission facilities in the area.94

89’ ‘Reljabili[y COWWII SUWCy Responses, ” supra note z, pp. ~- 10.

90~RC) supra note S7, p. iol.

91DOE, supra note 58, p. 47.

~zlbid.

g3~RC, supra note 5’7, p. 1 !~.

941bid, p. 124.
Chapter 6--Regional Characteristics of the Electric Power Industry ● 195

Reliability

SPP anticipates adequate generating capacity margins

during the forecast period. The primary reliability concern, according to NERC, is transmission access.

Western Systems Coordinating

Council (WSCC)

Membership in WSCC

is open to any electric

utility or group of utilities in the region regardless of the type of facilities or system size. Voting membership is available to entities with generation in excess of 100

MW or transmission above

230 kV. The Council

consists of one representative per member system. 95

Fuel Use

WSCC members are

divided into four sepaWASHINGTON

rate subregions: the ‘Northwest Power Pool, the Rocky

Mountain Power Area, the Arizona-New Mexico Power

Area, and the California-Southern Nevada Power Area.

Fuel use in each of these subregions is very different, For

example, the utilities in the Northwest Power Pool, which

is winter peaking, rely primarily on hydropower; the

Rocky Mountain Power Area, which is either winter or

summer peaking, relies on coal and hydro; the ArizonaNew Mexico Power Area, which is summer peaking,

relies on coal- and gas/oil- fired generation; and the

California-Southem Nevada Power Area, which is summer peaking, is heavily dependent on gas- and oil-fired

generation.

Capacity

Net generation additions of 16,771 MW are projected

by 1997. The projected additions are considerably less

that the net additions placed in service during the past 10

years, however. This reduction is in response to recent

lower load growth projections and to the availability and

abundance of capacity resources in WSCC.

The annual growth for 1988-1997 is 1.0 percent.

During the same period, summer peak demand is expected

to grow 1.9 percent annually, and winter peak, 1.7 percent

annually.

Transmission

WSCC’s overall bulk power transmission network

links the principal population centers with major northsouth lines along the Pacific Coast and through the

intermountain plateau. East-West lines tie the system

together. The result is an irregular large loop configuration, often called the “doughnut,” rather than an interlocking system that is found in the East. Few transmission

lines cross the sparsely populated ‘hole” of the doughnut

in Nevada.

According to NERC, WSCC transmission systems are

adequate to accommodate anticipated firm and most

economy energy transfer schedules during the 1988-1997

period. Of continuing concern is the effect of heavy

economy transfers on bulk electric power system reliability. Because of the region’s load diversity and capacity

resource mix, plus surpluses of base-load capacity and

large fuel price differentials, economy energy transfers

between areas are likely to continue.

WSCC members are currently making improvements

in the system in order to maintain an acceptable level of

reliability. These include upgrading and increasing transfer capability, and completion of additional lines. During

1987, a portion of the new AC Pacific Intertie was placed

in service to improve reliability. And, several utilities are

planning to install phase shifters on lines connecting

Utah/Colorado and Arizona/New Mexico. The phase

shifters are scheduled for operation during 1989-1991 and

are expected to mitigate the Regions loop-flow problems.

Bulk Power Transactions

There is a heavy volume of bulk power transfers in the

WSCC region. Utilities with coal-tired capacity in Utah,

Wyoming, Arizona, and New Mexico sell power to

California to back out oil and gas. Coal-fired electric

power is also sold to the Northwest to supplement

hydropower during dry spells and during winter peak

periods. The Pacific Northwest sells hydropower to

California utilities and other Southwestern States when

water conditions permit and during summer peak periods. 96

Coordination

Coordination and pooling have evolved on a subregional basis among utilities with similar needs and

problems. No pool formally plans bulk power facilities as

95’’Re]l~bl]ity ~~~ci] Suivcy Responses, ” supra nf31f2 ~, p. 10.

96D0f2, SUpra note 58. P. 47
196 . Electric Power Wheeling and Dealing: Technological Considerations for Increasing Competition

a single integrated system to serve the combined load

growth of its members.97

The Arizona-New Mexico Power Area participates in

a number of coordination arrangements, which in many

cases relate to specific projects and conditions. The Rocky

Mountain Power Area and the California-Southern Nevada Power Area rely on bilateral coordination arrangements. And, the Northwest Power Area utilities adhere to

the Pacific Northwest Coordination Agreement, which

provides for the coordination of resources and establishes

rights, obligations, and procedures for all signatories.98

According to FERC, power pooling could be especially

effective in the Rocky Mountain and Arizona-New

Mexico power areas. In the Northwest Power Area,

substantial bulk power supply economies are being

realized from the coordinated planning efforts of the

area’s utilities brought about by passage of the Northwest

Power Planning Act of 1980.99

Reliability

NERC projects that generating capacity margins will

range from 33 percent to 26 percent over the next 10 years

and will adequately meet demand.

Alaska

Fuel Use

Fuel use varies by

region within Alaska. For

example, the Rail belt region (Anchorage-Fairbanks) relies primarily

on indigenous natural gas

to generate electricity;

southeastern Alaska is

served primarily by Federal and State hydropower projects; and the widely dispersed villages in the

rest of the State obtain electricity from diesel-fueled

generators, ranging from 50 KW to 7 MW.lOO

Capacity

Alaska’s 1986 installed generating capacity was 2,433

MW, an increase of 5.6 percent over 1985 figures. About

two-thirds of the installed capacity was in the utility

sector; 25 percent in the industrial sector; and about 6

percent in the military sector. According to the Alaska

Power Authority, the military’s share may continue to

decrease if military facilities continue to contract out

power production responsibilities to the private sector. 101

Because of the State’s economic recession, current

projections are negative for the short term and around 2

to 3 percent over the next 10 to 15 years. The Railbelt

region has the largest concentrated segment of load in the

State. In the southeast, three major communities use

substantial amounts of power: Juneau (55 MW), Sitka (22

MW), and Kethikan (20 .MW). The largest rural towns

have loads in the 4- to 5-MW range. Load growth

forecasts are low for most areas of the State.102

Transmission

Alaska has few interconnected electric utilities. The

Railbelt region has the strongest interconnected system in

the State while all southeast communities are isolated and

lack major interties.

Alaska’s transmission network consists of 1,681.5

circuit miles. Almost 80 percent of the network is in the

Fairbanks and Anchorage-Cook Inlet areas. 103

Reliability

Reliability continues to be a major concern in Alaska.

In the Railbelt, for example, reserve margins are required

to be 30 percent. In the rural areas, communities are

essentially on their own for electricity, and utilities

typically provide high reserve generation levels. Reserve

margins of 100 percent are prudent. According to the

Alaska Public Utilities Commission, reliability should

improve for many isolated systems over the next 20 to 50

years as many communities become interconnected. ’w

97~RC, supra note 5’7, p. 137.

‘Wbid.

9’)Ibid,

looA]aska public utilities Commission letter to OTA, dated Aug. 30, 1988.

]olAlmka power Au~~~, Al~s~ Electric Power .~lati.~ti~s ]960-]986, November 1987, p. 1.

lmAl~ka public Utilities Commission letter, Supra note ioo.

l~Al~ pOWT Authority, supra note 101, p. 61.

l@A]~ka Publjc Utilities ~ommission ]ettcr, Supra nOte 100.
Chapter 6-Regional Characteristics of the Electric Power Industry ● 197

The Hawaiian Electric Company (HECO)

provides electricity to

Oahu and to three

other Hawaiian Islands

through its subsidiaries Hawaii Electric

Light Company

(HELCO) and Maui

Electric Company

(MECO). The systems

cover about 95 percent of the Islands.

Fuel Use

Hawaii

Hawaii is heavily dependent on oil and will continue its

reliance well into the future. In 1986, oil-fired capacity

provided about 93 percent of total capacity. The remainder is supplemented by purchased cogenerated electricity

from sugar processing facilities and from wind power

companies. In Maui, cogeneration from sugar processing

facilities contributes about 19 percent of the island’s

electricity requirements.

105 However, power contributions from sugar processors or from other renewable

resources are not expected to increase substantially.

Capacity

Hawaii’s installed capacity in 1986 was 1,535 MW.

HECO reports peak demand is 1,205 MW. 106i System

peaks occur in the evening. However, HECO projects that

by 1990 peaking

Transmission

will occur during the day.

The electric systems on each island are not connected

with each other. The lack of transmission capability is the

biggest impediment to development of the Islands’

indigenous resources. For example, the geothermal reserves on the Big Island are considered extensive enough

to fulfill most of the State’s power needs, but are located

far from the load center in Oahu.

Hawaii has 1,465 miles of transmission lines. Hawaii

Light Company, an affiliate of HECO, has begun

construction of two lines totalling 50 miles. The cost was

estimated to be about $11 million. 107

Reliability

HECO reports a reserve margin of 22 percent for 1987

and projects an increase to 35 percent by 1990.
Chapter 7

Siting, Environmental, and

Health Issues Associated With

Increased Competition and

Expanded Transmission Access
CONTENTS

Page

INTRODUCTION . . . . . . . . . . . . . . . . . . . . . . . . . 201

Siting . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 201

Environmental Impacts . . . . . . . . . . . . . . . . . . 201

Health Effects . . . . . . . . . . . . . . . . . . . . . . . . . . . 201

SITING ELECTRIC TRANSMISSION

LINES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 201

The Siting Process . . . . . . . . . . . . . . . . . . . . . . . 202

impediments to Transmission Line Siting.. 208

Interest Group Perspectives . . . . . . . . . . . . . . . 211

Options To Improve Transmission

Line Siting . . . . . . . . . . . . . . . . . . . . . . . . . . . 213

Conclusions . . . . .. .. .. .. .. .. ... ... .....$. 215

ENVIRONMENTAL EFFECTS OF INCREASED

COMPETITION IN THE ELECTRIC

-POWER INDUSTRY . . . . . . . . . . . . . . . . . . . . 216

Generation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 216

Transmission and Distribution . . . . . . . . . . . . 217

Scenarios of Change in the Electric Utility

Industry . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 218

Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 227

HEALTH EFFECTS OF POWER

FREQUENCY FIELDS . . . . . . . . . . . . . . . . . . 227

Sources and Nature of Electric and Magnetic

Fields . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 228

Exposure Parameters. . . . . . . . . . . . . . . . . . . . . 230

Comparing Human Exposures From Different

Sources . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 232

Current Scientific Evidence on Biological

Effects of Power Frequency Fields . . . . . . 232

Major Programs and Funding Levels for

Health Effects Research . . . . . . . . . . . . . . . 238

ELF Exposure and Regulatory Activity . . . . 241

Box

Box Page

7-A. Bidding in Massachusetts: A Glimpse of

the Future? . . . . . . . . . . . . . . . . . . . . . . . . . . . 221

Figures

Figure Page

7-1.

7-2.

7-3.

7-4.

7-5.

Dimensions of Typica1 345-kV

Transmission Lines . . . . . . . . . . . . . . . . . . . . 219

Electric Field Intensity at Ground Level

v. Horizontal Distance From Three

Common Sources of Power Frequency

Electric Fields . . . . . . . . . . . . . . . . . . . . . . . . . 229

Magnetic Field Intensity at Ground Level

v. Horizontal Distance From Three

Common Sources of Power Frequency

Magnetic Fields . . . . . . . . . . . . . . . . . . . . . . . 229

Comparison of Ranges of Electric and

Magnetic Fields From Common Power

Frequency Sources . . . . . . . . . . . . . . . . . . . . . 231

History offending for ELF Bioeffects

Studies in the United States From 1986

to the Present . . . . . . . . . . . . . . . . . . . . . . . . . 239

Tables

Table Page

7-1. State Certification and Siting Requirements

for High-Voltage Transmission Lines . . . 204

7-2. Most important Factors Affecting Timely

Consideration . . . . . . . . . . . . . . . . . . . . . . . . . 210

7-3. Boston Edison Company-Winning Bidders

RFPNo. 1 . . . . . . . . . . . . . . . . . . . . . . . . . . . . 223

7-4. A Summary of Results of Cellular Level

Experiments: Effects and Possible

Significance . . . . . . . . . . . . . . . . . . . . . . . . . . . 234

7-5. Methodology and Results of Epidemiologic

Studies of Childhood Cancer and

Electromagnetic Field Exposure . . . . . . . . 237

7-6. State Regulations That Limit Field Strengths

on Transmission Line Rights-of-Way . . . . 242
Chapter 7

Siting, Environmental, and Health Issues Associated With

Increased Competition and Expanded Transmission Access

INTRODUCTION

Increasing competition and opening up the transmission grids raise many public policy issues

beyond the technical and institutional feasibility of

accommodating these changes. This chapter provides an overview of three of the most significant

and potentially contentious of these issues: transmission line siting, environmental impacts, and potential public health effects of power frequency electric

and magnetic fields. Because of the clear interconnections with proposed industry changes, Congress

asked OTA to include consideration of these issues

in its assessment.

Siting

The process of gaining approval for transmission

line construction has changed and become more

formalized as opportunities have been provided for

public involvement and greater scrutiny of potential

environmental and social impacts of proposed projects. As the Nation is becoming more and more

urbanized, competition for available land to route

transmission lines has become more intense and

right-of-way costs have increased as higher value

lands are taken. It is clear, however, that in order to

provide an adequate and reliable power supply new

and expanded transmission systems will eventually

have to be built whether a competitive future path is

taken or not. The challenge for industry and regulators is to create a system that plans for and

encourages needed expansion and at the same time

accommodates other competing interests while resolving or minimizing conflicts. The siting section

of this chapter describes generally how transmission

line siting decisions are made by State, local, and

Federal agencies and discusses several proposals for

improving the siting process.

Environmental Impacts

Decisions over the future structure and composition of the electric power industry in the United

States have both direct and indirect environmental

impacts. These choices will shape fuel mix, dictate

location of impacts, and advance or frustrate the

achievement of other environmental and social

goals. Transmission line construction, operations,

and maintenance also raise direct and indirect

impacts on the environment. This section discusses

the potential environmental concerns presented in

the implementation of OTA’s alternative institutional scenarios.

Health Effects

One of the most prominent concerns raised by

people living near existing or proposed transmission

lines is the potential for adverse health effects from

exposure to electric and magnetic fields. Scientists

are still investigating whether and to what extent

these effects are harmful and long lasting and their

possible public health implications.

The health section describes the current state of

knowledge on health effects of power frequency

fields based on available research. It also discusses

some of the policy responses to the implications of

these research results,

SITING ELECTRIC

TRANSMISSION LINES

Long-distance transmission of electricity has

increased significantly in recent years. Transmission

capacity in some regions is already strained by high

usage. At the same time, the pace of construction of

new power lines has fallen. Some analysts point to

the many licensing and certification processes required to site new transmission lines as one possible

reason for this decrease in new construction.

Gaining approval of specific transmission line

projects from State regulatory agencies can be a

complicated process, often requiring the filing and

review of multiple applications. The involvement of

many local governmental agencies, the courts, and

Federal and tribal governments further complicates

the siting process and can lead to jurisdictional

conflicts. The participation of a variety of competing

interest groups in the siting process for new transmission lines frequently adds to the time required to

complete siting and to the complexity of the process.
202 ● Electric Power Wheeling and Dealing: Technological Considerations for Increasing Competition

Long-range planning efforts by utilities and

State agencies tend to focus on power generation

issues, leaving long-distance transmission issues

understudied. Consequently, decisionmakers are

often hampered by inadequate information about

transmission needs as they review project applications. Constraints imposed by State utility laws and

regulations could also hamper decisionmakers as

they review large interstate transmission line proposals. Moreover, the lack of multi-State siting

procedures and coordination among Federal and

State agencies could further encumber the siting of

interstate power lines. However, even without such

procedures in place, voluntary cooperation among

utilities and State and Federal agencies has resulted

in the siting, approval, and construction of multiState lines. The National Governor’s Association

Electricity Transmission Task Force survey, conducted in the fall of 1986 (hereafter referred to as the

NGA survey), indicated that 73 projects had been

approved and 84 requests were pending approval

within the previous year. In addition, the survey

noted that the majority of projects approved between

1982 and 1987 had been completed. ’

Proposals to improve the siting process for new

transmission lines include developing more information about transmission needs in the long-range

planning and application review processes, streamlining and clarifying State regulatory agency review

processes, broadening multi-State siting efforts, and

increasing public participation. Standardizing and

expanding reporting requirements, increasing interagency communication, developing clear and consistent evaluation criteria, and creating new regulatory entities empowered to make final siting decisions could also help achieve these objectives. A

number of States have already adopted some of these

measures.

This section provides an overview of the transmission line siting process, beginning with the

long-range energy planning process through which

States and utilities strive to identify future electricity

supply requirements. It also explores the impediments to power line construction and discusses the

perspectives of interest groups towards transmission

facilities. Finally, several proposed options to improve the transmission line siting process are examined. 2

None of OTA’s scenarios, described in chapter 3,

affect the process for approving the routing and

construction of transmission systems. This process

is generally separate from the regulatory decisions

concerning certification of need and recovery of

transmission system investments through ratemaking.

The Siting Process

Once a need for new power supplies has been

identified, specific transmission line projects are

designed by utilities, and approval for those projects

is sought from State agencies charged with certification and licensing. Project approvals from a variety

of local governmental entities are usually required.

In addition to these State and local siting requirements, special siting approval for power lines

crossing Federal and tribal lands and for multi-State

transmission line projects is required.

Capacity Planning

Recognition of the need for new transmission

lines usually surfaces through long-range energy

planning processes that attempt to predict electricity

demand patterns in future years and decades. At least

31 States require electric utilities to file long-range

supply and demand plans for their service area.3

These utility plans discuss, among other issues,

anticipated electricity supply and demand, the need

for new power generation or transmission facilities,

and anticipated nonutility generation capacity. Longrange energy plans generally reflect a 20-year

planning horizon, although shorter range planning

frameworks of 10 to 15 years are not uncommon.

Moreover, utilities are required to submit planning

1‘‘Tr~s~l.~l~~ Lln~ Ceflificallon and Sl[lng pr~.~durcs and Energy planning pr~ccsscs: Summary of slim! Government Responses 10 a SUIWCy

By tic National Govcmors’ Association Task Force on Elcc[nciiy Transmission, ” prepared by staff members of the Public Ulllilics Commission of

the S[ate of Ohio and of [he West Virginia Public Service Comrnlssion, OTA contracmr rcpon, July 1988, p 4, hcrcaf[er ‘NGA survey.”

zMuch of [he infoma[ion in lhls s~[ion is drawn from an OTA ~~n~a~~~r rc~rt, JWT3CS S. (hmon, ‘‘The Siting of’EHV Electric Transmission Lines,”

May 1988.

3Nallona] Gov~mor’s Association, commi[[~ on Encr,gy and Errvironmcnl T& Force on E]ecwicily Transmission, Moving Power” F/exd)illo for

rhe Fufure (Washington, LX: 19 W), $ ‘Foreword. ”
Chapter 7---Issues Associated With Increased Competition and Expanded Transmission Access ● 203

analyses to support their applications for approval of

specific power generation or transmission projects.

In many cases, utility plans are supplemented by

energy planning efforts by State government agencies. A recent survey of State electricity regulatory

programs by the NGA identified 18 States where

public utility commissions prepared independent

electricity plans and 12 States where planning was

performed by a State energy office or department.4

However, only a few States, such as California, New

Jersey, and New York, require agencies to solicit

public comment during the energy planning process

and to publish State energy plans at periodic

intervals.

According to the National Association of Regulatory Utility Commissioners (NARUC) and NGA,

several factors diminish the effectiveness of energy

planning processes. First, many State energy regulatory agencies do not have adequate staff either to

scrutinize utility long-range plans or to prepare

detailed energy forecasts on their own. Thus, planning reports often receive close review by a State

agency only when a specific construction project is

proposed, which may be years after the need for the

project was first identified.

Second, utilities jointly involved in the development of a transmission line submit separate longrange plans, which discuss only those portions of

energy projects directly affecting that utility. Most

State-mandated, long-range planning programs do

not require utilities to coordinate their projects’

planning reports. The task of consolidating the

individual plans into a comprehensive picture of a

State’s electric power system often falls to the

limited resources of the State agency to which the

plans are submitted.

Third, utilities’ long-range plans have traditionally focused on generation needs within a particular

service area. Issues related to interutility sales and

transmission are not necessarily addressed in detail

in long-range plans. Thus, NGA’s report noted

“determinations of transmission requirements are

frequently ancillary or iterative to, rather than

integral to the determination of need for new

generating capacity. ’5 Identification of the overall

efficiency or the economic benefits potentially

obtainable from expansion of the extra-high-voltage

transmission line system and increased interutility

sales can easily go unrecognized in the planning

process.

State Certification and Licensing

Major transmission line construction projects

usually require some sort of State certification

and/or licensing. Certification normally comes in the

form o! the issuance of a “Certificate of Public

Convenience and Necessity” (CCN) by a State’s

public utility commission (PUC). Other State agencies, such as the environmental protection department, may also be involved in the licensing of

projects through, for example, their responsibility to

issue requisite construction and operating permits.

In some States, power project siting boards coordinate State agency responses to transmission line

projects as well as serve as decisionmaking entities.

(See table 7-l.) A CCN is a prerequisite in many

cases for other permits and authorizations, such as

the taking by eminent domain of land that is needed

for the completion of the project.

Requirements for documentation in support of a

CCN application are vague in most States, one of the

many sources of uncertainty in the certification

process, Applications usually include formal testimony by the utility summarizing the utility’s argument for the project. Upon receipt of an application,

a case or docket is opened by the PUC, a hearing

schedule is established, and potential interveners are

notified. lntervenors frequently include other State

agencies and utilities, large power users, and public

interest groups. The PUC either accepts or rejects

interveners’ applications and the case usually enters

a “discovery” phase during which the various

parties collect and study information about the

project obtained through depositions and other

methods of information exchange.

At the conclusion of the “discovery” phase, the

PUC staff and the interveners file their formal

testimony, and the utility files a second, or rebuttal,

testimony. The case next enters the ‘‘healing” phase

during which the witnesses submit to examination

and cross examination by attorneys for all parties.

4NGA SurVCy, supra note 1, p. IA.

$NGA, ~upra note ~, p. 16.
204 ● Electric Power Wheeling and Dealing: Technological Consideration.sjbr Increasing Competition

Table 7-l-State Certification and Siting Requirements

for High-Voltage Transmission Lines

Required Required Agency with final

certification siting

State

authority for

authority authority project approval

Alabama . . . . . . . . . . . . . .

Alaska . . . . . . . . . . . . . . .

Arizona . . . . . . . . , . . . . . .

Arkansas . . . . . . . . . . . .

California . . . . . . . . . . . . . .

Colorado . . . . . . . . . . . . . .

Connecticut . , . . . . . . . . . . .

Delaware . . . . . . . . . . . . . .

District of Columbia . . . . . . . . .

Florida . . . , . . . . . . . . . . .

Georgia . . . . . . . . . . . . . . .

Hawaii . . . . . . . . . . . . . .

Idaho . . . . . . . . . . . . . . . ,

Illinois . . . . . . . . . . . . . . . .

Indiana . . . . . . . . . . . . . .

Iowa . . . . . . . . . . . . . . . .

Kansas . . . . . . . . . . . . . . .

Kentucky . . . . . . . . . . . . . .

Louisiana . . . . , . . . . . . . . .

Maine . . . . . . . . . . . . . . . .

Maryland . . . . . . . . . . . . . .

Massachusetts . . . . , . . . . . .

Michigan . . . . . . . . . . . . . .

Minnesota . . . . . . . . . . . .

Mississippi . . . . . . . . . . . . .

Missouri . . . . . . . . . . . . . .

Montana . . . . . . , . . . . . . .

Nebraska . . . . . . . . . . . , . .

Nevada . . . . . . . . . . . . . . .

New Hampshire . . . . . . . . . .

New Jersey . . . . . . . . . . . . .

New Mexico . . . . . . . . . . . .

New York . . . . . . . . . . . . . .

North Carolina . . . . . . . . . , .

Not required

Not required

Not required

Puc

Puc

—

—

Not required

Puc

Puc

Not required

DNR

Puc

Icc

Not required

Utility Division DOC

Corporate Commission

Psc

Not required

Puc

Psc

PUC/Siting Council

Not required

Puc

Psc

Psc

BNRC

PSB

Psc

Puc

BPU

Psc

Psc

Not required

North Dakota . . . . . . . . . . . . PSC

Ohio . . . . . . . . . . . . . . . . Siting Board

Oklahoma . . . . . . . . . . . . . Not required

Oregon . . . . . . . . . . . . . . . Siting Council

Pennsylvania . . . . . . . . . . . . PUC

Rhode Island . . . . . . . . . . . . PUC/Siting Board

South Carolina . , . . . . . . . . . PSC

South Dakota . . . . . . . . . . . . Not required

Texas . . . . . . . . . . . . . . . . PUC

Utah . . . . . . . . . . . . . . . . PSC

Vermont . . . . . . . . . . . . . . PSB

Virginia . . . , . . . . . . . . . . . Corporation Commission

Washington . . . . . . . . . . . , . Not required

West Virginia . . . . . . . . . . . . PSC

Wisconsin . . . . , . . . . . . . . PSC

Wyoming . . . . . . . . . . . . . . PSC

Not required

Not required

Not required

Puc

Puc

—

—

DOT (limited)

Not required

Siting Board

DNR

PUC/DNR

P u c

I c c

Not required

Utility Division DOC

Corporate Commission

P s c

Not required

LURC/BEP

P s c

PUC/Siting Council

Not required

EOB

P s c

P s c

BNRC

Not required

PSC/NCNR/NEC

Site Evaluation committee

BPU/DOC/DE P

Not required

P s c

Not required

P s c

Siting Board

Not requmd

Siting Council

Puc

PUC/Siting Board

Psc

Not required

Puc

Not required

PSB

Corporation Commission

EFSEC (limited)

Psc

PSC/DNR

PSC/DPIJISC

NA

NA

NA

P u c

Shared with EC

—

—

NA

NA

Siting Board

NA

—

P u c

I c c

NA

Utility Division DOC

Corporate Commission

P s c

NA

—

Psc

PUC/Siting Council

NA

—

Psc

Psc

BNRC

—-

Psc

—

Energy Facility Review Board

NA

Psc

NA

Psc

Siting Board

NA

Siting Council

P u c

PUC/Siting Board

P s c

NA

P u c

—

PSB

Corporation Commission

—

—

P s c

P s c

KEY: BEP=Board of Enwonmental Protactlon DoC=Department of Commerca ICC=lllInoIs Commerce Commkwon

BNRC=Board of Natural Resowxs and Conservahon DOT. Department of Transportation ISC.industrial !3tlng COuncd

BPU.Board of Pubfic Utilities DPL.Department of Pubhc Lands LURC.Land Use Regulatory Commismon

DEP=Oepartment of Environmental Promcoon EC= Energy Comm[ssmn PSB.PuUic Servrce Board

DNR=Department of Naturaf Resources EFSEC=Erwrgy Factdltles Site Evaluation Council PSC Public %wwce Commts.wm

SOURCE: Summary of State Government Responses to a survey by the National Governor’s Assocmtion Task Force on Electnclty Transmmson (prepared by the starts of the Public

Ut!htres Commlsslon of the State of Ohro and ot the West Vlrgmla Pubhc Serwce Comrnwon), OTA contractor report, July 1988.
Chapter 7---lssues Associated With Increased Competition and Expanded Transmission Access ● 205

Hearings are frequently held before a hearing

examiner appointed by the PUC commissioners,

although they are sometimes held in front of the

commissioners themselves. Most States also require

that public meetings be held to solicit public opinion

on the project. In some other States public meetings

can be called at the discretion of the public service

commission. 6

In instances where a hearing examiner is utilized,

he or she prepares a report and a proposed or

recommended decision which is reviewed and upheld, rejected, or modified by the PUC commissioners. If the commissioners hear the case, they prepare

both the report and render the final judgment. PUC

decisions can be appealed to the State court system.

The NGA survey found that the certification

process in most States generally takes less than a

year, although the process can take years in some

complex or controversial cases. None of the States

responding to the survey placed a limit on the

amount of time a public service commission can take

to decide on a CCN application.’

Depending on the State, a utility can proceed to

obtain permits from other State agencies needed to

construct a transmission line either before, during, or

after a CCN is granted. In 11 of 33 States responding

to the NGA survey, utilities are not permitted to

pursue required permits from other State agencies

until a final ruling on a CCN has been rendered.8 In

at least 21 States a joint certification and siting

approval process has been instituted that can simplify and expedite State agency permitting issuance.

At least eight States have established some sort of a

siting board to coordinate and resolve permitting

issues.9

Even with all required State agency permits in

hand, a transmission line cannot be constructed until

rights-of-way have been acquired for the land

through which the line travels. For some projects,

land acquisition for the transmission line corridor

cannot be obtained voluntarily by the utility through

negotiation with the landowner. Such opposition can

result in the abandonment of a project or a costly

rerouting unless the utility can invoke eminent

domain to acquire the needed property upon payment of a court-approved level of compensation.

In a few States, utilities are granted the power of

eminent domain by State law for any transmission

line project, but in most the issuance of a CCN is a

prerequisite before eminent domain can be exercised. According to the NGA survey, in at least 11

States the issue of whether or not eminent domain

powers are granted to a utility is decided as one

component of the certification and siting process. At

least 20 States require a separate application and

decisionmaking process for eminent domain which

occurs after siting approval has been obtained. In

some States, the power of eminent domain is

obtained from a court which considers issuance of a

CCN and siting approval as evidence in its decisionmaking process. ] 1

Local Permits and Approvals

Special use permits and zoning variances issued

by local and county governments are commonly

required before construction of a transmission line

project can begin. Acquisition of local permits can

be an extremely complex and time-consuming

undertaking, especially in areas where significant

local opposition to a transmission line project exists.

A recent case study by the National Coal Council of

a 50-mile transmission line project found that over

30 local and county governments had to be individually contacted regarding the project. 12 For a longdistance interstate transmission line project, separate approvals from many local government entities

can be required. Each decisionmaking process

generally includes an opportunity for appeal through

6pub]i~ scrvi~c Camniwkm d’ West virglnlit, “State Survey of Transmission Certification and Siting, and Plartmng Processes, ” unpublished

summary, Nov. 13, 1987, p, H. I’his dwumem provides the preliminary rcsuhs of the NGA-NARUC survey of Slate utility and siting commissions.

7NGA survey, SUpra nolc 1 ! p. 12

~~bllc scwlcc Commission of WCSI Virginia, supra note 6, p. 6.

9NGA su~ey, wpra nolc 1. P

 7

1°lbld., p, 4.

1 I NGA, supra note ~, p. 11.

12 Na[10nal coal Ctluncll, /n[er,$[u/t~ Trtm.\rni.\.sion Of Elccrricio (Washm&on, DC: JUnC lg~~)~ P s~
206 ● Electric Power Wheeling and Dealing: Technological Considerations for increasing Competition

... %

Photo credit: Casazza, Schultz & Associates, Inc.

View of multiple transmission lines

the court system in addition to the administrative

review process.

As part of their certification and licensing processes, several States permit one agency to override

the decisions of other agencies, including local

governments. At least 17 States grant such powers, ’s

but in at least 12 States, local agencies have the

authority to block transmission line projects from

being built within their jurisdiction. ’x

Permitting Transmission Lines Across Federal

Lands

Long-distance transmission lines often cross lands

administered by Federal agencies, especially in the

Western United States. In most cases, siting a line on

Federal lands requires obtaining a right-of-way from

the administering agency in a process separate and

distinct from State and local agency actions. Federal

land permitting frequently involves three steps: an

environmental review, a land-use planning process,

and review of a specific right-of-way application.

Under section 102(2)(c) of the National Environmental Policy Act of 1969 (NEPA), an Environmental Impact Statement (EIS) must be prepared

prior to any major Federal action significantly

affecting the quality of the human environment.

Most major transmission line projects that cross long

stretches of Federal lands are considered major

actions and fall under the EIS requirement.

The EIS process begins with a preliminary

analysis to determine how extensive an environmental review is required by NEPA for a particular

project. A “finding of no significant impact” can

permit a project approval process to continue

without more analysis under NEPA. If minor impacts are anticipated, an abbreviated environmental

assessment is deemed adequate.

For projects with significant potential impacts, a

full EIS is required to be prepared by the agency

administering the land affected by the transmission

line. When the lands are administered by more than

one Federal agency, a lead agency is selected, but all

agencies participate in and are bound by the results

of the EIS. For example, for the 1984 EIS analyzing

the 345-kilovolt (kV) line between the San Juan

Generating Station in New Mexico and Rifle,

Colorado, the Rural Electrification Administration

acted as the lead agency and the U.S. Forest Service

(USFS), the Bureau of Land Management (BLM),

and the Western Area Power Administration served

as cooperating agencies. 15

Separate from the NEPA process, several Federal

agencies, notably BLM and USFS, are responsible

for providing comprehensive land-use plans for the

lands under their jurisdiction and to identify areas

suitable for the construction of transmission lines.

Land-use plans, called Resource Management Plans,

for public domain lands under control of BLM are

13NGA SUIVCy, suprii II()(C ], p. 7.

14NGA, supra nolc 3, p. 10.

I SRL1r;,l Flcctrlfiu.tl(ln A~inls[ra[ion, RIJ(B [1) ,~un Jl~n j~j h~’ Tr~mymik\.ylon Line lln~ A.f,wx l(lt~d FUL dllle.$ Ftnd Environmental !~(l(’t ,~tutement

(Washington, DC’: March 1984), p 1.
Chapter 7--Issues Associated With Increased Competition and Expanded Transmission Access ● 207

required under the Federal and Policy and Management Act of 1976. 16 Similarly, National Forest

land-use plans are required under the National Forest

Management Act of 1976. Utility corridors are

frequently discussed in Regional Guides, which are

prepared for each of the USFS’s 10 regions and in

the Land and Resource Management Plans for each

National Forest. Identification of potential utility

line corridors is an important part of these land-use

plans because only projects sited along corridors

identified as suitable for transmission lines can be

approved.

Many land-use plans, such as the recently released

Farmington Resource Management Plan for the

BLM administered lands in the San Juan Basin in

New Mexico, employ a “window” approach to

planning for transmission lines, which seeks to

identify general areas where power lines might be

needed and more specific areas where a conflicting

land use would preempt transmission line construction. This approach provides significantly more

flexibility in later line siting efforts than would exist

if only specific corridor paths were approved at the

land-use planning stage.

Apart from NEPA and land-use planning processes, approval of the use of Federal lands for a

specific transmission line is still required from the

administering Federal agency. Depending on the

type of transmission line project and the categories

of Federal lands involved, a number of Federal

agency permits might be required. For example, the

BLM issues a right-of-way permit across public

lands and the USFS issues an authorizing document

for a line to cross a National Forest. For lines

crossing an international boundary, a permit must be

obtained from the Department of Energy as the

implementing agency of a 1953 Presidential Executive Order on international electricity transactions.

The Department of Defense can deny a permit if it

interferes with a major military installation or if it is

deemed to interfere with national security. The

Federal Highway Administration (FHA) must approve corridor paths along interstate highways,

which is currently only done as an exception to FHA

policy. The U.S. Army Corps of Engineers must

issue permits for lines crossing interstate navigable

waterways. The Federal Energy Regulatory Commission (FERC) must approve transmission line

projects associated with Federal hydroelectric facilities.

Permitting Transmission Lines Across Tribal

Lands

Approval of transmission line corridors across

tribal lands must be obtained from the governing

tribal council or other tribal ruling body for the

affected Indian lands. There is no Federal requirement for land-use planning on tribal lands, nor are

there standardized procedures for applying for a

right-of-way across tribal lands. Reporting requirements and the decisionmaking process employed to

rule on the application vary among different tribal

governments and can change markedly over time.

Utility companies cannot exercise the power of

eminent domain on tribal lands even though they

may have received overall approval of transmission

line projects by Federal or State agencies. In eight

States, tribal governments are consulted as part of

the State process for transmission line certification

and licensing even if tribal lands are not involved. 18

Transmission line siting on tribal lands has proven

to be very difficult in some instances, even when

only sparsely populated lands are involved. For

example, proposed transmission line rights-of-way

from the San Juan power plant in New Mexico

across the Navajo Nation, where the transmission

system can be linked to the electricity demand

centers in the Far West, have been debated by the

Navajo Tribal Council for decades and remain a very

controversial topic with no clear resolution in site.

Regardless of the decisionmaking procedure used

by the tribal government, any action taken by a tribal

government must also be approved by the U.S.

Bureau of Indian Affairs (B IA) as the Federal trustee

for tribal lands. (B IA, however, does not exercise its

authority over all categories of Indian lands, e.g.,

allotment lands.) Because BIA approval of a permit

for a large transmission line project is often ruled to

be a major Federal action under NEPA, an EIS can

16TI[1c v SCW out Fcdcra] l~d requtr~rnen[s, including the shared usc of” righ!s-of-wuy, where poss]blc.

ITNallOnal R~gu]alo~ R~s~i~r~h ]n$litulc, Non-f rLhnjLa/ /mpCdlrn~n/&\ 10 ~O~er Tran,flkr,\ (~o]umtlus, OH: 1%?), P. 16] ,

l~~bll~ Sewlcc Commlss]or] of West Virgmli~, supra nolc 6, p. 1.
208 ● Electric Power Wheeling and Dealing: Technological Considerations for Increasing Competition

be required for projects on tribal lands. For example,

BIA has acted as the lead agency for the EIS for the

proposed Ole power line in New Mexico because

several proposed routes could affect Pueblo Indian

lands or sacred sites within a National Forest.

Multi-State Siting Efforts

Certification and siting of transmission lines are

generally the responsibility of State regulatory

agencies. For a long-distance interstate power line

project, regulatory agencies in each State independently review the portion of the project within their

jurisdiction. Denial of a CCN in any one State can

lead to the abandonment of an entire interstate

project,

An interstate transmission line project which

distributes costs and benefits in many States presents

a difficult problem for State regulatory agencies as

they assess the overall need for the project in relation

to the traditional State-specific criteria for certification. Only a few programs have been undertaken to

date to bring regulatory agencies together during the

planning or permitting of an interstate power line.

Communication among States most frequently occurs on an informal basis through associations of

State agencies such as NARUC. Other examples

include the Western Interstate Energy Board and the

Western Conference of Public Service Commissioners, which in 1987 established a joint Committee on

Regional Electric Power Cooperation; the National

Governors Association, which has formed a Committee on Energy and Environment Task Force on

Electricity Transmission; and the New England

Governors’ Conference, which has formed an interstate agency Power Planning Committee. Occasionally regulators from other States will be invited to

observe or participate in a planning or certification

process taking place in another State. Sometimes a

State agency will take the initiative to intervene in a

regulatory proceeding in another State.

The Federal Government currently plays only a

small role in transmission line certification issues for

interstate or interutility projects. Under the Federal

Power Act, FERC has the authority to set the

wholesale rates that utilities may charge for bulk or

economy sales and wheeling. Although FERC

decisions are critical in determining the overall

economic viability of a long-distance power line

project, it does little to assist in power line siting.

Utility companies have done the most to foster

interutility planning for reliability purposes, which

includes identifying the need for new long-distance

transmission capacity. One institution that performs

this function as part of its mandate is the North

American Electric Reliability Council (NERC).

Power pools and coordination agreements among

utility companies provide another forum for joint

utility planning and transmission line project development. For example, both the New England Power

Pool and the Pennsylvania-New Jersey-Maryland

Interconnection engage in joint utility planning

activities. Moreover, ad hoc interutility agreements

that deal with potential transmission and reliability

problems occur frequently among utility companies. l9

With one exception, multi-State utility and State

agency programs regarding long-distance transactions are voluntary. The one mandated interstate

electricity planning agency—the Northwest Power

Planning Council (NPPC)-was established and is

guided by Federal legislation.2O Washington, Oregon, Idaho, and Montana are the member States of

NPPC, which was created by the Pacific Northwest

Electric Power and Conservation Act of 1980. The

Council prepares long-range electricity demand

forecasts for the region and develops power supply

plans capable of meeting that demand.21

Impediments to Transmission Line Siting

Institutional, regulatory, and legal elements of the

transmission line siting process can delay extra high

voltage (EHV) power line projects by adding to their

completion time and cost and by contributing to the

uncertainty that the required approvals will be

obtained. Three potential sources of impediments

are discussed in this section: 1 ) power line approval

l~Na[ional Regulatory Rcsearth Inslitule, SUpTa nOle 1’7, p. 96.

20NGA, supranote 3, p. lg. pacific NoflhWCs( E]cc(rlc power pl~nlng ~(1 ~on~wa[lon&’[ Of 1980, put)li~ Liiw 96-S01, 94 Stal. 2697, Dec. 5, 1980,

16 U.s.c. 839.

21Nonhw~s( Power P]mlng Comcl], western ~/~C(riCi/y s/@ BricJ”n4 p~er, /n(erre~/()~/ Transac/ions, P()~l~d, orCgon, Dc~, 28, 1987,

‘‘ Preface.”
Chapter 7--Issues Associated With Increased Competition and Expanded Transmission Access ● 209

procedures; 2) jurisdictional complexities among

agencies required to give approval to a project; and

3) the lack of multi-State coordination.

Obstacles to Transmission Line Approval

As noted earlier, State-mandated utility planning

processes tend to have a strong focus on the need for

new power plants and frequently do not analyze in

depth the potential for increased long-distance

interutility transmission to facilitate interutility sales

as a supply option. The inherent uncertainties

involved in interutility power sales, especially from

another State or from Canada, often result in a low

ranking of this option in long-range plans. Another

shortcoming of the long-range planning process is

that utilities jointly involved in development of

transmission lines are not required to discuss components of the project either owned by other utilities

or located out of state. State agency staff are left with

the job of thoroughly scrutinizing and consolidating

the project plans. The same shortcomings may often

apply to long-range electricity plans produced by

State regulatory agencies.

The lack of attention given to long-distance

transmission projects and interutility sales during

the long-range planning process contrasts sharply to

the attention these issues draw in the world of actual

electricity sales contracts and transmission line

project development. Moreover, when the time

comes for decisions about specific projects and

contracts, limited analysis from past planning efforts

is available.

State laws regarding the obligations of utilities

and utility regulators alike often create obstacles to

long-distance transmission line projects. State utility

franchise laws generally place the greatest obligation on a utility to provide reliable service within its

service area. This obligation provides a disincentive

for a utility to consider a project such as building a

power plant or transmission line which may have as

its goal supplying electricity to customers of another

utility.

State regulatory agency transmission line siting

criteria reflect the same specificity with regard to

service areas that guide most utility company

actions. In assessing need for a transmission line,

State public service commissions generally examine

first the benefits that may accrue to the customers of

the utility proposing to build the line. These benefits

are then balanced against the anticipated costs of the

project, including impacts on the environment, the

lifestyles of affected residents, and other public

interest considerations,

A difficult analytical dilemma is frequently encountered by State regulatory agencies facing an

application for a long-distance transmission line

project. Often the only direct benefit to the customers living in the service area through which a

transmission line passes is improved reliability of

electricity supply, which is impossible to quantify.

The quantifiable benefits of low-cost electricity

often accrue to customers living in other service

areas or States outside of the agencies’ jurisdictions

or the scope of the application. On the other hand,

local costs are obvious and quantifiable, including

lifestyle and economic disruption, and aesthetic,

environmental, and recreational impacts.

Balancing costs and benefits is a complicated

process for State regulatory agencies, especially in

some States. Wisconsin, for example, has laws

which require that local or statewide benefits outweigh local costs as a condition of power line

approval. Many State regulatory agencies have

responded by developing conservative ‘‘prudence”

or public interest criteria against which to judge the

merits of utility projects under review. These public

interest criteria have on occasion been criticized as

‘‘highly parochial attitudes” that dampen the enthusiasm for utilities to undertake long-distance transmission line projects.23

Another problem utility company applicants face

is that power line approval criteria can differ among

agencies within a State and especially when agencies are located in different States. As a result, power

companies often must file multiple applications in

support of a transmission line project. Moreover, the

information in each application must be tailored to

fit the evaluation criteria of the agency to which it is

submitted.

221bd, p. 90.

27 Natmnid Cm] Council, suprti note 12, p 2
210 ● Electric Power Wheeling and Dealing: Technological Consideration for Increasing Competition

Unless one agency is empowered to veto a

contrary decision by another agency, a utility

applicant faces several ‘‘show-stopper” regulatory

review processes. An adverse decision in any one

arena in any State can force the abandonment of the

entire project. Furthermore, criteria used by a single

agency can change, even during the process of

review of one project.

A final consideration is that very few siting

procedures contain any deadlines for decisionmaking. Thus, it becomes impossible to predict with

confidence when a power line project approval or

denial will be forthcoming. Even when deadlines are

established, they usually affect only one component

of the decisionmaking process, not the entire process. For example, schedules set for regulatory

agency actions are completely distinct from schedules set by courts to address judicial challenges to

regulatory agency actions. Scheduling problems

encountered by transmission line projects have led

NGA to conclude that the lack of a definitive time

table for the regulatory decisions appears to be one

of the biggest causes for delay .24 (See table 7-2.)

Jurisdictional Complexities

A labyrinth of regulatory agency requirements

faces the sponsors of long-distance transmission line

projects, Coordination among Federal, State, and

local agencies is frequently poor, and jurisdictional

boundaries are often vague, leading sometimes to

mismatches, overlaps, and gaps in agency responsibilities and to interagency conflicts.

Federal and tribal land administering agencies

have permitting powers that exist separate from

State regulatory agency approval procedures. Decisions by these agencies affect the viability of a

transmission line project regardless of State agency

actions. Federal and State jurisdictions mesh somewhat more closely between FERC, which sets

wholesale power and wheeling rates upon which

interutility sales depend, and State public utility

commissions, which usually grant required project

licenses. However, according to the National Regulatory Research Institute (NRRI), “there is virtually

no coordination between the two entities in regard to

these activities. ”25

Table 7-2-Most Important Factors Affecting

Timely Consideration

Most important factors(s) promoting timely considerations:

Statutory time frame

Single agency

Ease of process

Discretionary hearings

Joint review

Information requirements

Formal planning process

Limited siting authority

Most important factor(s) hindering timely considerations:

Reviews/opposition/issues

Environmental constraints

Incomplete information

Lack of resources

Duplication of effort

Cumbersome process

Lack of deadlines

Court involvement

Other agencies involved

None

SOURCE: Summary of State Government Response to a survey by the National

Governors’ Association Task Force on Electricity Transmmion (prepared by

the stalk. of the Pubhc UtIIItres Commission of the State of OhIo and of the

west Vtrginia Public Servtca Commission), OTAcontractor report, July 1986.

Depending on the State, several State regulatory

agencies can be involved in the permitting process

for a large transmission line project. Although many

States have established either a siting board or

appointed a lead agency to coordinate the State

review process, guiding an application through the

regulatory apparatus can be a difficult and timeconsuming task. Joint agency permitting processes

remain the exception, not the rule, and because

consideration of some permits is often contingent on

issuance of others, agency approvals must sometimes be sought sequentially rather than simultaneously.

Participation of a multitude of local municipalities and county governments in permitting a longdistance transmission line represents another layer

of jurisdictional complexity. Even in States where

local decisions can be overruled by a State siting

agency, local government actions are still important

to the overall siting process, especially where strong

local opposition makes a State agency leery of

vetoing local government actions.

MNGA, SUpriI note 3, p. 23.

~~National Regulatory Research Institute, supra note 17, p. 169.
Chapter 7-issues Associated With Increased Competition and Expanded Transmission Access . 211

Added to this intricate network of regulatory

agency interactions is the court system. Judicial

review of regulatory agency actions is a legal right

of opponents to most agency decisions, Thus,

depending on the agency and the decision involved,

Federal, State, and local courts frequently enter the

transmission line approval process and can create

lengthy tangents from the regulatory agency review

process.

Lack of Multi-State Coordination

Variations in transmission line approval processes among States coupled with the lack of

coordination in decisionmaking and interstate information exchange can create major obstacles to

long-distance power line projects. Even where there

is some fledgling effort at interstate coordination, no

one State agency is necessarily bound to implement

a decision made as a result of multi-State planning

efforts.

Coordination between State agencies and FERC

is also inadequate. The current practice of independent actions by FERC and by State regulatory

agencies has moved the NRRI to conclude that ● ‘the

Federal-State regulatory dichotomy can be considered to be an important institutional impediment to

the movement of bulk power between utilities. “26

One problem that can result from the lack of

coordination between FERC and State agencies is

that State public utility commissions, as they make

their cost/benefit analyses, cannot necessarily obtain

needed information from FERC. Another potential

problem is that State regulatory decisions with

regard to interutility power projects can be affected

by future FERC rulings that the agencies cannot

anticipate and over which they have no control.

Interest Group Perspectives

A number of interest groups frequently interact

during the siting of a transmission line. These groups

include utility companies, government regulators,

landowners, consumers, environmental organizations, and energy system advocates. Although the

positions of these groups are molded by the individual circumstances surrounding each project, a number of perspectives are commonly associated with

each group. It is the clash between these perspectives

during the siting process that frequently leads to the

conflicts that impede transmission line siting.

Utility Companies

At least 35 utilities in the United States now have

formal public participation programs to assist in the

planning of utility project...27 Nearly all utilities

include public participation at some point in their

decisionmaking regarding transmission lines.

Nonetheless, it is common for utility companies

to feel that criticism of transmission line projects

comes from amateurs who cannot possibly understand the economic and technical intricacies of the

electric utility industry. In many respects, utilities do

know more, if not best, and in adversarial environments resentment can build. Moreover, State franchise laws and historical utility standard operating

practices tend to promote conservative, risk-averse

attitudes on the part of many utility companies. On

occasion, these attitudes can reinforce skepticism

towards suggestions originating outside utility company circles, especially ideas regarding complex

projects such as transmission line construction.

Government Regulators

State and Federal Government regulatory agencies respond first and foremost to the statutory

mandates under which they operate. For State public

utility commissions this usually means careful

implementation of prudence and cost/benefit balancing concepts in transmission line siting reviews.

For an environmental protection department this

translates to assurance that transmission line applicants will comply with a wide range of construction

and operating requirements.

A narrow perspective could develop among individual regulatory agencies with each agency focusing on its mandated responsibilities. This perspective does not necessarily foster free information

exchange, cooperation, and compromise among

decisionmaking authorities and also may hinder the

development of a rationale for collaboration among

261bld, p. 47.

~?WcsI\Icw Sptcial S[udics in Nii[ural Rcsourcc Mwugcmcnt, Dcnni\ W, Ducsik (cd,), PddIt /nvolvetncnt in Energy Ful ilify P/unnin~ The Ele(fric

UtdLr,v .Experlence (Boulder, CO: WCSIWCW Prc\\, 1986), p. 5.
212 . Electric Power Wheeling and Dealing: Technological Considerations for lncreasing Competition

agencies that could expedite and facilitate transmission line siting approval.

Landowners and Affected Populations

People who live, work, or play under or near a

proposed transmission line corridor are often the

most vocal interest group during the siting process.

Their concerns can take many forms. If they live

directly beneath the proposed path of the power line,

they might be opposed to moving or they might fear

that they will be inadequately compensated for the

loss of their homes. These same concerns are typical

if businesses, such as farm or ranch operations, are

situated along a line’s path. Public health concerns

are also commonly encountered among people who

live near an EHV transmission line.

Local opposition to a transmission line can also

occur if the line is perceived to threaten noneconomic values attached to the land. Thus, for

example, some Native American groups have opposed transmission lines crossing lands they hold

sacred. And, subtle lifestyle disruptions caused by

transmission lines, such as aesthetic degradations,

can foster controversy about a project. Noneconomic

concerns can cause an affected population to view as

unfair the distribution of the economic costs and

benefits of a transmission line project if they believe

they will absorb a disproportionate share of the costs

while the benefits are more widely dispersed or

accrue to others altogether.

These concerns can often be addressed through

careful route selection for a proposed line, extensive

impact mitigation programs, and increased compensation to the affected population. Nevertheless, the

perspective of the local population can solidify into

nonnegotiable opposition, typified by the slogan

“not in my backyard. ”

Ratepayer Consumer Groups

The electricity ratepayer is usually concerned

chiefly with the cost of electricity at the point of end

use and, to a lesser extent, with long-term reliability

of supply. Under the current conditions of excess

power generation capacity in many parts of the

country, these concerns frequently are reflected in

support of increased competition in the electric

utility industry, more interutility sales, and wider

interutility connections to facilitate long-distance

transfer of cheap electricity. In some instances,

however, concern over the cost of a transmission line

project or over the future availability, cost, and

reliability of supply can outweigh these protransmission expansion sentiments, leading some ratepayer

organizations to oppose such projects.

Environmental Organizations

Environmental groups often take strong exception

to the potentially adverse impacts of long-distance

transmission lines on the visual and physical environment, wildlife, human health, and traditional

lifestyles. In many instances where proposed transmission lines cross inhabited areas, the concerns of

environmental groups reflect those of local landowners, particularly with regard to public health

issues and the disruption of traditional lifestyles, and

sacred sites.

Alternatively, environmental groups can oppose

transmission line projects because they conflict with

land use objectives distinct from those held by the

affected population, thereby placing them in conflict

with the landowners on these issues. This situation

often occurs for transmission line projects proposed

to cross sparsely populated lands such as National

Forests and other public lands managed by the

Federal Government. Rerouting and impact mitigation measures can sometimes, but not always,

resolve satisfactorily many of these environmental

concerns.

Energy Systems Advocates

A number of organizations promote a particular

energy policy objective or technology. For example,

‘‘soft path” energy advocates believe that a combination of energy programs to promote conservation

and decentralized power supply systems provides

the best approach to long-term energy security in

this country. 28 Similarly, trade organizations exist to

promote individual energy technologies, including

decentralized systems, conservation, and “hard

path’* coal and nuclear generating technologies.

In some instances promotion of long-distance

electricity transmission and interutility power sales

can be contrary to the objectives of energy systems

advocates. For example, in the late 1970s, Citizens

28Amo9, ~vlns, .$of[ Emrgy pufhs (C’~rnbridge, MA: Bdlingcr Publishing CO., 1‘)77 h P. I ~.
Chapter 7-Issues Associated With Increased Competition and Expanded Transmission Access ● 213

for a Better Environment opposed on technology

grounds the expansion of long-distance transmission

capacity to California from the Northwest partially

because of a concern that the capacity would be used

as a justification for the proposed construction of

several large nuclear plants in Washington State.

Another example is the National Coal Association’s opposition to the construction of a transmission line from Quebec, Canada to an existing utility

line owned by Central Maine Power Company. The

Association feared the project would promote the

importation and use of hydroelectric power to the

detriment of coal-fired power plants .29

Options To Improve Transmission Line

Siting

The approval of transmission line projects by

regulatory agencies is a routine, although often

difficult procedure. According to the NGA survey,

State regulatory agencies approved 515 transmission line projects between 1976 and 1986, while

denying approval for only 18. More than two-thirds

of the projects approved during 1981 to 1986 have

been completed.30 The survey did not distinguish

among the types of lines involved.

The success rate of power line siting notwithstanding, impediments to siting continue to draw fire

from interest groups and a number of recommendations for ways to improve the siting process now

enjoy considerable support in some circles. Several

proposed recommendations are presented as policy

options in this section.

Expanding the Planning Process

Inadequacies in the long-range planning process,

especially with regard to transmission line planning,

could be reduced in a number of ways. Simply

providing more resources to the agencies involved in

planning could help produce more comprehensive

and insightful plans. Transmission line and interutility power sales issues could receive a higher priority

in the planning process. The scope of planning

efforts, including those submitted by individual

utility companies, could be broadened to include

regional and interstate electricity issues. Some

entities that are frequently exempted from planning

requirements, such as municipal-owned utilities and

power cooperatives, could be required to participate

more in the planning process.

Greater integration of planning efforts and transmission line project development could also enhance the usefulness of planning. More relevant and

accurate long-range electricity plans should be of

greater usefulness in determining overall project

costs and benefits during the regulatory review

process of specific transmission line projects. As

noted by the NGA, ‘‘planning on a multi-State or

regional basis can help identify even larger sources

of savings from improved coordination of generation and transmission capacity development. “31

Improved planning should help utilities anticipate

land requirements for transmission line corridors

farther in advance and with greater certainty of

actual future need. The NGA and others have

suggested that several transmission line corridors be

pre-approved as part of the planning process. Creation of ‘‘resource banks” of approved corridors

could provide ‘‘a bridge between the planning and

transmission line certification processes to reduce

the lead time for final approval” of transmission line

projects, the NGA believes.32 On the other hand, it

can be argued that preelection of multiple corridors,

some of which will never be used for transmission

lines, can needlessly involve and upset people, lead

to unnecessary changes in patterns of land use and

value, and add significantly to the cost of planning.33

Streamlining the Regulatory Approval Process

Simplifying and shortening the process for obtaining certification and license approvals for a

transmission line project from State and local

regulatory agencies has undoubtedly been for years

the single largest target of reformers of the siting

process. Frustration with the difficulties inherent in

the current system has, in part, prompted the Electric

~~coal Week, SCpI. 8, 1987, p. ~.

3(J~bl]C Sem]cc commt~slon of WCSI Virginia, Supra nOlc 6, p. ~.

31NGA, supra note 3, p. I 8.

321bid, p. 25.

ssNati~nal RCgUlalO~ ReSC~Ch InSlitute, Supra n(.)lt IT, p. 156.
214 ● Electric Power Wheeling and Dealing: Technological Consideration. for Increasing Competition

Power Research Institute to develop a handbook for

utilities to use as they weave through the regulatory

labyrinth. 34

One of the most frequently made suggestions is

that the State siting process be coordinated by a

single agency or by a Siting Board composed of

members of several agencies. About 12 States have

already taken this step, although the circumstances

when the Boards become involved and the extent of

power vanes considerably.35 This move toward

‘‘one-stop” shopping for licenses and permits has in

fact expedited the siting process in many cases, but

provides no guarantee that the controversy surrounding a transmission line project can be resolved.

Nonetheless, the NGA has concluded that “consolidation of the approval process within a single agency

(even if that agency must work with other agencies)

appears to improve the predictability and certainty

of the regulatory process and may increase the speed

with which the State acts on project proposals. "36

Endowing siting agencies or boards with the

power to overrule decisions made by other regulatory agencies and local governments is another

suggestion commony offered to speed government

review of transmission line project applications.

Many States currently do authorize preemption of

decisionmaking authority by some agencies, resulting, in some instances, in faster siting of transmission lines. But delays can still occur in part because

of a reluctance to assert veto authority. Thus,

endowing an agency with veto power may save little

time and effort in the review process, but it does

create a greater degree of certainty over the final

outcome.

Establishment of clear criteria against which a

transmission line application can be measured could

also help simplify the siting process. Some States,

including Florida and Montana, have established

specific siting criteria, such a.. minimum corridor

widths for power lines, based on generic issues, such

as public health concerns. Greater definitiveness and

specificity in siting criteria can ease the information

requirements for the applying utilities and help focus

the review process.

Finally, many critics of transmission line siting

procedures call for the institution of firm deadlines

in decisionmaking. The NGA has noted that ‘‘of

those (impediments) involving State regulation, lack

of a definitive time table for the regulatory process

appears to be one of the biggest causes of delay. ”37

On the other hand, the price tag for forcing decisions

within tight schedules can be inadequate review and

analysis of the issues involved. Moreover, structuring a penalty for an agency for missing a deadline

poses difficulties and, as a result, deadline schemes

usually act more to pressure rather than coerce

agencies to act on utility applications for transmission line projects.

Involvement of Multi-State, Federal, or

Independent Agencies

A final group of policy options are tailored

especially for application in the siting of 1ongdistance transmission lines that involve several

States.

Increased Federal Government involvement in the

siting of interstate transmission lines has been

suggested as a policy option by several organizations. The National Coal Council, for example, has

been very supportive of this option and has recommended that the Secretary of Energy intervene in

siting cases that have interstate or regional implicaTtionso

3s

Increasing the powers of the FERC could provide

another method of bolstering the Federal role in

interstate transmission line siting. FERC or another

Federal agency could affect siting indirectly by

creating ‘‘model” siting procedures or transmission

line application review criteria which could help

standardize procedures used by State regulatory

agencies.

34 EPRI,Electrica] Systems Division, ‘‘A Stream] incd Proccdurc for Obtaining Regulatory Approval for Ncw Transmission Lines, ” contractor report

prepared by Westinghouse Elccuic Corp. (EL-1404, RP-TBS79-733), December 1982.

MNGA, supra note 3, pp. 28-30.

JfYbid, p. lo.

371bid, p. 23.

J~Nalional COaI coun~l], supra note 12, attached Iclter 10 Sccrctary Hcmin@on.
Chapter 7-issues Associated With Increased Competition and Expanded Transmission Access ● 215

Expanding the Northwest Power Planning Council concept to other regions could offer another

avenue to increase Federal and multi-State involvement in transmission line siting. Alternatively,

congressionally approved siting ‘‘compacts” of

States through which a transmission line is proposed

to pass could create ad hoc multi-State decisionmaking bodies with broad siting powers. It should be

noted, however, that there have been no clear

examples of one State blocking the construction of

an interstate transmission line.

Informal Federal-State transmission line siting

dispute resolution boards could provide forums

where clashing interest groups can come to discuss

and possibly resolve their differences. More dramatically, some have suggested that the Federal

Government or some independent dispute resolution

organization, such as the American Arbitration

Society, could be empowered to make decisions on

issues about which regulatory agencies in different

States disagreed.39 But, the need for such a Federal

role is not clear.

Enhanced Public Participation

Most utilities and State and Federal regulatory

agencies have established extensive public participation programs which include participation in the

review of transmission line projects, These programs seek to provide early disclosure of information and to solicit public input into the designing of

utility projects. Citizen review, evaluation, advisory,

and participation committees are commonly formed

to help shape transmission line projects. Moreover,

individual interest groups can make their opinions

known through public comments, formal interventions, and legal appeal processes which occur at a

number of points under most siting procedures.

Development of new models for public participation specifically geared to the circumstances commonly encountered during transmission line siting is

an ongoing process which, if effective, could alleviate some impediments to siting. Toward that goal,

the Edison Electric Institute convened a task force

on public participation in 1982 and subsequently

sponsored a lengthy study of the issue.

Conclusions

The complexities involved in the siting of large

transmission line projects are significant, especially

with regard to multi-State projects designed to

promote interutility power sales. Nevertheless, the

simple fact is that most power line projects are

successfully sited in a timely fashion, if not to the

satisfaction of all the interest groups participating in

the decisionmaking processes. Even in the face of

increased demand for new transmission capacity

anticipated by electric utility industry restructuring

proposals, current siting procedures are probably

adequate, although inefficient.

A number of impediments to transmission line

siting can be clearly identified, although sound

recommendations to remove those impediments are

not so obvious. A dearth of information about future

transmission needs and a lack of communication

among regulatory agencies appear to encourage

confusion in siting processes. Conflicting regulatory

agency priorities, objectives, and jurisdictions can

add Byzantine elements to siting processes. Multiple

decisionmaking procedures within overall siting

procedures permit interest groups to pick the decisionmaking arena of their choice in which to express

their views or to repeat the same concerns before

different audiences recognizing that a single success

can achieve their objective.

Many proposals to alter siting procedures could

have negative as well as positive effects in practice,

sometimes leading to solutions which create conditions as bad or worse than the problems they are

designed to correct. For example, creation of “oneStop” siting entities with final decisionmaking

authority can greatly simplify and expedite siting,

but it can also undercut public participation, information dissemination, and the exercise of statutory

responsibilities by other regulatory agencies. Bolstering long-range transmission planning can provide more useful analytical information for decisionmakers, but collection of this information can add

time and costs to siting processes and identify new

uncertainties and information needs.

Most of the proposals to address the impediments

to transmission line siting discussed in this section

are being tested to a greater or lesser degree in

3~Nali~nal J@u]alo~ RcseW~h Institute, supra nolc 17, p. 159.
216 ● Electric Power Wheeling and Dealing: Technological Considerations for Increasing Competition

specific States or regions of the country. Perhaps the

most prudent advice is to encourage the continuation

and expansion of these efforts to improve siting

procedures. Greater attention to the implementation

of innovations to traditional siting protocols under

virtual “test” conditions coupled with redoubled

efforts to share the resulting experiences and insights could produce significant improvements to

siting processes over time without undercutting

along the way what appears to be a basically sound

process.

ENVIRONMENTAL EFFECTS OF

INCREASED COMPETITION IN THE

ELECTRIC POWER INDUSTRY

The electric utility industry faces perhaps the

broadest array of environmental issues of any

industry in the Nation and has for many years.

Because electric utilities are so pervasive in the life

of the United States. and because their facilities are

often so large, the industry has been at the cutting

edge of environmental disputes and a leader in

developing environmental control and monitoring

technology.

As the industry’s structure changes, either

through evolution or by conscious public policy,

there is no reason to believe that environmental

issues will recede into the background. Indeed, it is

likely that environmental concerns over generation,

transmission, and distribution activities will continue to be a major element in the industry’s

structural dynamics under any future scenario.40

Generation

The major environmental impacts of electric

power generation can be divided according to fuel

cycle issues and combustion issues. Changes in

electric power industry regulation and the structure

of bulk power markets could have demonstrable

impacts in these areas, and moreover, these are 1ikely

to vary in different regions of the country .41

Fuel-cycle issues include the impacts of extracting, processing, and transporting fuels and disposing

of their wastes. The primary fuels for power

generation are coal, oil, gas, uranium, and waste

materials. Major concerns include the impacts on

competing land uses, air and water pollution, and

hazardous waste disposal. Renewable energy

sources such as hydropower, wind, solar, and

biomass each have their own set of environmental

impacts.

Combustion issues include not only the direct

impacts of generation or combustion, but also the

mix of electric utility generation—the size, type,

fuel, and location of generating plants. Burning

fossil fuels raises a whole series of air quality issues,

including control of emissions of SO2, NOx, CO2,

and other hazardous pollutants. Nuclear generation,

of course, has a long and familiar list of environmental and public health disputes, including routine

air and water emissions, reactor safety, emergency

planning, and the consumptive use of water.

There is fairly widespread belief that reliance on

competitive bidding for new electric power supplies

could, depending on the details of the bidding

process, cause a shift in the size of new plants and in

fuel choices. If small supply increments, lower

short-term costs, and shorter lead time projects are

favored, it is likely that more oil and gas generators

will be built. However, developing coal technologies—

particularly atmospheric fluidized bed and integrated, combined-cycle coal gasification-that are

targeted at smaller, modular units could eventually

be competitive for cogeneration and utility applications. Under other bidding structures, larger plants

with perhaps lower long-term costs might be able to

compete more effectively.

Size and fuel choices can be important environmentally. Until quite recently, air pollution regulations subjected smaller boilers (i.e., less than 67

megawatts) to much more lenient sulfur dioxide

standards than large boilers. But as a result of a

lawsuit brought by the Natural Resources Defense

Council and settled late in 1987, the 1.2 pounds per

million Btu SO2 standard and 90 percent emissions

reduction rule will apply to all fossil-fueled boilers

above about 27 megawatts. 42 And EPA is on a

4~Much of [he in f(>mlallon in [his ~tion is drawn from an (.)TA wntrxmx r~porl, Kennedy P. Mtiiz~, “Envwonmtmtal Efl@s of Increased

Competition in the Ektric Power Industry, ” May 1988.

~1 see ~IW ~C discussion m Ch. ~.

42wh1]C 27 Mcgdwatls is ralhcr ]argc for ~ ~a~.fired ~onlbu$lion [Urbinc Or ~ombin~d-~y~]c project, it is on the smaller side for ~oal -fired boi]crs.
Chapter 7-Issues Associated With increased Competition and Expanded Transmission Access ● 217

schedule to apply the 1.2 standard to even smaller

coal-fired plants by 1989.43

Transmission and Distribution

Transmission and distribution have their own set

of environmental issues. While these issues haven’t

received the national attention accorded air quality

and waste Tdisposal, they have often been just as

intense and fractious at the local level as the more

traditional environmental disputes. Transmission

issues may become a greater part of the environmental debate in the future, as utilities change their

spending patterns away from building plant and

toward moving power.

Transmission and to a lesser extent distribution

are intimately tied into local land use and zoning,

and disputes often take place in the institutional

forums created for dealing with local problems, such

as city, county, and State zoning boards, boards of

zoning appeals, and the like. Other venues for land

use disputes over transmission and distribution can

occur before State bodies that must license or permit

a facility, in an eminent domain proceeding, or in

State courts.

44 If Federal lands are crossed, Federal

land management agencies will be involved. Landowners who will see power lines cross their property, particularly in urban or suburban areas but also

in rural areas, often believe the line will lower the

value of their property. 45 Consequently, the disputes

can be very bitter and intense.

Because power lines can extend for long distances, are often highly visible, and frequently pass

through populated areas, the siting process can be a

time-consuming, politically fractious, and frustrating experience for the utility, regulators, and local

citizens. The economic impacts of siting decisions

on affected landowners can be direct and costly.%

After the project has been sited and permitted, there

can also be environmental disputes related to the

impacts of construction, including issues such as

erosion and sediment control, soil compaction,

destruction of forests, and the like.47

Once a power line is built and operating, a

different set of impacts comes into play, although

these issues likely will have been raised earlier

during the siting and permitting processes. These

include visual impact, impacts on bird life,48 audible

noise,

49 corona effects,50 and, an area that has

generated a lot of attention of late, the effects of

electrical and magnetic fields on wildlife, livestock,

and human health.51 Another environmental issue

related to existing power lines is the use of pesticides

and herbicides to clear rights-of-way.

Visual impacts play a major role in transmission

line disputes, in part because the visual presence of

the lines often becomes a symbol of its total

presence. Figure 7-1 shows the dimensions of

typical 345-kV transmission line towers. The utility

industry has attempted to design less visible structures. although that can drive up costs. Some

analysts have suggested that the presence of a visible

line is ‘‘a negative feedback mechanism” that could

serve to slow growth of electrical use, by symboliz43 Tc]ephonc intewiew with David Hawkins, NRDC, Jan. 7, 1988. Plants with a capacity factor of less than ~~ percent and plants burning VefY low

sulfur 011 are exempted from the percentage reduction requirements. See also, American Public Power Association, ‘‘Small power plants now must meet

pollution s@ndards,’ ’American Public Power Weekly, Jan. 11, 1988.

44sce the discussion of the siting process elsewhere in th]s chapter.

4SRo~~ R. Thompson and William E. Phillips ,

C

’Agricultural Land Value Changes From Electric Transmission Lines: Implications for

Compensation,” Righr of Way, December 1985, pp. 24-27.

%Su, for exmple, the rem~ks of Ric~d Disbrow, President, American Electric Power ScrviCe COW.. OTA workshop, SePt. ~8* 19~T.

47 For a ~@ dl~cussion of the environmen[a] irnp~ls Of powerlincs, xc FCderal co]swip Transmission Corridor Study Projeel Team, “Developing

Numerical Values to Estimate Potential Environmental Impact of Power Transmission Corridors,” Bonneville Power Administration, Novcrnber 1978,

Appendix.

daRene M~es, EPRI JOIUM1, M~ch 1980. p. 49.

49JOhn A. Molina et al., ‘‘Modification of Transmission Line Audible Noise Spectra to Reduce Environmental Impact, ” /EEE Tranwcrions on Power

Apparaws and Systems, vol. PAS-l(K), No. 4, April 1981.

sOAjr ioniy~ by tie high electric fields at the surface of the conductor crcales tie corona phenomena.

slFOr a dlSCuSS1on of tic evolution of ~nvironmcn[al con~ems ahoul WwCr lines, we Wi]liam E. I-~erO, ‘‘The Evolution of Electromagnetic Effects

Issues, ” paper presented at the international Ulility Symposium on Health Effects of Electric and Magnetic Fields, Sept. 16-19, 1986, Toronto, Canada.

89-137 - 89 - 8
218 ● Electric Power Wheeling and Dealing: Technological Considerations for Increasing Competition

ing to consumers the costs associated with electricity

use.

52

Existing power lines can have an adverse impact

on bird populations, including protected species

such as the golden eagle, which use poles as perches

for hunting and are often electrocuted by contact

with lines. There is also some evidence that overhead lines may increase avian mortality from

collisions and changes in behavior, although not

much data on this problem has been accumulated.53

The physical presence of power lines is associated

with what are sometimes referred to as “nuisance”

effects that are annoying or unpleasant to those

living or working around them. Corona discharges

from power lines create audible noise and interfere

with radio and television frequencies. Corona discharge is largely a function of weather, posing

greater problems in rain or fog.54 Corona noise is

typically both low-frequency hums and buzzes, and

random, high-frequency hisses and crackling. Studies suggest that the high-frequency component is

more objectionable to listeners .55

Another product of corona discharge is ozone, a

powerful oxidant that can affect living tissue. Ozone

is similar to ionizing radiation, in that it causes

tissues to breakdown and undergo chemical change.

It can irritate eyes, lungs, and circulatory systems of

animals, including humans, and increase susceptibility to infection and chronic disease through stress.

It can also cause direct damage to vegetation.

Power lines may also have a more subtle impact

on health. A number of studies have demonstrated

effects on cells, animals, and humans from exposure

to extremely low-frequency fields such as those

generated by power lines and household appliances.

The electric utility industry is devoting a greater

share of its research dollars to this emerging field,

trying to pin down the mechanisms that are at work,

and determine what steps can be taken to prevent

damage if it is occurnng.56

Finally, maintenance and vegetation management

can have environmental impacts with existing transmission lines. Utilities generally want to establish a

shrubland environment under their power lines,

because shrublands last far longer than grasslands,

once undesirable trees are removed. Since the 1940s,

utilities have applied chemical herbicides to control

vegetation. Information is lacking on the effects of

chemical herbicide treatment beyond the initial

brownout that results.57

Scenarios of Change in the Electric

Utility Industry

Structural changes in the electric power industry

could have different environmental consequences.

These impacts are difficult to discern in light of the

speculative nature of the proposals. Despite the

inability to pin down the impacts with precision, it

is possible to describe how OTA’s five scenarios

(see ch. 3) might affect the environment.

Scenario 1: Reaffirming the Regulatory Compact

As with all the scenarios, scenario 1 presents both

environmental problems and opportunities. The

environmental advantages flow from the fact that

scenario 1 is well understood. As essentially the

status quo with slight modifications, the first scenario presents issues that have been faced in the past

and relies on institutional arrangements that have

been developed over the past 20 years. With this

scenario, most environmental issues are known.

The concept of “rolling prudence” has some

potential environmental benefits. It might prove

easier to cancel some projects earlier in the construction process, before such enormous amounts of

capital have been sunk in a project that cancellation

becomes politically difficult. Prudence is a doctrine

SZThomm w. Smlti et ~]., Tr~~~”ssion Lines: Enviro~nta/ and Pub/i{, Po/icy Consideration, Institute for Environmental Studies, University Of

Wisconsin-Madison, June 1977, p. 44.

53 M~es, ~upra note Q& Of ~our= ]Wge birds a]so can have minor, but harmful irnpacls on transmission Iincs. EPRI, “A Joint Utility Investigation

of Unexplained Transmission Line Outages, ” (EL-5735) Final Report, May 1988, Palo Alto, CA.

sdsmi~ et a]., supra note 52, p. 39.

ssMolina et al., supra nOte 49, p. 2]22.

561~E~: The &bate on He~th Eff~ts, ” EPR/ Jour~/, vol. 12, No, 7, &to&r/Novem&r ]987, pp. 4-]5, SW idSO, Mm H. Malakoff, “Electronic

Smog,” Not IUan Apur?, March-April 1988, pp, 1O-11.

sTSmi~ et al., supra note 52, p. 32.
Chapter 7--issues Associated With Increased Competition and Expanded Transmission Access ● 219

Figure 7-1-Dimensions of Typical 345-kV Transmission Lines

18’6” 24’6”

-

“ 0

27’3’”

l — l

.

“- \ “ /

—.. 

18’

0

SOURCE: Office of Twhnology Assessment ada@ad from Electric Power Research Institute, Transmm@on Line Reference &ok: 345kV#rdAlwwe, 2d ad. (Palo Alto. CA: Research

Reports Center, 1982).

that utility commissions have rediscovered recently

and applied with various effect. However, the

findings of imprudence necessarily come too late to

prevent expenditures which should never have been

made.

Utilities complain that post-construction prudence determinations subject them to too much

financial risk, and there is merit in that complaint.

But many regulators, consumer groups, and environmentalists are also critical of the current system

because it allowed construction to continue on a

number of nuclear and coal plants that later proved

to be imprudent because of their extreme costs or

excess capacity. Carefully designed, periodic prudence reviews could provide an institutional mechanism to prevent unneeded, socially costly, and

environmentally damaging plants from being built.

The periodic reviews might also be a way to factor

in technological advances made during the course of

plant construction. Under the current system, once a

plant design is finished, it can be difficult to

persuade the utility to alter it voluntarily to incorporate advances in pollution control technology. Reviews during the process might provide a way to

update the plant plans and apply the best available

technology. State assurances of recovery of prudent

expenditures would offer additional incentives.

Scenario 1 is not without environmental problems, but those problems are largely similar to those

under the status quo.

The down side to scenario 1 and the status quo,

from an environmental standpoint, is the incentive it

gives to the continued operation of some of the

oldest and dirtiest coal-burning power facilities,

which are among the primary targets of acid rain

cleanup proposals. For example, Cleveland Electric

Illuminating’s Eastlake plant has a State emission

limit of 5.64 pounds per million Btu and the Avon

plant has a 4.65 pound limit, in contrast, the new

source performance standard is 1.2 pounds. Other

older plants around the country have even higher

emissions 1imits under State Implementation Plans.58

The 1970 Clean Air Act (as amended in 1977) was

premised on the belief that most older plants would

be replaced after their 30-year book lifetime. Consequently, the act relies on the new source performance standards for its regulatory bite, rather than on

pressing for improved environmental performance

of existing plants.

The economic landscape in the years since

Congress passed the Clean Air Act has favored

keeping existing plants on line and avoiding building new ones. This was driven partly by the costs of

pollution control on new plants, but more directly by

unusually high interest rates of the 1970s, coupled

with declining and unpredictable load growth, Power plant life-extension and geriatric programs have

become a major focus of savvy utilities, and some

experts believe that it may be possible to keep old

5~Fi~rcs me from ~ in[crviCw wi(h C’en[crior Encr~y’s environmen[a] department by Kennedy Maize, OTA contractor, Apr. 1~. 1988.
220 ● Electric Power Wheeling and Dealing: Technological Considerations for Increasing Competition

plants in service almost indefinitely .59 Under the

Clean Air Act, if the cost of a life-extension program

exceeds 50 percent of a “comparable new facility,”

the plant may be subject to New Source Performance

Standards (NSPS). According to the Electric Power

Research Institute: ‘‘This regulation has not yet been

tested, and utilities are unsure whether the 50 percent

trigger refers only to a one-time capital expenditure

or to aggregated refurbishment costs over several

years. ”60

The status quo offers a strong incentive for

utilities to keep the oldest, and often dirtiest, plants

on line as long as possible. In extending the life of

existing plants, the utility avoids siting disputes,

heavy capital requirements, prudence reviews, and

major disallowances. By contrast, some of the other

scenarios might encourage utilities to close the

facilities if they can get power cheaper from QFs or

independent producers, can raise capital relatively

inexpensively, or can avoid the need for prudence

reviews and rate basing entirely by building a

deregulated plant.

Scenario 2: Expanding Transmission Access in

the Existing Institutional Structure

From an environmental perspective, this scenario

could have some favorable and some troubling

consequences. On the positive side, it would be

possible to build environmental considerations into

the public interest standard for wheeling orders. For

example, it might further environmental goals to

wheel in power from remote sites to avoid burning

coal or oil in an urban environment. Increased

wheeling could lead to construction of fewer baseload plants and a more flexible electric supply

system, better able to accommodate advanced renewable technologies such as photovoltaics. Greater

wheeling and stronger interconnected transmission

grids could avoid situations such as today’s power

surplus in the South and Midwest while the Northeast faces potential power shortages.61

Scenario 2 also has potentially negative environmental consequences. If expanding transmission

access is successful, presumably more transmission

capacity will be constructed. Utilities would have to

plan for third-party transmission in their system

planning of power lines. The result likely would be

plans for more transmission lines, with concomitant

disputes over siting and construction. Some utilities

might see transmission as a new business opportunity and build transmission marketing into their

plans. Siting, building, and operating electricity

transmission has both well-understood and frontier

environmental problems, ranging from land use to

public health issues associated with extremely

low-frequency fields.

Access to transmission services and expanded

competition might also encourage unneeded plant

construction, both by independent power producers

(IPPs) and QFs. If electric utilities see selling

transmission services as a business opportunity,

rival utilities might get into price wars attempting to

lure generators into their grids. That could lead to

construction of plants beyond what would occur

simply to supply the PURPA market if transmission

continued to be closely guarded.

The availability of wheeling and expanded QF

eligibility could cause a shift in the generation mix.

It is not known how this change might affect the

nature and distribution of environmental impacts of

power generation. Based on early experience among

QFs, it has often been presumed that QFs and IPPs

would rely heavily on gas-fired combustion turbines, with perhaps some combined-cycle generation as well, but initial results of State competitive

solicitations somewhat belie this presumption. See

box 7-A: Bidding in Massachusetts: A Glimpse of

the Future’? While natural gas is the cleanest burning

fossil fuel, it is not entirely devoid of pollutants. In

nonattainment areas, increased local generation

could lead to further tension and disputes over

pollution offsets and lowest achievable emission

rates (LAER). In attainment areas, increased generasg’’~nger Life for Fossil Fuel pkMs,” EPRl Journul, vol. 12, No. 5, July/Augus[ 1987, pp. 21-27.

60]bld, p, 26. A]W, the P]mt ~ou]d ~subject to Nsps If the cmission rate of my of lhc criteria @lut~ts is increased as a result of the llfe-eXtenSiOll

program.

61 Scc New mgl~dGovcmors’ conference, ‘‘A Plan for Meeting Ncw England’s Electric Needs,” Dcccmber 1986. For a powerful critique of this

view see New England Energy Policy Council, “Power to Spare: A Plan ior Increming New England’s Competitiveness Through Energy Efficiency.”

Ju]y 1987.
Chapter 7---Issues Associated With Increased Competition and Expanded Transmission Access ● 221

Box 7-A—Bidding in Massachusetts: A Glimpse of the Future?

The Commonwealth of Massachusetts has been one of the pioneers in implementing a bidding scheme for

allocating generation under PURPA. The State’s department of public utilities issued its first set of competitive

bidding regulations in late 1986, and the first contracts have been awarded. The State and its utilities are now

working on a second round of bidding, with somewhat changed circumstances. 1

The bidding process begins with supply and demand plans for each utility filed with the state’s Facility Siting

Council. Based on its plan, the utility forecasts what its next supply addition will be. If, for example, the utility were

to conclude that the next plant addition it would build to meet projected demand would be a 200-megawatt,

combined-cycle facility, then the utility would attempt to solicit 200 megawatts of supply from QFs. to avoid that

new facility.

Massachusetts regulations stipulate how to calculate costs of the new generating capacity, including system

fuel costs and capital costs. That determination, which is the equivalent to the avoided cost, becomes the ceiling

price for the bidding process or the maximum bid that the utility will accept from QFs.

The Massachusetts program uses a standard contract, developed by the Department of Public Utilities (DPU),

against which the suppliers are to bid. The utility can include “nonPrice” elements in its solicitation and

bid-evaluation process. This is where the utility can build in environmental constraints, or other special conditions

such as reliability, dispatchability, fuel diversity, preferred locations, and the like. The standard contract provides

a baseline, but the final contract does allow for negotiation as long as DPU is able to exercise oversight.

The current bid system does not include provisions for conservation and load management. That thorny issue,

along with the issue of how to treat non-QF facilities, is currently the focus of another regulatory proceeding,

underway at DPU.

It is important to note that Massachusetts already requires wheeling within the State, on the basis of an open,

published tariff. If a QF in the western part of the State wins an award from Boston Edison, State regulations require

the intervening utilities to wheel the power.

The Experience To Date

Boston Edison Co. was the first utility to complete the full cycle, from initial solicitation with the company

expecting to have contracts for 344 MW of power from nine separate projects (see table 7-3). Boston Edison

originally sought only 200 MW, but received bids for 1,860 MW. The levelized ceiling price for the bid was 8.7

cents per kWh, and the successful bids tendered at between 6 and 6.5 cents. The first eight low bidders came in at

a total of 144 MW, but the ninth bidder offered 200 MW. After some negotiations among the parties, Massachusetts

DPU concluded that Boston Edison could go forward with the nine bidders. Later, even though several projects

dropped out, contracts were signed for a total of 416 MW.2

To prevent a repetition of California’s early experience with its Standard Offer No. 4, where as many as a third

of the bidders turned out to be speculative projects that likely never would have been built, Massachusetts’

regulations require that the QF put up a $15 per kW deposit as earnest money at the contract signing.

From an environmental standpoint, the winning projects do not support assumptions that bidding will

necessarily result in a better fuel mix or greater environmental protection than conventional avoided cost

determinations.

First, the 200-MW coal-fired facility belies the widely shared expectation that gas would be the preferred fuel

for QFs and IPPs. It is also important to note that the original bid for the 200-MW atmospheric fluidized bed facility

proposed a site in East Boston, a small, highly urbanized area, Subsequently, the project developers decided that

perhaps an inner-city site wasn ‘t such a good idea and proposed two alternative sites for the project. As of November

1988, the plant remained unsited.

Some 35 MW are to come from waste-to-energy plants. The Clean Harbors project would bum hazardous

wastes in a rotary kiln, raise steam, and sell power to Boston Edison, but whether the project will ever be licensed

IMUCh ~f [his ~nr~atlon IS ba~~WIm[cmknvs by OTA cmrracmr Kenndy MSIZC W’lth f+- Yoshlmura of ~ Mas~chu~ll~ ~~~~~[ ‘f ‘blic

Utilities and witi John Whipperr, manager of energy resouree plaruung and forecasting, Boston Edison Co.

21 INEEs ~I]s 4 wilting ~oj~ls out of Boston Edi\{m SoliciIalion, ” Elci mic Ulilil’y Week, Nov. 21, 1988, p. 19,

Continued on nextpqp
222 . Electric Power Wheeling and Dealing: Technological Considerations for Increasing Competition

Continued from previous page

is clearly a legitimate question. The Webster mass burn facility is already running into the predictable siting

disputes, which threaten to derail or delay the project. It’s future is also clouded because the developers have filed

for reorganization under protection of the bankruptcy court. The Wheelabrator project is one of several proposals

to burn construction wastes or “urban woods. ” Construction wastes would appear to offer a higher quality fuel

stream than conventional mixed trash. It might also be a cleaner waste stream, although one could postulate some

environmental problems with construction trash, particularly with air emissions and ash toxicity from burning

lumber treated to resist termites. Another problem could be associated with the amount of gypsum wallboard in the

waste stream. Burning gypsum could cause serious sulfur dioxide problems. It too remains unsited,

There is an interesting irony in the four cogeneration projects offered by the New England Electric System

(NEES). While NEES has been among the utilities that have been pushing the FERC to embark on an all sources

bidding scheme,3 the Company has been less enamored of bidding for QF power at home. NEES argued in the

Massachusetts proceeding that it could get more and cheaper power by negotiated contract rather than open bidding.

The DPU gave the company an exemption from its bidding procedures in return for NEES agreements on more

stringent wheeling procedures and to a provision that the company must demonstrate that it obtains more power for

less money by negotiations. Thus DPU and other utility oftlcials were surprised when NEES was a major bidder

for the Boston Edison contract. NEES subsequently dropped its four winning project because of siting difficulties.

The technological mix that resulted from the first Boston Edison Request for Proposal (RFP) was probably a

result of bonus points the company awarded in the nonprice section for fuel diversity. ‘‘We had established certain

objectives we wanted to pursue “ in the first RFP, said a Boston Edison official, “that included the promotion of

fuel diversity.”4

Boston Edison plans to revise its RFP over the next few months, to match an updated resource plan and will

then file RFP No. 2 with DPU. While the new RFP will be “philosophically” the same, it will be less price intensive,

and push several nonprice issues.

Anticipating regulatory changes.,5 Boston Edison likely will push environmental performance by providing

target pollutant levels, with a bonus for commitments by bidders to exceed those targets, The RFP, for example,

might specify a 1.2 pounds per million Btu standard for SO2 emission, and give a bonus for a commitment to exceed

by 110 percent.

Boston Edison is also pondering how to build conservation and load management bids into RFP, probably by

targeting specific loads the utility wants to reduce. Utility planners hope to have some version of a negawatt bidding

system in place.

Other Massachusetts utilities are not as far down the bidding road as Boston Edison. The DPU has approved

the following supply additions, and ceiling prices, for the participating utilities:

Cambridge Electric Light Co: 33 MW -7.33 cents per kWh

Commonwealth Electric: 76 MW -6.52 cents per kWh

Eastern Edison: 30 MW -6.86 cents per kWh

Fitchberg Gas& Electric: 11.7 MW -7.69 cents per kWh

Nantucket Electric: 3.6 MW -7.8 cents per kWh

Western Massachusetts Elec.: 40 MW -5.8 cents per kWh

Clearly, capacity bidding in Massachusetts has not proceeded far enough yet to make any firm conclusions

about how it is working from an environmental standpoint. However, the first Boston Edison bids had some

troubling aspects because of the unexpected presence of a large coal-fired plant and the proliferation of

waste-to-energy projects. The second round of bids, driven by tough new pollution rules, could be better. It will be

worth watching what goes on in Massachusetts as a harbinger of what might occur as a result of the FERC bidding

initiative.

3Bill Rankin, “FERC Competitive Bidding Plan Splits The Utility fndustry,” Energy Dal/y, vol. 15, No. 171, Sept. 9, 1987, p. 1.

4~ipF, wpra note 1 ~

5M=Mchu=.~ in 1985 ~as~~ ~ ~ld rain ~on~o] law hat wll] ~ulrc ~ubs[~tj~ sulfur dioxide emission reductions by 1%15. The law requires ~ average

emission rate of all utilities m the State of less than 1.2 pounds of S02 per mdhon Btu. New England Power, the NEES generating subsidiary expects tia[ it will

have to rcduee cmissions from IIS Massachusetts facilities by as much as 46,(Kt0 mns per year, New England Power Faa Sheet, “‘Using Natural Gas al New England

Power Company’s Brayton Poim State to Meet Massachusetts Acid Ram Law Reqummwms,” Jan. 18, 1988.
Chapter 7-Issues Associated With Increased Competition and Expanded Transmission Access . 223

Table 7-3-Boston Edison Company-Winning Bidders-RFP No. 1

Project Size Technology.

FHN Energy . . . . . . . . . . . . . . . . . . . . . . . 200 MW Coal-AFB

(w/ Dominion Resources)

Clean Harbors . . . . . . . . . . . . . . . . . . . . . 2.5 MW Hazardous waste

Bellingham . . . . . . . . . . . . . . . . . . . . . . . . 68 MW Gas-combined cycle

NEES-cogen . . . . . . . . . . . . . . . . . . . . . . . 3.3 MW Combustion turbine

NEES-cogen . . . . . . . . . . . . . . . . . . . . . . . 3.3 MW Combustion turbine

NEES-cogen . . . . . . . . . . . . . . . . . . . . . . . 24.5 MW Gas-combined cycle

NEES-cogen . . . . . . . . . . . . . . . . . . . . . . . 10 MW Gas-combined cycle

Webster Resource . . . . . . . . . . . . . . . . . . 7.4 MW Trash-mass burn

Wheelabrator Energy System . . . . . . . . . 25 MW Construction debris

(aka “urban woods”)

Total . . . . . . . . . . . . . . . . . . . . . . . . . . . 344 MW

MTE: More recwtt developments have cast even greater undartamty over the results of the ttrst round bidding. kcordkrg to E/eetric UtI/(ty

Week,NEES dropped its four wmrring projects because of siting difficulties and two pojects, including the large coal plant and U-W

urban woods project, remam unslted, Even so, conlracts have been sqned for a total of 416 MW. (Elecfrc Utihty kWek, Nov. 21,

1988, p. 19.)

tion would consume some of the PSD increments

available for other kinds of industrial development.

Greater access to transmission could stimulate the

development of trash-to-energy projects by creating

a broader market for their power. That could lead to

even greater contention over waste-to-energy projects at the local and national level.62

Greater access to transmission could also slow

individual utility conservation and load management programs and complicate the analysis that goes

into conservation and load management planning. It

might become necessary to create regional conservation and load management institutions, such as the

power pools and NERC, to match conservation and

load management planning with regional transmission and generation planning. This is what has

happened in the Pacific Northwest as a result of the

1981 Northwest Power Planning Act.

Scenario 3: Competition for New Bulk Power

Supplies

From an environmental standpoint, there is probably more known about scenario 3 than some of the

others, because more thought and effort has gone

into it at both the Federal and State level. At least

seven States have implemented bidding systems of

some some sort.63 FERC has commissioned two environmental studies in connection with its notices of

proposed rulemaking (NOPRs) on competitive bidding and independent power producers. An environmental report done for FERC by Oak Ridge National

Laboratory before release of NOPRs identified

potentially significant environmental impacts from

the proposals, particularly increased use of coal in

four States, New York, New Jersey, Virginia, and

California. 64 As a result, FERC agreed to prepare a

full nationwide Environmental Impact Statement as

part of its rulemaking.

Scenario 3 offers some potential environmental

benefits, chiefly the prospect of more rapid replacement of the older plants with new plants, which are

likely to be less polluting. The scenario implicitly

assumes that ‘new” power will eventually drive out

‘‘old” because new, “competitively priced” generation will be cheaper and because old plants will

be phased out on some actuarial basis. But if the

guaranteed rate of return to the old plants, particularly those that are fully depreciated, exceeds the

return on investment available in the competitive

market, those assumptions may not hold, and old

plants may continue to be a problem.

@see Neil seidm~, ‘‘Garbage [n, Garbage OUL” Nor Man Apart, November-Deeember 1986, pp. 10-1 I, for an environmental critique of maw bum

projeets. The Institute for Imeal Self Rcliarrcc has a study of transmission and wasle-to-energy projecls currently underway.

bsco]or~o, M~nc, Mmsxhuxtts, NCW Jersey, New York, Texas, and Virginia.

64’’ Envlromenta] Report: Rcgulation,sGoverning Bidding progr~~”(D~ket No.RM8~.5-~)and $ ‘Regulations @vernhg Independent power

Producers (Docket No. RMlltl-4-000),” Oak Ridge National Laboratory, March 1988.
224 . Electric Power Wheeling and Dealing: Technological Considerations for Increasing Competition

One environmental issue will be whether and

how to treat plant geriatric work in the context of

bidding. If a utility is required to bid the added

supply associated with a particular life-extension

project, it starts with an asset owned by the

ratepayers. Even if fully depreciated, the plant would

still have a market value. If the market value of the

plant isn’t factored into the bid price, the utility

could reap a windfall profit from the life extension,

a further incentive to keep old plants on line. This is

similar to the problem posed by a deregulation

scheme that allows a utility to spin off its existing

plant into a deregulated subsidiary and then bid the

power from that plant against new construction in

the power auction. In both cases, it is necessary to

factor in the value of the existing asset in order to

avoid subsidizing older, presumably dirtier, plants.

TWO other environmental issues are particularly,

pertinent to the concepts of all source bidding to

supply utilities with power. The first is how to factor

environmental considerations into the bidding process, and the second is how to square the bidding

schemes (a supply-side issue with conservation and

load management demand-side issues). The second

issue may prove to be the most difficult to deal with,

although not insurmountable.

In the States that have addressed the bidding

schemes so far, environmental issues generally have

been treated as ‘nonprice” factors.65 Other nonprice

factors include such things as reliability, dispatchability, and fuel diversity. The difficulty with the

nonprice factors is that they introduce an element of

subjectivity to the selection of the winning bidder,

and take away from the auction aspects of the

bidding process. That means there will continue to

be a need for regulatory review to make sure that the

subjective judgments of the utility don’t adversely

bias the decisions. It is also possible that nonprice

factors will be given less emphasis than the more

easily quantifiable price elements in the bids.

In ca..es where there is a larger policy issue—such

as, for some, fuel diversity—the bidding process

might have to be altered somewhat to reflect this. In

New York, for example, Long Lake Energy Company, a hydro developer, suggested that, in view of

the public policy in favor of developing renewable

sources of energy, the State require separate requests

for proposals for renewable projects during the

bidding. Otherwise, the company said, a capitalintensive project such as hydro might not be

competitive on a price-only basis.66

One of the major considerations in any competitive scenario is the desire to establish a level playing

field for all competitors. From an environmental

perspective, an important consideration will be

whether all the players—utilities, IPPs, and QFs—

are required to meet the same high environmental

standards. 67

Building environmental concerns into a bidding

process as a subjective factor at least provides a

conceptual way to make sure that awards are

environmentally sound. But including conservation

and load management raises far more difficult

issues. So far, States have approached the problem

in different ways.

In New York, the State PSC adopted a staff

proposal to require utilities to establish bidding

auctions for demand-side management.68 An administrative law judge earlier had rejected the State PSC

staff proposal for “negawatt bidding,” in which a

purveyor of conservation and load management

could bid measures to reduce the utility’s consumption by the proposed supply increment, and ruled

that demand-side management not be included in the

same bidding process with supply auctions.69 The

judge cited the imperfect equivalence of demand

reductions and supply additions and the potential

loss of utility revenues. In Maine, demand-side

65s= tcstlmOny of Robefl J. J@gan, Commissioner, Mass~hu~tts~p~en~ of mblic Utilities, before the Senate Energy and Natura l

Resources Committee, Feb. 4, 1988, p. 8.

66ALJ Frank S, Robin~n, CaSC 29409, Recommended Deci.ston on Bidding, Avoided cost Bidding, Ud Open wheeling, p. 65.

671n i~ brief to tie New York ~blic SeWice Commission on mat State’s bidding m]emaking, ~~gc & RNkland Utilities MgWX! that ‘ ‘to h(id utilities

to higher environmental standards would provide IPPs with an unfair and possibly dcccptive economic advantage: customers could be receiving an

ostensible benefit in their utility bills. with a hidden cost to the Smtc’s environment. ” Robinson, supra note 66, p. 66.

bfJNew York State public Service Commi~$ion, Case 29409, Opinion No. 88-15, mim~, pp. 21-22.

@Robinson, supra nole 66, p. 53.
Chapter 7--Issues Associated With Increased Competition and Expanded Transmission Access ● 225

options were allowed to compete to provide needed

increments of electricity supply .70

FERC’s proposed rule on bidding under PURPA

does not provide for bidding of conservation and

load management. Economist Paul Joskow of the

Massachusetts Institute of Technology has argued

that FERC is correct to avoid the negawatt issue.

Including demand-side options in the FERC proposal, Joskow told a congressional subcommittee,

“could result in higher electricity rates, inequitable

electricity rates, windfall profits for some conservation suppliers, and incentives for inefficient conservation investments. ” But Ralph Cavanagh of the

Natural Resources Defense Council told the same

committee that omitting demand-side options from

the rulemaking would ‘‘exclude from power supply

competitions the least expensive resources available

to modern electricity systems. ”71

Despite the objections, demand-side bidding is a

powerful idea for stimulating energy conservation in

a market-oriented industry structure. More analytic

work, and perhaps some practical experiments, are

needed to test whether the barriers that critics raise

are real or fiction. Some suggest that negawatt

bidding can work by targeting specific loads for

reductions, such as motor efficiency, lighting, or

buildings.

Scenario 4: All Source Competition for All Bulk

Power Supplies With Generation Segregated

From Transmission and Distribution Services

Both scenario 4 and scenario 5 are considerably

further from the status quo than any of the predecessors. Consequently, trying to divine their environmental impacts is a speculative enterprise at best.

Nevertheless, several environmental questions present themselves with this full-fledged revolution in

the electric utility industry: the older plant problem,

how to build in environmental analysis, and the

problem of demand-side management.

Scenario 4 could present the most powerful

incentives yet to continue using older, dirtier plants.

If existing plants and life-extension projects can be

bid to supply generation on the same basis as other

sources, utilities will doubtless argue that since their

older plants are fully (or nearly) depreciated, they are

the low-cost bidders, ignoring the market value that

the plant possesses. The result is a powerful subsidy

for the fully amortized plant, even if a considerable

amount is spent in life extension. (There is a similar

problem in scenario 3.) This incentive could frustrate long-standing environmental goals, embodied

in statutes such as the Clean Air Act and the Clean

Water Act, of replacing aging, more polluting plants

with new, less polluting industrial plants.

One method of reducing the potential competitive

advantages of older plants is to structure the

transition to scenario 4 so that the market value of

the existing plant and equipment gets recognized in

the market price of power from those plants. After

all, one can make a powerful argument that it is the

public, in the form of the ratepayers, who own the

plant, since they paid for it.

One way to deal with this problem would be to

force newly segregated generating companies to bid

against others for ownership of the generating plants

of its integrated utility predecessor. Another alternative would credit or debit the utility’s rate base for

any difference between the net book value of the

asset and its sale price. The new owner would do the

geriatric work and use the refurbished unit to enter

the market.72

This scenario also faces the familiar problem of

how to factor environmental analysis into the

competitive process. Again, this is related to the

larger problem of older plants with less sophisticated

pollution control devices that likely would have a

cost advantage in bidding. A new plant, for example,

would have to obtain site approval and a host of

permits that would not burden the existing plant.

A new plant sited in a nonattainment area would

have to go over the costly LAER (lowest achievable

emission rate) hurdle, obtain pollution offsets, and

70 Maine public U(ilitlcs Commlxsloner David N40slcovitz would deal with the imperfect WUiVidenCe problem by tying a Utillty rate Of tKIUm to

relative reductions in the average bills paid by residential customers, and to reductions in electricity use per square foot by commercial customers. Thus,

the lost revenues from conservation would be offset by higher returns on the remaining business. Aviva Frcudman, ‘‘Moskovitz’s Modest Proposal:

Reward Utilities for Reducing Customers’ Bills,” Energy Daily, vol. 16, No, 72, Apr. 15, 1988, p. 1.

7i~mi~ wmst~, “NCgaWa(lS or Negafood? A Dcmand-Side Dichotomy, ” Energ)’ Dully, vO1. 16, No. ~~, Apr. 4! 1988* P“ 1“

72 Robin50n, supra nOte 66, P. 55.
226 . Electric Power Wheeling and Dealing: Technological Considerations for increasing Competition

the like. In an attainment area, the new plant would

have to go through the PSD process. An existing

plant competing against those new plants could

avoid any of those costs, as well as the high capital

costs of scrubbers, bag houses, precipitators, and the

like. It will require considerable regulatory ingenuity to figure out how to put the existing plant and new

plants on an environmentally level playing field in

this scenario.

Finally, there is the conundrum of how to carry on

conservation and demand-side management in an

economic environment that is almost completely

supply side. In a nonintegrated market, with generation separated from transmission and distribution. it

is not very clear just who will worry about conservation and reducing demand. The distribution companies or “discos” will be less concerned, because

they no longer face the risks of construction which

have driven much industry concern about demand

management. Potentially, discos will make money

only if they sell power and pass through the costs of

purchased power. If the equivalence between demand reduction and supply addition is imperfect in

scenario 3, it is even less so in scenario 4. Clearly,

the interest of the generating company (genco) will

be to generate and sell megawatts. The scenario

might also reduce pressure on State regulators to

push for conservation and demand management if

their retail ratesetting influence over wholesale

transactions is curtailed.

Scenario 5: Common Carrier Transmission

Services in a Disaggregate, Market-Oriented,

Electric Power Industry

In addition to the environmental issues raised with

regard to scenario 4, scenario 5 has some unique

environmental problem areas. The knotty issue of

conservation and load management becomes even

more intractable in a conventional sense. With

transmission companies (transcos) now in the market, making their money from selling transportation

services, another force has been removed from the

conservation and load management equation and

added to the supply ledger. Now only the regulated

distribution utility—probably serving a captive and

bypassed residential and small commercial market—

will have any incentive to push demand-side measures. And as long as the disco can buy power cheap

enough to make a reasonable rate of return on sales,

all incentive for conservation and load management

disappears.

Scenario 5 also raises the specter of reduced

maintenance of power generating equipment. In the

rush to compete, particularly if the competition

seriously drives down prices and profit margins,

generating companies may decided to cut costs by

skimping on maintenance. This can have disastrous

environmental and health consequences. In this

regard, the electric utility industry could come to

resemble the deregulated U.S. airline industry,

where the need to pay careful attention to costs has

increased pressures on the maintenance decisionmaking process.73

This issue is not present in prior scenarios,

because in each case, some strong institutional entity

remains with a vested interest in reliability and

maintenance. Even in scenario 4, the integrated

transmission-distribution companies have a need for

high reliability standards.

But in scenario 5, the only entity with an

overriding interest in reliability appears to be the

distribution company. For both the genco and the

transco, reliability becomes solely an economic

issue. Freed from its obligation to serve, if it makes

more economic sense to walk away from a market

than to continue to sell to it (as a result, for example,

of a poorly structured fuel supply contract or a

contract for transmission services that turns out to be

uneconomic), the genco probably will walk. If the

transco has an obligation to provide transmission

service, the company might meet that obligation

grudgingly.

There also is fear that the disco could become a

weak market player, bypassed by its biggest customers and left serving only a market that is economically fragmented but politically very powerful (i.e.,

a market that uses its political power to keep rates

low). In those circumstances, the disco may not have

enough clout to insist that its suppliers maintain their

plants even under adverse economic conditions.

73u.s. @n~CS~, Office of Wcholofl ASS~SSmen[, &@ ,$kieh~ fOr TO~rr~v: A}’iatlon ,$aft~’ in a Competitive Environment, OTA-SET-381

(Wmhington, DC: U.S. Government Printing Office, July 1988), p. 108.
Chapter 7--Issues Associated With Increased Competition and Expanded Transmission Access ● 227

Finally, the sort of industry structure envisioned in scenario 5 could result in a construction

boom for new transmission with an associated

increase in local siting battles,

Conclusions

Change is a given in the electric utility industry,

and most observers would agree on the general

direction of that change: toward greater competition

in the generation sector and away from the traditional pattern of the vertically integrated electric

utility. But as those changes appear, it will be

important to keep an eye on the environmental

impacts of the changed circumstances and conditions in the industry.

Neither expanded competition or increased transmission access is inherently incompatible with

national environmental objectives. Nor are arty of

the scenarios inherently preferable on environmental

grounds—at least, given our current level of understanding. However, as each scenario diverges further

from the status quo than its predecessor, assessing

environmental consequences become increasingly

difficult and problematic.

In all cases, environmental concerns will be an

important consideration in the policymaking that

will accompany the changes in the electric utility

industry. The OTA scenarios and other proposals

would have their most direct environmental effects

by affecting fuel choices and the generation mix,

potentially frustrating achievement of anti-pollution

goals and reducing incentives for development of

some renewable energy technologies. Implementation of consemation and load management programs

could be complicated and/or stalled by competitive

markets that focus only on supply-side options, An

increased demand for transmission services could

lead to more transmission line construction and

aggravate some already difficult disputes over transmission line siting. Based on OTA’s preliminary

review, there is little evidence that would support

blanket assertions that major structural or regulatory

changes in the electric power industry would be

environmentally neutral or benign.

HEALTH EFFECTS OF POWER

FREQUENCY FIELDS

For about two decades, there has been some

concern about the health effects of electric and

magnetic fields produced by electric power systems.

Recent studies have only intensified this concern.

One study in particular, the New York State Power

Lines Report generated headlines in newspapers all

over the world, focusing attention on the health

effects associated with living next to power lines.

Whatever the future direction of the electric power

industry, these concerns are likely to persist.74

The first evidence that electric and magnetic

power frequency fields might have a direct effect on

human health appeared in 1972 when Soviet investigators reported that workers in Soviet extra high

voltage (EHV) switchyards suffered from a number

of ailments, such as appetite loss, fatigue, headaches, insomnia, and reduced sexual drive. While

the Soviet research proved to have a number of

flaws, it served to stimulate public concern.

In the United States, most of the health effects

concerns have focused on fields generated by power

lines. In several States, health effects have become

a central issue in transmission line siting hearings.

By the end of December 1987, there were about

144,386 miles of transmission line (230 kV and

above) in the United States75 and thousands of miles

more under construction or being planned by utilities.

For many years, the scientific consensus was that

power frequency fields could pose no threat to

human health. Unlike x-rays that break chemical

bonds by ionization, or microwaves that heat things

up, power frequency fields are not powerful enough

to break chemical bonds in human cells or cause

significant tissue heating. Despite the low energy

level of power frequency fields, laboratory research

over the last 15 years has shown that even power

frequency fields of low intensity (or strength) can

disrupt certain processes at the cellular level.

T~Much of the information in ~ls ~tlon is dawn from ~ (_JTA ~on~ra~[or rcp~fl, by lrr~ira Nair, M. @mger Morgan, ~d H. Keith F!orig,

Carnegie-Mellon University, Department of Engineering and Public Pol]cy, “Power-Frequency Electric and Magnetic Fields—Exposure, Effects,

Research, and Regulation, ” Jan. 16, 1989.

T5NERC, ]988Elecplc@ s~pl~ Urui Demand for 1988 -]997, @lobCr 19g& p. 63.
228 . Electric Power Wheeling and Dealing: Technological Considerations for Increasing Competition

The research results are complex and often

inconclusive. There have been many experiments

that have found no difference between biological

systems that have been exposed to fields and those

that have not. But the growing number of positive

findings have now clearly demonstrated that under

certain circumstances, even relatively weak fields

can produce changes at the cell level. Moreover, the

number and consistency of positive findings has

resulted in better experimental design and improved

control of the experimental process.

As recently as a few years ago, scientists were

making categorical statements that on the basis of all

available evidence there are no health hazards from

human exposure to power frequency fields. It is still

not possible to demonstrate that such effects do

exist, and it is important to remember that they may

not. However, the emerging evidence no longer

allows one to categorically assert that there are no

risks.

If fields do turn out to be a health risk, it is

unlikely that high-voltage transmission lines are the

only sources of concern. Power frequency fields are

also produced by distribution lines, household

wiring, appliances, and lighting fixtures. These

non-transmission sources are much more common

than transmission lines and could play a far greater

role in any public health problem.

There is, of course, no difference in the biological

effects of exposure to power frequency fields under

any of the scenarios discussed in chapter 3 or

elsewhere in the report. Expansion of transmission

systems in a manner that exposes more humans to

potential hazards from electric and magnetic fields

could occur under any scenario.

Sources and Nature of Electric and

Magnetic Fields

People are exposed daily to electric and magnetic

fields. In fact, electric and magnetic fields arise from

many natural sources. Processes in the atmosphere

produce large static electric fields at the surface of

the Earth, thunder clouds produce lightning, and the

Earth’s core produces a magnetic field which makes

navigation by compass possible. Electric and magnetic fields are also produced by high-voltage

transmission lines, low-voltage distribution lines,

building wiring, electric appliances, and light fixtures. This section focuses on the fields created by

power lines.

Power lines carry electric currents that alternate at

a frequency of 60 cycles per second (60 Hz). That is,

the current changes direction 60 times per second.

The alternating current produces electric and magnetic fields around the power lines. These electric

and magnetic fields, which oscillate at the same

frequency as the electricity in the lines, are called

power frequency fields. Power frequency electric

and magnetic fields are ‘‘extremely low frequency”

(ELF) fields. Other common electric and magnetic

fields produced by radio and television broadcasting

stations, for example, have higher frequencies than

power frequency fields.

The term “electric field” is merely a description

of the electric force that a charged object is capable

of exerting on other charges in its vicinity. The

intensity of the electric field is proportional to the

magnitude of its force. The electric fields of power

lines, wall wiring, and appliances are produced by

electrical charges that are ‘‘pumped’* onto the wires

by electrical generators. Similarly, “magnetic field”

is the term used to describe the magnetic force. The

magnitude of the magnetic fields around a currentcarrying wire is proportional to the amount of

current. Both electric and magnetic fields have

magnitude and direction. The electric field is measured in volts per meter (V/m) and the magnetic field

in ampere per meter, gauss, or tesla.

Unlike ionizing and microwave radiation, which

are forms of energy that travel distances from the

source, ELF fields diminish rapidly with distance

away from the source. Figures 7-2 and 7-3 show the

intensity-distance relationship for fields produced

by EHV transmission lines. Fields produced by

power lines are strongest right under the conductors.

The magnetic fields around many appliances are

stronger than those under either a transmission or

distribution line. However, magnetic fields produced by appliances typically fall off faster with

distance than do fields from other sources. This is

because appliances are less extended in space than

are long power lines.
Chapter 7-Issues Associated With Increased Competition and Expanded Transmission Access ● 229

Figure 7-2—Electric Field Intensity at Ground Level

v. Horizontal Distance From Three Common Sources

of Power Frequency Electric Fields

T-- J

Distance from source (meters)

Bands represent variation across individual sources in each

group.

SOURCE: Adapted from H.K. Florg, 1. Nair, and M.G. Morgan, Briefing Paper 1

Sources and Dosimetry of power Frequency Fields, Technical Report,

prepared for the Florida Department of Environmental Regulation under

DER Contract SP1 17, March 1987.

Shielding

Buildings and other large structures, fences, and

vegetation can provide appreciable shielding from

electric fields. Houses, for instance, diminish electric fields from nearby power lines by about 90

percent. 76 Also, electric fields can virtually be

eliminated by grounded shield wires or screens in

direct contact with the earth. Buried power lines

produce almost no electric fields above ground.

Unlike electric fields, magnetic fields easily pass

through most objects, including buildings, earth, and

people. Houses, trees, and most other objects do not

provide appreciable shielding from magnetic fields.

Only structures containing large amounts of ferrous

or special metals can shield magnetic fields.

Some have suggested that in the future, superconducting materials could be used to reduce exposures

to power frequency fields.77 In theory, superconducting materials could be used to carry large

Figure 7-3-Magnetic Field Intensity at Ground level

v. Horizontal Distance From Three Common Sources

of Power Frequency Magnetic Fields

1o,ooo —

1000

I

x

100

10

1

0.1 1

0.l ‘ l.0 ‘ 10 100 1000 J---

Distance from SOUrCe (meters)

Bands represent variation across individual sources in each

group.

SOURCE: Adapted from H.K. Florig, 1. Ntw, and M.G. Morgan, Br/ef@ Paper I;

Sources and Dowmetry of Power-Fre~ency Fmlds, Technical Report,

IXqXWad fof UM Fbnda Department of Environmental Regulation under

DER Contract SP1 17, March 1987.

quantities of power a.. direct current thus avoiding

the magnetic fields caused by rapidly alternating

current. But they would not eliminate all magnetic

fields-a static magnetic field would remain around

the superconducting line because all currents produce a magnetic field in their vicinity. Moreover, use

of superconductors could be prohibitively expensive

or unnecessary for this purpose.

How We Are Exposed To Power Frequency

Fields

The human body contains free electric charges,

largely in ion-rich fluids such as blood and lymph.

(There are also charges, although not entirely free,

on cell membranes.) The electric charges, within the

body, move in response to forces exerted by charges

and currents on appliances and nearby power lines.

The processes that produce these movements, or

76H.K. Flong, ‘Population Exposure 10 Power-Frequency Ficlds<onccpts, Components, and Confrol,” Ph.D. Thesis, Department of Engineering

and Public Policy, Carnegie-Mellon University, 1986.

ITSWerco&uL.tiviW Flash Report. “Do Overhead Transmission Line Health Risks Help SC,” p. 8.
230 ● Electric Power Wheeling and Dealing: Technological Considerations for Increasing Competition

body currents, are called electric and magnetic

induction.

Electric Induction—In electric induction,

charges on a power line or appliance attractor repel

the body’s free charges. Since body fluids are such

good conductors of electricity, charges in the body

move to the surface under the influence of this

electric force. For example, a positively charged

overhead transmission line induces negative charges

to flow to the surface of the upper part of the body.

Because power line charges alternate from positive

to negative many times each second, the charges

induced on the body surface alternate as well.

Negative charges induced on the upper part of the

body one instant flow into the lower part of the body

the next instant. Therefore, power-frequency electric

fields induce currents in the body as well as charges

on its surface. Figure 7-4 shows electric and

magnetic field strengths observed in common exposure settings.

Magnetic Induction-Magnetic fields are interrelated with electric fields. As noted earlier, alternating current produces magnetic fields which oscillate

with the current. The changing or alternating magnetic fields, in turn, produce electric fields, which

exert forces on the electrical charges contained in the

body. This process is called magnetic induction. The

currents induced in the body by magnetic fields are

greatest near the periphery of the body and smallest

at the center of the body. Because magnetic fields

have only recently become a human health concern,

data on the detailed distribution of magnetically

induced currents in humans and animals are quite

sparse compared to the information available on

electric induction.

The magnitude of surface charges and internal

body currents induced by power-frequency fields

depends on many factors. These include the magnitude of the charges and currents in the source, the

distance of the body from the source, the presence of

other objects that might shield or concentrate the

field, and body posture, shape, and orientation.

Consequently, induced surface charges and currents

are very different for different animals.

Contact Currents-In addition to electric and

magnetic induction, humans are exposed to contact

currents. Contact currents are the currents that flow

into the body when physical contact is made

between the body and a conducting object carrying

an induced voltage. Examples of contact current

exposure include contacts with the handle of a

refrigerator and with vehicles parked under a transmission line. Contact currents often produce high

current densities in the tissue near the point of

contact. Although contact currents result in some of

the most intense exposures, they are also among the

briefest, usually lasting only as long as it takes to

open the door of a car or refrigerator.

If a person touches a vehicle parked under a power

line, the body provides a path to the ground through

which the charge induced on the vehicle by the

power line’s electric field can flow. The magnitude

of the contact current depends on a number of

factors: local field intensity, the size and shape of the

contacted object, and how well-grounded the contacted object and the person are. The largest contact

currents are drawn by well-grounded persons who

touch large metal objects that are well-insulated

from the ground. Most common contact currents are

imperceptible. Under the right circumstances, however, contact currents can be annoying or even

painful. To protect the public from life-threatening

contact currents, the American National Standards

Institute (ANSI) has recommended that overhead

lines be designed so that contact currents from even

very large vehicles do not exceed 5 milliamps.78

(One milliamp is equal to one-thousandth of an

amp.) There is some concern that the ANSI limit is

too high because 5 milliamps is still above the

“let-go” threshold for some children. The “let-go”

threshold is the current above which a person loses

voluntary muscle control and cannot ‘‘let go” of a

gripped contact.

Exposure Parameters

While it is possible to measure fields and induced

currents to which people are exposed, scientists do

not know which, if any, aspect of the field can have

an impact on human health. For example, scientists

do not know whether to be concerned about field

strength, change in field strength overtime, currents

induced in the body, exposure duration, or some

other variable. For most known potential hazards,

78Am~ric~ N~OIMJ Stamimts Institute, National Electrical ,hfety Codt!S, 197’7.
Chapter 7-Issues Associated With increased Competition and Expanded Transmission Access . 231

Figure 7-4--Compariaon of Ranges of Electric and Magnetic Fields From Common Power Frequency Sources

Exposure S ituatio n

1 -On Row o f 600 k V - I I n e

2- I n house neer 600-k V I I n e

3-Car contact near 600 k V

4 -Appliance contac t

6-EIectric blanket

6-EIectric shaver

7 -Household backgroun d

8-Beneath distribution Iine

I

●

● ●

I

I

I I 1

EXposure situation

1 -On RoW of 600 k V -1 in e

2-1 n house near 600-k V I ine

3-Car contact near 600 k V

4-Appliance con tac t

6-EIectric blanket

6-EIectric shaver

7-Household background

0001 0.003 001 003 0 1 0.3 1 3 10 30

8-Beneath distribution Iine I 1 ~ o 0 3 1 0 3 10 30 100 3 0 0 1000

1

2

3

4

6

6

7

8

1

2

3

4

6

6

7

8

SOURCE: OTA adapted from Irrdra Naw, M. Grangar Morgan, and H. Keith Flong, Power Frequency ElachIc and Magnetic FMkls-Effects, Research and Regulanon, OTA contracw

EVXXT car~”~l~n Unlverslv, mWment Of Em-wing and PUblIC POIICY, final report, Jan. 16, 1969.

such as chemicals, one can safely assume that if ●

some of the agent is bad, more of it is worse. This

may not be the case with power frequency fields.

Biological experimental evidence about power fre-

●

quency fields suggests that the “more-is-worse”

assumption cannot always be justified.

Some suggested measures of the bioeffects of

power frequency fields include:

. Frequency and intensity ‘‘windows”- ●

biological effects are noted in specific narrow

ranges of field intensity and frequency.

Time thresholds—biological effects are observed only after several weeks of exposures.

Time “windows”—biological effects are noted

after long- and short-duration exposure periods.

In some studies of cells and tissues, the effect

is not observed immediately after exposure.

Rather, there appears to be a window in time in

which biochemical perturbation occurs.

Field threshold—biological effects appear only

when field strength exceeds some threshold

value.
232 ● Electric Power Wheeling and Dealing: Technological Considerations for Increasing Competition

Together these different measures of dose suggest

that one cannot make the assumption that dose is

proportional to field strength or to time spent in the

field.

Comparing Human Exposures From

Different Sources

Because scientists do not know what measure is

relevant in determining biological effect, comparisons cannot be made on the basis of relative

contributions to effective dose. Comparisons among

sources can be based only on those physical

quantities that are amenable to measurement or

theoretical estimates. These include electric quantities, such as induced surface charge and internal

currents, exposure duration, frequency of exposure,

and number of people exposed. Although the electric

quantities may not relate in any simple way to a

public health impact of a given source, scientists can

use them to get some idea of how similar or different

people’s exposures from various sources are.

Current Scientific Evidence on Biological

Effects of Power Frequency Fields

Most of what we know today about the effects of

exposure to power frequency fields comes from

three types of studies or experiments:

1.

2.

3.

Laboratory experiments that use animal or

human tissues or cell cultures exposed to

fields. These experiments are termed “in

vitro” (in glass).

Laboratory and field experiments that use

animals exposed to fields. These experiments

are termed 6’ in vivo” (in live state) experiments.

Epidemiological studies that observe the efffects of field exposures on human populations

at work (occupational studies) or at home

(residential studies).

Cell-Level Experiments

A considerable body of evidence has emerged that

points to the cell membrane (the membrane enveloping the cell) as the primary site of interaction

between ELF fields and the cell. 79 The cell’s

membrane serves as the boundary and maintains the

structural integrity of the cell. It is also responsible

for transmitting information arriving at its surface to

the cell interior so that appropriate life processes can

take place. The cell membrane is a highly selective

filter that maintains an unequal concentration of ions

(charged atoms) on either side and allows nutrients

to enter and waste products to leave the cell.

The ELF experiments on the cellular level concentrated on how some of the specific processes

governed by the membrane change as a result of

exposure. Some of the changes noted in the experiments include the modulation of calcium ion flows;

interference with DNA (deoxyribonucleic acid)

synthesis and RNA (ribonucleic acid) transcription;

interaction with the response of normal cells to

hormones and neurotransmitters; and interaction

with the biochemical kinetics of cancer cells.

The phenomenon most studied on the cellular

level is the flow of calcium ions across the cell

membrane when exposed to 60 Hz fields. Calcium is

present in the membrane structure and is released

when triggered by an appropriate signal. Calcium

flow regulates physiological processes such as

muscle contraction, egg fertilization, and cell division. The quantity and the rate of calcium ion

transport are important in this regulation. When

information in the form of an electrical or chemical

impulse arrives at the cell membrane, the membrane

binding and the permeability of calcium are altered

and calcium is released. The subsequent flow of

calcium across the membrane transfers information

to the interior of the cell. In addition to regulating

physiological processes, calcium flows activate

certain enzymes called protein kinases, which are

found on the surface of nerve cells. When activated

by the calcium changes, these enzymes cause actions

on other cell surface proteins that are important in

cell adhesion during development and growth. The

unusual behavior of calcium flow from cell membranes in brain tissue in vitro was the first clear,

reproducible effect of ELF fields observed in biological tissue.

Recent research has demonstrated unequivocally

that under certain circumstances, the membranes of

cells are sensitive to externally imposed low79W.R0 *Y, t ‘E]~@Orn8~Cti~ Fields, Q]! MCrnbr~e Amp[ifi~~ion, andc~cer Promotion,” paper presented al the National council on Radiation

Rotedon and Measurements Annual Meeting, National A&demy of Suicnecs, Wa*ingmn, DC’, 1986.
Chapter 7---Issues Associated With Increased Competition and Expanded Transmission Access ● 233

frequency electromagnetic fields, even when the

fields’ intensity is much weaker than the cell

membrane’s natural fields.80 Consequently, processes that are governed by the cell membrane, such

as a cell’s capacity to recognize other cells, may be

candidates for disruption by field exposure.

Also, ELF experiments have focused on chromosomal damage and interference with DNA synthesis

and RNA transcription. DNA and RNA are the

primary biomolecules in the cell. Nuclear DNA

carries the genetic code while the extranuclear RNA

transcribes the DNA command codes into proteins

for the physiological functioning of the cell. Wellstudied cancer-initiating agents, such as ionizing

radiation and chemicals, cause direct damage to

DNA by mutations. As noted earlier, ELF fields do

not have enough energy to break bonds or otherwise

disrupt the structure of DNA. However, research has

shown that exposure to fields may interfere with the

transcription patterns of RNA, resulting in the

production of structurally changed proteins. Protein

synthesis is a very complicated process, and experiments yield no simple interpretation about potential

ELF effects on the organism.

Several experiments have studied the effects of

ELF fields on endocrine tissue. From these experiments, it is impossible to draw any inference about

the effects of fields on the endocrine system in a

human or animal, other than to say that fields do

exert an action on endocrine tissue and endocrine

processes in vitro, and these effects, too, show

windows.

Also, ELF experiments on interaction with the

immune response of cells showed that field exposure

had no significant effects on immunological functions of normal or specifically immunized cells.

However, fields may affect cells already stimulated

by mutagens (agents that provoke an immune

response).

Several experiments have examined the effect of

ELF fields on cancer cells. One of the hypotheses

developed is that fields promote cancer formation or

cancer growth rather than initiate cancer. The fact

that ELF fields have not been known to cause

alterations in DNA structure, as discussed earlier, is

consistent with the observation that ELF fields do

not initiate cancer. However, it should be noted that

any potential relationship between field intensity

and the degree of promotion may be highly complex.

It is important to remember that even when effects

are demonstrated consistently on the cellular level in

laboratory experiments, it is difficult to predict

whether and how they will affect the whole organism. Processes in the cell are integrated through

complex mechanisms in the animal. When a cellular

process is perturbed by an external agent, such as an

ELF field, other processes may compensate for the

perturbation so that there is no overall disturbance to

the organism.

Another problem in deducing possible health

concerns from cell-level effects has been the lack of

a theoretical model to explain and understand these

potential effects. Although great strides have been

made in recent years, cell membrane biology is still

in its infancy. Until recently, there was not enough

understanding to even advance hypotheses about the

potential mechanisms by which ELF fields may

disturb healthy cell and organ functions. Hypotheses

are now being advanced but are still at a speculative

stage. Several decades of carefully designed experiments may be necessary before all the current pieces

of evidence fall into place in a coherent framework.

Moreover, many of the lessons learned from

environmental hazards, such as chemical agents

(PCB, vinyl chloride, benzene, etc.), or physical

agents (asbestos, ionizing radiation, etc.), cannot be

applied to ELF fields. The cell-level effects produced by ELF fields are complex and dependent on

a number of factors, such as frequency and field

strength, time pattern of exposure to the field, and

direction of the applied field. The effects also may

depend upon whether the field is a simple alternating

field or a pulsed field. Because of these complex

dependencies, ELF fields appear to be an agent for

which there is currently no known analog.

A summary of the results of a number of cell level

experiments is shown in table 7-4.

‘%V,R, Adey, “Tissue Interactions with Nonionbing Elcctromagnctk Fields,” Physmlogical Reviews, vol. 61, pp. 435-514, 1981; lkstimony

presented to the U.S. House of Representatives, Subcommittee on Water and Power Resources, “Hcidth Effects of Transmission Lines,” (M. 6, 1987;

W.R. Adey and A.F. Lawrence (eds.), Nonlinear Electro@amics in Biological .5ystems (New York, NY: Plenum Press, 1984).

89-137 - 89 - 9
234 ● Electric Power Wheeling and Dealing: Technological Considerations for Increasing Competition

Whole Animal Experiments

In addition to cell-level studies, whole animal

experiments have been conducted. Animal systems

have been examined under a range of electric and

magnetic field intensities and for varied exposures

and durations. The experiments involved many

different subjects, including rats, mice, miniature

swine, cows, guinea pigs, and chicken eggs.

Historically, animal experiments focused on general effects rather than on formulating and testing

hypotheses. Very early experiments were riddled

with problems of poor experimental design, leading

to artifacts in results. Moreover, animal studies with

statistically sufficient numbers are very expensive

and time-consuming. In the past 15 years, the quality

of health effects experiments has improved but has

not yet reached the hypothesis testing stage. Epidemiological studies have focused on a search for

cancer as the primary effect because of historical

observation rather than because cancer is the most

likely effect.

Whole animal and human experiments are reviewed under these categories of effects:

1.

2.

3.

4.

5.

General effects, such as detection, avoidance,

and behavior responses; development and

learning of animals; and moods of humans.

Effects on externally measured physical parameters, such as growth, birthweight, respiration, heartbeat rate, and temperature

rhythms.

Effects on specific biochemical such as hormones that are responsible for maintenance,

regulation, and control of general physiological and psychological functions; for response

to environmental stressors; for growth and

development; and, for triggering special responses such as sexual function, and fetal and

newborn nourishment.

Effects on circadian rhythms of animals and

humans,

Epidemiology of cancer, particularly leukemia

and brain cancer.

Table 7-4--A Summary of Results of Cellular Ievel Experiments:

Effects and Possible Significance

Experiment Effects noted Possible significance .

Calcium efflux from Efflux is dramatically changed Significance is not clear

cell membrane The change occurs only at but points up the possibility

(6 experiments) some frequency and intensity values, that effects of fields may

but not at others. not be such that “higher field

intensity is worse than lower.”

Chromosomal damage No chromosomal damage Does not cause the damage

(3 experiments) detectable. that usually initiates cancer.

DNA synthesis rate Rate change at low Extremely low AC magnetic fields

(1 experiment) magnetic field. as small as the Earth’s natural DC

field may affect cell process rates.

RNA transcription New proteins made by Fields may alter rates of

(1 experiment) the cell. Rate of primary cell processes.

transcription altered.

Cell response Modifications in Public health significance not

modifications: adrenal and bone tissue clear. Adrenal response

Response to: response to hormones. shows intensity windows. Bone

A: hormones tissue experiment points to membrane

(1 experiment) as site pf action

B: Neurotransmitters Phase shifts in the If true in humans, could

(1 experiment) periodicity of have implication for

secretion rhythms. psychological disorders,

C: Immune system Not clear that there are such as chronic depression

(5 experiments) significant effects except Implications not clear.

in special cases.

SOURCE: L Nair et al., Daparbnent of EngInaanng and Public Pohcy, C- Mallon Wwmmity, OTA contractor raport, ‘PowarFraquency Ewric and MagnatIc F*: Expoaure, Effects,

Raaaarch, and Regulation,” Jan. 16, 1989.
Chapter 7---Issues Associated With Increased Competition and Expanded Transmission Access . 235

A summary of the results of whole animal and

human experiments follows.

Detection, Behavior, Learning, and Avoidance

Responses in Animals—No general conclusions

could be gleaned from the experiments on general

effects except to note that there are central nervous

system effects which may be windowed even in the

whole animal.

Reproduction, Growth, and Development— Reproduction, growth, and development studies measure a wide range of factors, such as reproductive

behavior, prenatal viability; alterations in physical

parameters, gross malformations, and central nervous system development. Most of the studies attempting to examine developmental effects of ELF

field exposure have concluded that no overt defects

and malformations resulted from the exposure.

However, some studies have seen subtle effects and

the possibility of the existence of an effect remains

an open question.

Several studies have examined the effects of 60

Hz fields on bone growth and repair. Overall, these

studies showed that high-intensity electric fields do

not appear to have a strong effect on bone growth

and repair in rodents.

Central Nervous System Effects—Animal studies have indicated that ELF-central nervous system

interactions are very complex. Interactions may vary

with the background static fields present, the time of

day, and exposure duration. Studies have found that

developing nervous systems may be particularly

susceptible, and effects may be latent, manifested

only in specific situations or later in time. Also,

findings show that ELF fields are specific with

respect to regions of brain tissue affected. Whether

these findings have public health implications remains unclear.

Blood and Immune System Chemistry-The

experiments conducted on blood and immune system chemistry imply that there is no general or

overall immune system performance changes or

short-term endocrine system changes induced by

exposure to electric fields of a rather high intensity

over a duration of several months.

Circadian Systems of Animals and Humans—

The circadian timing system serves to synchronize

various physiological and biochemical processes

that have a daily cycle. Many aspects of the biology

of circadian and other timing systems are not yet

well understood. But, the last two decades have

brought considerable understanding of some of the

elements of the system. ELF experiments on the

effects of electric and magnetic fields on circadian

systems of man, primates, and lower animals indicate a definite effect on the periodicity of physiological functioning. It is not clear, however, whether such effects are deleterious or even long-lasting.

Dyssynchrony of the circadian system has been

associated with physiological and psychological

disorders. These disorders include altered sensitivity

to drugs and toxins and internal conflicts between

the timing of physiological processes of sleep, and

psychiatric disorders, including chronic depression.

Epidemiological Studies

Epidemiological studies have focused on the

association between exposure to ELF fields and

cancer in children and/or occupational cancer, These

studies have received the most attention in terms of

the public health consequences of exposure to ELF

fields. Because ELF fields are not known to cause

chromosomal damage, cancer promotion, as opposed to initiation, is most often cited as the role

ELF fields play in carcinogenesis. However, no

experiment or theory clearly proves that ELF fields

promote cancer or growth enhancement.

Exposure to ELF fields was first linked to cancer

by Wertheimer and Leeper in 1979. The authors

estimated the comparative magnitude of the magnetic field in the home by the surrogate measure of

wiring configurations. This landmark epidemiological study noted an association between childhood

cancer and homes that were classified as located near

“high current configuration” distribution lines that

were likely to produce stronger than average magnetic fields. In 1982, the cancer association issue

resurfaced again-this time in the workplace. The

New England Journal of Medicine published an

article on the effects of occupational exposure to 60

Hz fields. The article noted that power station

operators had 2.5 times the death rate from leukemia.

In addition, recent epidemiological studies have

begun to examine the incidence of certain cancers to

magnetic fields in the household environment.

These studies have created a growing need to

understand the various sources of magnetic fields in
236 ● Electric Power Wheeling and Dealing: Technological Considerations for Increasing Competition

the home, which include not only appliances and

house wiring, but also ground currents in plumbing,

gas lines, and steel girders.81 The latest and by far the

most thorough study was funded by the New York

State Power Lines Project.

Childhood Cancer—Five completed epidemiological studies have addressed the question of association between exposure to ELF fields and childhood

cancer. Three of the five studies found positive

results. (See table 7-5.)

The latest study, the New York State Power Lines

Project, expanded on the 1979 Wertheimer and

Leeper study, which involved children from the

Denver area. Both wire coding and actual measurement of fields in homes were used to characterize the

residential field environment. An analysis of the

total childhood cancers occurring in the Denver area

was also done and showed that Denver children

share the same overall risk as those in the National

Cancer Institute Surveillance, Epidemiology, and

End Results (SEER) Program. The study also

assessed other measures of potential field exposures,

such as electric heat and hot water use, the use of

heating pads and electric blankets by children and

pregnant women, and the total number of electric

appliances in the house. The general findings of the

study follow:

●

●

●

●

A 30-percent increase in risk (odds ratio= 1.31)

for all cancers was observed at high magnetic

fields (2.50+ milliGauss). The odds ratio did

not systematically increase or decrease with

field magnitudes, i.e., higher field ranges did

not always give a higher cancer risk.

Cancer subgroups were analyzed under the

categories: leukemia, lymphoma, brain tumors,

soft tumors, and ‘‘other cancers. ” All the

categories except leukemia showed odds ratios

of 1.3 to 1.6 at high (2.5 mG+) field exposures

only. Leukemia showed an odds ratio of 2.11

for the highest field class and 1.23 for the 1.00

to 2.49-mG field range.

The risk of cancer was not associated with

magnetic field values at residence of birth.

Higher electric fields did not show higher risk

. Results on the relationship of childhood cancer

to use of appliances, electric blankets, heated

water beds, and electric heat are mixed but

suggestive of a few trends. Electric blanket and

isolette exposures were associated with increased risk of all cancers, especially of the

brain and soft tissue, for isolette exposure.

Residential Exposure and Adult Cancer—Three

studies have examined the association between adult

cancer and exposure to ELF fields from nonoccupational sources. Wertheimer and Leeper were the first

to report an association between adult cancers and

residential wiring configurations. Four categories of

wiring configurations were used to characterize

residences in which subjects had lived for periods

from 3 to 10 years prior to the diagnosis of cancer.

The researchers found an association between cancers of the nervous system, uterus, and breast with a

systematically increasing risk for higher current

configurations.

The latest study carried out under the New York

State Power Lines Project found no association

between acute nonlymphocytic leukemia and residential wiring configuration and residential field

exposure. The studies do not provide enough evidence that residential field exposure increases the

risk of cancer.

Occupational Exposure and Adult Cance+

About 20 studies have examined the association

between cancer, particularly leukemia and brain

cancer, and occupational exposure to ELF fields.

Studies have been done using electrical worker

populations or ham radio operators in the United

States, England, Sweden, and New Zealand. The

results of all studies taken together indicate a small

positive association or no association.

Leukemia--Occupational studies of the association of ELF exposure and leukemia show that

electrical equipment assemblers and aluminum workers have the highest relative risk of all “electrical”

occupations. Uncertainties about the relative risk of

these two occupations, however, do exist. For

example, job classifications do not clearly indicate

actual occupational exposure to fields, and the

of cancer. studies did not take into consideration confounding

61 D,A. savjtz, Ca.e control ,$tJ@ Of C\Ji/&[J~ ~’u~-~r fJd ~.~(),~ur~ fO Elec/romgne/i(’Fir/d.$. TMnka] RcpotI 10 the Ncw York S[iUC power Lines

Project (Albany, NY: Health Research, Inc., 1987).
(&J

I

I

I

Table 7-5-Methodology and Results of Epidemiologic Studies of Childhood Cancer and Electromagnetic Field Exposure

Wertheimer & Leeper Fulton et al. Myers et al. Tomenius

(1979) (1980) (1985) (1986)

Geographic source . . . . . . . . . . . .Colorado

Case group:

Time period . . . . . . . . . . . . . . . . . .Deceased 1950-73

Diseases . . . . . . . . . . . . . . . . . . .All cancers

Age range . . . . . . . . . . . ........0 to 18

Size . . . . . . . . . . . . . . . . . . . . . . ..344 (491 dwellings)

Other criteria . . . . . . . . . . . . . . . . .Colorado birth certificates;

resided in Denver area,

1946-73

Control group:

Source . . . . . . . . . . . . . . . . . . . . . .Birth certificates

Matching . . . . . . . . . . . . . . . . . . . .Year of birth; some by county

Size ..344 (472 dwellings)

Other criteria 1. .Subsets formed based on

residence information

Exposure:

Definition . . . . . . . . . . . . . . . . . . . .Wiring configurations

(wire type, gauge, number,

proximity to home)

Range . . . . . . . . . . . . . . . . . . . . . .Up to 35 mG

Potential

confounders . . . . . . . . . . . . . . .Age of onset; sex; urbansuburban residence;

socioeconomic class; maternal

age; birth order;

traffic density

Positive association between

high-current configurations

and cancer; dose-response

gradient; consistent across

cancers

Results:

Rhode Island

onset 1964-78

Leukemia

o to 20

119 (200 dwellings)

Identified at Rhode Island

Hospital; residences up to

years before diagnosis

Birth certificates

Year of birth

240 (240 dwellings)

Only birth addresses

considered

Estimated exposure from

Colorado measurements,

divided into quartiles

NA

Year of birth; father’s

socioeconomic level;

age of onset

No association observed

between imputed exposure

and leukemia

Yorkshire (England)

Health District

Diagnosed 1970-79

All cancers

o to 14

376

Birth certificates

Time of birth,

near case’s birth address

501

Only birth addresses

considered

Calculated magnetic

fields from overhead

lines

0.002 to 16.8 mG

Age

No consistent tendency

for higher exposures

among cases

Stockholm County

Registered 1958-73

All tumors

O to 18

716 (1,172 dwellings)

Born and diagnosed in

Stockholm County

Birth certificates

Age, sex, and church district

716 (1,015 dwellings)

Birth and “diagnosis”

address in Stockholm

Electrical construction within

150 miles, including 200-kV lines;

SO-HZ magnetic fields near door

0.004 to 19 mG

Age, sex, church district

More electrical construction

within 150 miles of case homes;

more case homes

SOURCE. 1. Nalr et al , Department of Engineenng and Public Policy Carnqe Mellon Umversty. OTA ccmtractor report, “Power frequency Electncand Magnet!c Fields Expxure, Effect, Research, and Regulation,” Jan 16, 19E9.
238 . Electric Power Wheeling and Dealing: Technological Considerations for Increasing Competition

variables and household and other exposures. Studies show that the third highest relative risk grouptelegraph, radio, and radar operators, consistently

exhibit increased risk. The largest set of data is

available for this group.

Collectively, the studies do not provide sufficient

evidence that work-related exposures to powerfrequency electric and magnetic fields increases the

risk of leukemia or brain cancer. However, there is

sufficient evidence to warrant more detailed and

finely focused research on this question.

Brain and Central Nervous System Tumor-The

association between brain and central nervous system tumors and ELF field exposure related to

occupation has been examined in a number of

studies, some of which are general cancer studies.

Brain cancer in adults is rare (1 percent of all cancer

incidence; 5 in 100,000 risk), peaking at about 60

years of age. In comparison, brain cancer is the

second highest risk cancer for children between O to

8 years of age.

The small number of occurrences of brain cancers

in adults poses a data problem in establishing causal

association. Also, the brain is a favored site for

metastasis. 82Therefore, cases counted as Primary

brain cancer may actually be secondaries spreading

from a different organ where the cancer actually

initiated.

In addition to the data problem mentioned above,

the studies used occupational classification-based

data to estimate exposure. Data are classified by job

titles or general occupation codes, such as “electrical occupations. ” The problem arises when a

general occupation code includes workers who are

no more exposed to ELF fields than the average

individual. For example, in some cases “electrical

occupations “ include electrical and telecommunications engineers. Even electricians often work with

circuits turned off so that their exposures may not be

significantly higher than those not in the electrical

field.

Major Programs and Funding Levels for

Health Effects Research

Over the years, funding for research on the effects

of power frequency fields has fluctuated. Current

levels of support are only modest. Over the past

decade, the Department of Energy (DOE) has been

the chief source of Federal funding. DOE’s fiscal

year 1988 budget for ELF research was $2.2 million,

a substantial decrease from a high of $4.7 million in

fiscal year 1985. The proposed budget for fiscal year

1989 is higher at $3.0 million.83 The Bonneville

Power Authority (BPA), a Federal power marketing

agency, also has supported research. In the past

decade, BPA has provided about $200,000 per year,

primarily for environmental and livestock studies. A

history of the research funding provided by the six

largest programs is shown in figure 7-5.

The U.S. Navy played an important and early role

in research on the effects of exposure to ELF electric

and magnetic fields. In 1968, the Navy proposed to

build an ELF submarine communications facility in

northern Wisconsin that would have covered many

thousands of square miles. In response to concerns

raised by people in Wisconsin and to comply with

the recently enacted National Environmental Policy

Act, the Navy launched a large laboratory research

program that examined the effects of ELF exposures

on many animal and plant species.84 Between 1969

and 1977, the Navy funded about 8 million dollars’

worth of research. It now has two operating ELF

transmitting facilities, one in Wisconsin and one in

Michigan. The Navy has continued to sponsor

ecological field studies in the vicinity of these

transmitters. Navy funding for this program is

currently about $2 million per year.85

At one time, several laboratories of the Environmental Protection Agency (EPA) had small research

programs involved in both exposure and effectsrelated studies. Because of recent budgetary pressures, EPA’s work on ELF fields has essentially

stopped. 86

gzMei~t~is refers to ~Ond~Y growth of cancer that spreads from ~ primary site.

831, Gyuk,us,Dep~ent of Energy, Washington, DC, personal communication, NOV. ZZS lg~~.

R4’T.c. RO~ell, “BIO]OglCal Research for Extremely low Frequency Communications sYWmS,” Biologic and Clinical Effects of Low-Frequency

Magnetic and Electric Fields (Springfield, IL: Charles C. Thomas, 1974), ch. 7, pp. 91-97.

S5M.M, Abmmavage, ITT Research lnstitutc, personal communication, @tobcr 1987.

BbBi~l~~omagne~iCS Society, ‘‘Bioclearomagnctics Funding Survey, “ Bioelectromqnetics Society Newsletter, May/June 1986.
Chapter 7---Issues Associated With Increased Competition and Expanded Transmission Access ● 239

Figure 7-5-History of Funding for ELF Bioeffects

Studies in the United States From 1986 to the Present

5

4

3

2

1

0

7890123456 78901234567 8

1

9

6 0 s

*

1

’

7 0 s

~

1

’80’ ~

Year

solURCES: M.M. Abromavaga, Ergneering Mwsor, IIT Research lnatltne, Washqton, DC, prsonal commumcation, October 1987; Bioelactromagnetns

Society, Bmlectromagnatics FunctI~ Survey, Biodactrorrragnatics .%x.

efy Akmvsk?ffar (68), May/June 1986; 1. Gyuk, US Department of Energy,

Washington, DC, personal communication, Dwxmber 1988; “DOE EMF

Bodbcts Budget Set at $3 Milhon,’” Microwave Aws8(5):8, September/

October 1988; and S. !%ssman, Manager, Non-lomzing f?ediatm Subpro

gram, Environment Dwiwn, Electric Powwr Research Irrstttite, Palo Alto,

CA, personal communtcatmn, Daxmber 1988.

State agencies have also funded research. From

1982 to 1986, the State of New York operated a $5

million research project on field effects. The project—

the New York State Power Lines Project-was

administered by the New York Department of Public

Health, with money provided largely by the State’s

electric utilities. Another useful but smaller Statefunded program is the Maryland Power Plant Siting

Program, which has supported database development and dosimetric studies at the Johns Hopkins

Applied Physics Laboratory. In addition, the California Public Utilities Commission with assistance

from the Department of Health Services (DHS) is

currently reviewing and summarizing electric and

magnetic fields research and related biological

theories. DHS expects a report to be issued in

September 1989. After the report is released and data

gaps identified, DHS will launch a 3-year, $2-

million electric and magnetic fields research program, which will be funded by a one-time utility

tax.87

In addition to Federal and State Governments’

support, the electric utility industry has been involved in supporting research on ELF fields effects.

Utility support began as early as 1962 when the

American Electric Power Company (AEP) funded

two small-scale studies at Johns Hopkins University. One study focused on EHV lineworkers and the

other on mice exposed to strong electric fields. AEP,

several years earlier, had become the first U.S. utility

to build an EHV transmission line. Several other

utilities, most notably Southern California Edison,

have initiated fields research programs. Together,

utility sources have provided about $3 million in

funding over the last decade.

The Electric Power Research Institute (EPRI), the

utility industry’s research arm, has spent $15 million

on such research over the past decade and has

increased its support annually. EPRI’s 1989 budget

targets about $5.5 million on electric and magnetic

fields research.88 The Institute is currently sponsoring ELF research on statistical studies of human

disease patterns, measurements of actual human

exposure, and laboratory studies on animals and

cells. 89

International Programs

Many nations have active fields research programs. These include Sweden, West Germany,

United Kingdom, Canada, Japan, Italy, France,

Finland, and Norway.

87Pcrso~a] communica~ion wi~ Dr. Raymond Neutra, Chief Epidemiological Studies Section, California Department Of Health ScrviCeS, Mar. 14.

1989.

sRDr, Ro&fl Black, EPRI, personal communication, NOV. 30, 1988.

6~EpRI 1987 Annual Report, “Tcchnoiogical lnnovaiions: Window to Economic Pmspcrity,” p. 16.
240 ● Electric Power Wheeling and Dealing: Technological Considerations for Increasing Competition

Sweden’s research program has a budget of

$1.9 million (11 million krona). Health officials

have already embarked on a large-scale epidemiological study of people who have developed certain

types of cancer and who lived within 300 meters of

a 220- or 400-kV power line for at least 1 year

between 1960 and 1983. Funding is provided

primarily by Sweden’s State Power Board and

Sweden’s National Institute of Occupational Health.

Studies have focused on epidemiology, exposure

assessment, and cancer induction and promotion.90

In the past decade, the United Kingdom has spent

about $6 million investigating the biological effects

from its high-voltage overhead transmission grid.

After a decline in funding over the past few years,

Britain’s Central Electricity Generating Board (CEGB)

now plans to double its research budget. This

increase in funding was prompted by findings of the

New York State Power Lines project. British scientists expect to spend about $2 million this year. The

CEGB plans to measure the domestic exposure of

every child who has contracted cancer in Britain in

the past year or two. British research will use a range

of new instrumentation that will permit precise

measurement of electric and magnetic exposure and

will deal with a domestic technology that differs

significantly from the United States system. Where

the United Kingdom differs from the United States

is that far more of the local distribution system is

buried instead of dangling from poles. Underground

cables are twisted together in a way that tends to

cancel out their fields. In addition to dose measurements, CEGB scientists will commission medical

surveys from university statisticians to correlate

with the measurements.9l

The West Germans are currently funding a

half-dozen projects that include animal teratology

experiments, in vitro studies, and measurements of

human exposure. Financial support is provided by

both public and private sources.

Canadian utilities, Ontario Hydro and Hydro

Quebec, have been actively involved in exposurerelated research for some time and have recently

begun an animal cancer study. They also have active

programs in high-voltage DC field and ion effects.

Japanese utilities have underwritten a number of

studies of electric field dosimetry over the last few

years and funded a study at Southwest Research

Institute on the effects of electric fields on baboon

behavior. Italy’s programs are entirely utility funded

and include electric field studies with chickens and

rodents,

Strategies for Research

At the same time as scientific developments have

prompted many to conclude that the issue of possible

60 Hz health risks should be taken seriously, there

has been a marked decrease in the level of Federal

funding for ELF effects research. The reductions in

funding do not, however, appear to be a deliberate

effort to reduce fields research but rather a byproduct

of efforts to limit the level of overall Federal

expenditures.

While current research is sufficient to raise

serious concerns about ELF field health effects, it is

not sufficient to provide satisfactory answers or to

point the way to action. Without adequate research

on which to base answers, the vigorous public debate

on ELF health effects, and in some instances

intervention and litigation, could go on for many

years and have costs significantly greater than the

costs of the needed research.

Beyond the issue of funding levels, several

research management issues need to be examined

when addressing the potential health effects of ELF

fields. An overall ELF research program should

include a balanced mix of cell-level, whole animal,

and epidemiological studies. No one study is likely

to lead to the kind of complete understanding that is

necessary to make informed judgments about risk

assessment and management. While epidemiological studies may be able to establish an association

between health impacts and humans, cell and animal

studies would have to demonstrate the mechanisms,

and other features, of the effects. The identification

of dose-response mechanisms is essential for the

development of effective risk management strategies.

Also, there is a danger of becoming too focused on

cancer promotion as a single health effect of

~echnology Review, “Power Lines and Cancer: The Evidence Is Growing,’” October 1987.

glDavid FisM~k, “&ilain will Double h Budget for Research Into Elcctrornagnclic Fields,” Energy Daily, vol. 16, No. 61, Mar. 30, 1988, p. 3.
Chapter 7--Issues Associated With increased Competition and Expanded Transmission Access ● 241

concern. The breadth of cell-level and animal

experiments suggest that other public health effects

deserve some attention.

Furthermore, little attention has been given to

field exposures that result from sources other than

high-voltage transmission lines. As noted earlier,

fields from distribution lines, building wiring, and

appliances could be primary sources of public health

effects. It will be important for legislators, regulators, and others to address the issue as one of field

exposure rather than as a problem of high-voltage

transmission lines. Otherwise, enormous attention

may be devoted to one, possibly minor, source of

public exposure while ignoring other, possibly

major, sources of public exposure. A systematic

characterization of the entire low-frequency field

environment to which people are exposed in normal

modem life would be useful to this end.

Finally, little or no research has been done on

exploring techniques for reducing or eliminating 60

Hz field exposures. Preliminary work conducted by

Carnegie-Mellon University suggests that in many

cases solutions may be possible at economically

reasonable levels. For example, a low-field electric

blanket might be designed by using concentric

conductors in the heating elements, by using twisted

pair heating elements, or by using heating fluid. A

series of carefully conducted studies designed to

explore the technical and economic feasibility of

reducing field exposure, is needed.

ELF Exposure and Regulatory Activity

In recent years, States have experienced increasing pressure to take regulatory action to protect

citizens against the possible hazards posed by power

frequency fields. Major transmission line projects in

New York, Montana, and Florida, for example, have

encountered considerable public opposition based in

part on concerns over possible health effects. In

several instances citizens have carried these disputes

into the courts. In response to these pressures, States

have taken a number of approaches to regulate

exposures to electric and magnetic fields.

By January 1989, seven States had already set

limits on the intensity of electric fields around power

lines. A brief summary of the existing field limits is

shown in table 7-6.

Officials in Florida have adopted standards to

limit the amount of both electric and magnetic fields

that new power lines generate. Florida is the first

State to restrict magnetic fields around transmission

lines. The final maximum edge of right-of-way

magnetic field strength limits for new transmission

lines are 200 mG for 500-kV lines, 250 mG for

double-circuit 500-kV lines, and 150 mG for 230-kV

and smaller lines.92

Starting in July 1988, Ohio utilities applying for

approval of a new transmission line must first submit

calculations of electromagnetic field strength of the

proposed line. Predicted field strengths must be

made for the edge of the right-of-way for the line and

at the fence line for substations. However, according

to the Ohio Power Siting Board, not much will be

done with the calculations until a national consensus

is formed.93

To date, most of the pressures are directed toward

the control of transmission lines. It is likely that

similar pressures will increase for distribution lines—

at least for those lines that are visible. On the other

hand, pressures to control fields associated with

building wiring and appliances are likely to increase

more slowly.

Legislators and regulators have been dealing with

known or suspected health risks from environmental

agents for decades. However, data on exposure to

ELF fields is even more complex and uncertain than

evidence compiled for other hazards such as toxic

chemicals and ionizing radiation. Because of the

complexity of the interactions between power frequency fields and living cells, conventional legislative and regulatory strategies that focus on setting

‘‘safe” or “acceptable” exposure thresholds may

not lead to effective results for the possible risks.

The experimental evidence that finds a windowing

of observable effects and the presence of effects at

very low-field strengths makes reliance on conventional threshold approaches probably inappropriate

and unsupportable by available scientific data.

gz’’~orida EnvironmCnl~]RCgul~lorS Set NCW Elcctromagnctic Field Limits, ” Electrlc Utihh Week, Jan, 30, 1989, pp. 1-3.

gg’’For New Lines, Ohio Uti]ilics Told to Submit Data on Field Strcng~hs, ” Eleclri( Utiltty Week, May 23, 1988, pp. 19-20.
242 ● Electric Power Wheeling and Dealing: Technological Considerations for Increasing Competition

Table 7-State Regulations That Limit Field

Strengths on Transmission Line Rights-of-Way (RoW)

State Field limit

Montana. . . . . . . . . . . 1 kV/m at edge of RoW in residential

areas

Minnesota . . . . . . . . . 8 kV/m maximum in RoW

New Jersey . . . . . . . . 3 kV/m at edge of RoW

New York . . . . . . . . . . 1.6 kV/m at edge of RoW

North DakOta . . . . . . . 9 kV/m maximum in RoW

Oregon . . . . . . . . . . . . 9 kV/m maximum in RoW

10 kV/m maximum for 500-kV lines

2 kV/m maximum for 500-kV lines at edge

of RoW

8 kV/m maximum for 230-kV and smaller

lines in RoW

2 kV/m maximum for 230-kV and smaller

lines at edge of RoW

Florida . . . . . . . . . . . . 200 mG for 500-kV lines at edge of RoW

250 mG for double circuit 500-kV lines at

edge of RoW

150 mG for 230-kV and smaller lines at

edae of RoW

SOURCE: 1. Nair et al., Department of Engineering and pubhc Policy, Carnegie Mellon

UniWrsity, OTA contractor report, “P~r-trequerrcy Electric and Magnetic

Fields: Exposure, Etfacts, Research, and Regulation, Jan. 16, 1989.

Three important limits need to be considered in

policy choices. First and foremost, it has not been

conclusively proven that ELF fields do pose a health

hazard. Second, it is possible that no straightforward

dose-response relationship exists between the degree of exposure and the level of harm, thus reducing

the effectiveness of traditional standards approaches

to risk management. Finally, there are many potential sources of ELF exposure and transmission and

distribution lines may not in fact pose the greatest

threats. In the future, better scientific understanding

may clearly demonstrate the existence of adverse

public health effects from ELF field exposure from

transmission and distribution lines and suggest

specific risk management strategies. But, for now,

we have to operate with admittedly imperfect

response strategies. Possible policy responses include the following:

●

●

●

●

●

Deferring regulatory action while continuing

and expanding research to resolve scientific

uncertainties.

Establishing public information programs.

Adopting a field strength-limit approach to

transmission line fields by setting an arbitrary

‘‘acceptable level of exposure even though

not fully supported by scientific evidence.

Adopting a “similarity” based approach to

transmission line fields designed to make

people’s exposures to transmission line fields

as ‘‘similar” as possible to the exposures from

all the other fields common in our daily lives.

Adopting a “prudent avoidance” strategy by

taking reasonable steps at modest costs to keep

people out of fields in the siting and re-routing

of transmission and distribution lines and by

redesigning electrical systems to reduce fields.
Chapter 8

Public Policy Issues and

Legislative Strategies
CONTENTS

Page

TECHNICAL CONSIDERATIONS--POLICY OPTIONS AND ISSUES. . . . . . . . . . . . 245

Enhancing and Preserving Reliability and Economy in a More Competitive

Incustry. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .......... 245

Creating a Stronger and More Flexible Transmission Network To Accommodate

Industry Change and National Needs.... .. .. .. .. .. .. ... ... .... . . . . . . . . . . . . 250

EXPANDING COMPETITION IN THE ELECTRIC POWER INDUSTRY—

INSTITUTIONAL AND POLICY ISSUES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 252

Enhancing Bulk Power Competition. . . . . . . . . . . . . . . . . . . . . . . . . . ... . . . . . . . . . . 252

Restoring a Balance in Federal and State Regulatory Jurisdiction—

Legislative Issues . . . . . . . . . . . . . . .. 0 . . . . . . . . . . . . . . . . . . . . . . . . . . . . ... 256

Alternatives to Competition for Achieving Reliability and Economy . . . . . . . . . . . . . . . 258

Impacts on Other Public Policy Goals . . . . . . . . . . . . . . . . . . . . . . . . . .. .. . ~ . . . . . . . . . . . 258

Better Information and Analysis for public Decisionmaking. . . . . . . . . . . . . . . . . . . . . . 258

Power Frequency Fields and Public Health . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 259
Chapter 8

Public Policy Issues and Legislative Strategies

This chapter provides a broad overview of a

number of the public policy issues and potential

legislative responses associated with creating a more

competitive electric power industry. The policy

options in this chapter are aimed at the general

technical and institutional changes that may be

required to expand competition among potential

suppliers of electric power, including increasing

access to transmission services, and not at the direct

implementation of the scenarios used in OTA’s

analysis.

This policy discussion targets three areas of

potential congressional concern. The first area

includes the key technical and institutional changes

that must occur to assure that the reliability and

economy of operation of the bulk power systems do

not suffer in any competitive transition. The chief

responsibility for assuring their successful implementation will rest on the electric power industry,

including new competitive generators. While regulators and legislators will be directly involved in the

initial decisions on what competitive changes will

be adopted, they have only an indirect role in

implementation and system operations. Nevertheless, there are a range of actions that can be taken to

encourage a smooth transition.

The second area of concern embraces the broad

public policy questions that will be central to any

debate over fundamental changes in the regulation of

electric utilities and bulk power markets:

. encouraging broader market participation,

. expanding transmission access,

. changing existing Federal laws and regulations,

and

. establishing an appropriate balance in Federal

and State regulation of electric power.

A range of alternative legislative strategies are

identified for each.

The third area of congressional concern is the lack

of information, analysis, and experience to support

decisionmaking about electric power industry structure and regulation. Notable areas where additional

research and information are needed are bulk power

markets, transmission system capabilities, the potential efficiency gains from expanded competition,

and the availability of other alternatives to achieve

similar efficiency gains. Related areas that also merit

further investigation are the impacts of competition

on other Federal energy and environmental goals.

Finally, we include some possible legislative responses to the possibility raised by recent scientific

studies that exposure to power frequency fields may

pose a human health hazard.

TECHNICAL CONSIDERATIONS—

POLICY OPTIONS AND ISSUES

Enhancing and Preserving Reliability and

Economy in a More Competitive Industry

A fundamental goal of the regulated electric

power system has been to maintain reliability of the

system while providing economical service. Any

shift to a more competitive industry structure would

not alter this goal, but its achievement would depend

on successfully continuing coordinated planning

and operation of the bulk power system.

The bulk power system consists of generation and

transmission resources that are planned and operated

together in a coordinated fashion. Currently most

generation and transmission facilities are integrated

either because they are both owned and controlled by

the same vertically integrated utility or they are tied

together through a local control area. Competitive

trends are already modifying that traditional model.

The system today already has absorbed a significant

increase in bulk power transfers and the entry of

nonutility generators—mostly qualified cogenerators and small power producers. The terms and

conditions for the transactions that have driven these

incremental changes were largely dictated by the

integrated utilities and power pools. It is not at all

clear, however, whether more extensive or rapid

changes can be as easily accommodated and whether

effective system operating arrangements will evolve

to adequately protect reliability.

Increasing bulk supply competition and expanding transmission acccess will generally involve a

separation or unbundling of the ownership and/or

operation of generation and transmission facilities.

-245-
246 ● Electric Power Wheeling and Dealing: Technological Considerations for Increasing Competition

The extent could range from modest changes, as in

scenarios 1 and 2, to more extensive long-term

industry restructuring, as in scenarios 3,4, and 5. As

long as competitive generation’ makes up only a

small portion of the generating resources in an

integrated system, most control and coordination

problems posed by these alternative suppliers should

not be serious and can be handled by available

technologies and operating procedures. With more

and more new utility and nonutility generators

supplying bulk power to the system, however, the

degree of separation in operation and ownership will

grow and direct utility control could potentially

decrease. As the portion of the generating base not

directly under utility operation grows, maintaining

effective coordination of planning and operations

will become more complex, but not impossible.

Similar difficulties arise as the number of wheeling

transactions increase—because the bulk systems

operations center has less direct control over the

generators pushing power onto the lines. For the

system to function reliably and effectively, some

entity must coordinate the individual generation and

transmission components. Under all scenarios, but

especially scenarios 2 through 5, this may require

additional agreements and operating guidelines, and

in some instances, creation of new institutions and

operating relationships that would include nonutility buyers and sellers in the cooperative efforts.

Meeting the Technical Requirements for

a More Competitive Generating Sector

It is possible that as competition assumes a greater

role in the generation sector the number and

diversity of electric power producers will increase.

With such a change would come greater technical

and institutional challenges in meeting the three

main requirements for coordinating the bulk power

system:

1. adjusting generator output to follow load

changes;

2. maintaining reliable operations; and

3. coordinating power transactions among interconnected systems.

Effective generation control and coordination for the

expanded competitive system as a whole will be

achieved through some combination of equipment

and operating agreements, contractual obligations,

and other subsidiary arrangements.

Generation Control for Load Following-Control

centers and generators must establish operating

agreements and maintain the equipment necessary to

follow moment-to-moment fluctuations in load.

This frequency regulation equipment includes the

central automatic generation control systems, governors on the generators, and metering, communication, and accounting equipment to measure generator performance under an agreement to provide load

following service. Responsibility for load following

can be assigned in contracts and coordination

agreements. For nondispatchable units, arrangements might be made to provide and compensate for

these services by either reducing the amount paid to

the generator or assessing a share of the associated

system costs.

An integrated system also requires that generating

units be scheduled to follow daily, weekly, and

seasonal load cycles. A control center for an

integrated utility or a tight power pool usually

follows a previously established unit commitment

schedule and ramps up or down the individual

generating units as needed to follow actual or

predicted loads. Schedules are usually set to achieve

the best economic dispatch of available units.

Because off-peak loads may be only 50 percent or

less of peak loads, systems require a large fraction of

schedulable generation to be able to follow daily,

weekly, and seasonal load variations. Some units,

such as nuclear plants and large fossil-fired steam

turbines, are used to meet fairly constant or base

loads and are considered “noncycling.” A firm

power sale committing the output of a specific

generating unit to serve a specified wholesale or

retail customer, which might be a typical bulk power

transaction under a more openly competitive system,

could be considered as a noncycling unit for load

following.

As the amount of noncycling or nonscheduled

generation in a system increases, both the difficulties

of providing cyclical load following and the economic costs of doing so can increase. Potentially, the

IBY $$comwtilivc generation “ we mean bulk power obtained through a compe(i[ivc procurement process from a generator that is not owned and

operated direcdy by the purchasing utility. The supplier could be another utlh[y {or a suhsidiuy or affiliate), a P[JRPA qualified facility, or an

independent power producer.
Chapter 8-Public Policy Issues and Legislative Strategies ● 247

burdens of system support could fall heavily on the

utility controlling the system and its generating

units. Under a competitive system where generators

are paid only for the electricity they generate, some

mechanism must be in place to encourage competitive suppliers to follow load cycles since it may

require operating their facilities below capacity.

This will require the negotiation of specific agreements for dispatch and scheduling control for load

following, the establishment of compensation

schemes or preferences for load following competitive suppliers, and the assessment of load cycling

system charges for nonparticipating generators.

Generation Control and Reliability-Control

over generation is also needed to schedule and

control power flows between interconnected systems. This is essential to minimize the potential for

unintended power exchanges on transmission lines

between systems.

All interconnected generating units must be under

some coordinated control for security in case of

emergencies. The type of control required to prevent

bulk system failures is more immediate than that

used for load following. Agreements are also needed

to resolve system engineering problems and to

maintain system operations within stability limits.

Maintaining spinning reserves and “ready reserves ”2

as substitute power supplies in case of

emergencies is necessary for system reliability and

security. To meet this obligation the system maintains generating units that are operating or standing

by to provide needed power on short notice. In a

competitive generating sector, the costs and responsibilities for maintaining system reserves may need

to be reallocated.

Legislative and Regulatory Initiatives-The responsibility for establishing an adequate technical

framework to support a more competitive generating

sector will largely fall on the electric utilities, the

competitive generators, and the industry’s various

voluntary and professional associations. And a

successful transition will depend on their cooperative efforts. There are, however, a few areas where

Federal and State legislators and regulators can

further the technical and institutional changes

needed to assure adequate system coordination. The

first area for possible government action is improving information gathering and research to support a

competitive industry structure. A few State regulatory agencies and utilities are already jointly pursuing these changes. They are still a minority, however.

Although there already has been some experience

with integrating competitive supplies into utility

systems, most of these transactions have been on a

small scale. Unbundling generation and bulk power

system support functions will require development

of new standards, data collection practices, and

analytical methods that are acceptable to all or most

participants. Much can be done using existing

technology and methods and adapting them to a new

operating environment. Perhaps the primary areas

where additional information and research are

needed to establish a firm technical foundation for a

more competitive electric generation sector are: a)

coordinated operations, and b) coordinated planning.

Most utilities support integrated system operations by allowing their generating units to be

dispatched to follow loads and maintain reliability.

In a more competitive bulk power market, not all

generators may be willing or able to follow loads.

This could result in an unbundling of generation

functions and of the responsibilities for providing

them. This raises issues of how to maintain coordination and how to apportion system support cost

equitably. If competitive generators agree to allow

their plants to be dispatched and/or scheduled

cyclically, the control center will need detailed cost

and operating information for the units, Appropriate

contractual agreements or guidelines will need to be

devised to assure compliance with load following

responsibilities and to require information sharing.

New and better means of calculating a precise value

for load following and cycling services will need to

be developed either to compensate load following

generators or to establish a preference in bidding.

systems. An acceptable method will also be needed

for determining the costs of and setting prices for

providing load following services through scheduling or full dispatchability.

Among the possible policy initiatives available to

assure that the industry adequately anticipates and

2Rc~Y ~c=wes include generating units and interruptible loads that can be dispatched within 10 minutes.
248 ● Electric Power Wheeling and Dealing: Technological Considerations for Increasing Competition

meets the technical and institutional challenges of a

changing bulk power system are the following:

●

●

●

Regulatory agencies could establish guidelines

for determining and allocating the costs of

providing unbundled services, such as load

following, and the additional support services

related to system reliability.

Regulatory agencies and utilities could work

together to establish minimum or standard bulk

power purchase agreements that provide for the

necessary technical conditions of generation

control, coordinated operations, and specific

obligations for system support services and/or

payments. 3 More flexible arrangements could

also be negotiated, provided that adequate

provisions were made to preserve reliability.

Regulators may need to require that competitive supply contracts contain adequate enforcement and default terms to assure that power

supplies will continue to be available. Alternatively, regulators may need to approve larger

reserves for reliability and load following

purposes, as well as possible increases in

transmission system capacity.

As part of their obligation to serve, public utilities

have the responsibility to plan for future power

needs. This utility planning is often conducted with

close review and oversight by State regulators and in

cooperation with other utilities. Generation control

and system engineering considerations are incorporated into these internal planning activities. Information about demand forecasts and resource plans are

frequently shared among utilities through NERC

regional and subregional councils and other voluntary associations to assure that individual utility

resource plans are consistent with regional reliability guidelines.

Most of the current planning efforts rest on a

model of an integrated utility meeting its own needs

in cooperation with its neighboring systems. New

planning methods may be required to integrate

potential competitive power supplies in resource

plans and operating guidelines and to accommodate

new uncertainties that they may bring. New mechanisms or institutions may be needed to promote

participation in cooperative planning by competing

generators to assure that overall system operating

standards are achieved.

●

●

State regulators could require utilities to provide more detailed descriptions of system

needs and technical requirements in filings

with regulatory agencies or bulk power solicitations so that alternative suppliers could effectively compete to provide reliable service. This

obligation would be imposed on integrated

utilities and on transmission and distribution

utilities under a restructured industry.

Regulators might consider structuring the resource planning in a competitive system to

facilitate and encourage long-term planning

that allows more systematic choices about

generation mix, type, location, environmental

impacts, demand management, and conservation strategies.

Meeting the Technical Requirements for

a More Open Transmission System

Under any approach to expanding access to

transmission systems, the primary technical challenges will be in accommodating a greater diversity

among generators and bulk power customers and in

handling an increased number of wheeling transactions.

The transmission system is an integral component

of the overall bulk power system, and it functions

through the coordinated control and operation of

generating units to move power within and between

interconnected systems. Wheeling transactions require some entity to coordinate generation and

reactive power sources to maintain voltage and

frequency, minimize inadvertent flows over other

systems, and provide for security and reliability.

Expanding bulk power transfers also raises issues of

how to schedule and allocate available transmission

capacity, how to cost and price unbundled transmission system support services, and how to encourage

construction of needed capacity. The technical

challenges and the likely cost and reliability impacts

of increased wheeling will depend strongly on who

the buyers and sellers are, their mutual obligations,

the type of service required, and the volume of

transactions. It will also be important to include

3Some State pURpA ad comWlitive bidding prOgTWTI~ Ulrcady have some fom~s Of standard contract ICmlS. The~> s~~dtid arrangcmms Could bC

expanded so [hat technical concerns arc addressed more explicitly,
Chapter 8---Public Policy Issues and Legislative Strategies ● 249

assessments of future transmission needs in overall

system planning for generation and transmission

resources.

The major challenges in accommodating moderately expanded transmission access are primarily

institutional, but overcoming these hurdles is central

to its technical feasibility. Under most, if not all,

scenarios for change, it will be necessary to create

new methods and procedures of coordination, capacity allocation, accounting, and compensation for

unbundled transmission services. Increased wheeling transactions or a more open transmission system

will create challenges for operation and planning

and may require the establishment of new entities

and working arrangements to take over some of the

functions now performed by integrated utilities,

power pools, and cooperative agreements among

utilities.

Expanding transmission services also involves

some technical challenges. The reliable operation of

the Nation’s transmission systems requires coordinated control of most generators that are connected

to the system. Coordination in a more competitive

system with expanded wheeling would function

essentially the same as in the existing system, but

there would likely be many more transactions to

execute. Under a competitive system, the responsibilities for providing certain system support functions might be shifted from integrated utilities to

alternative generation suppliers. Control center operations and planning will become more complex.

There are significant technical differences between wheeling services required for a purchasing

integrated utility with its own generation and

wheeling services for a retail customer or requirements utility without its own generation. If the

purchaser has its own generation, it generally has the

ability to follow load and provide for reliability. If it

does not, the wheeling customer will have to arrange

for equivalent reliability protection with the wheeling utility or bulk power supplier.

Firm transmission agreements tying a specific

generator to a specific customer could cause serious

challenges for system operators in preserving reliability and economy. As the volume of such

transactions increases, the restrictions they impose

on economic dispatch and security constrained

dispatch may result in additional costs and reserve

requirements on the integrated system. Additional

transmission and generating facilities may be

needed for system reliability, which makes this

problem similar to that presented in integrating

nondispatchable generation.

An additional generation control problem that

could increase with more wheeling is the need to

provide frequency regulation for customers with no

generators of their own. Integrated utilities now

provide such services to their full requirements or

distribution only utility customers. If expanded

competition reduces the integrated nature of the

electric power industry, more wholesale and retail

customers could require frequency regulation services from one source but base load and cycling

power from another.

The bulk power system infrastructure and operations will have to evolve to accommodate the

changes that would arise under expanded transmission access. Control centers may need to be upgraded with more personnel and equipment to

handle more transactions. New and improved software for control area operations and accounting will

be needed to execute and track unbundled transactions.

Information and Research Needs—Laying the

institutional and technical foundations to support

greater levels of wheeling in a more competitive

bulk power system will require new and different

information, an increased sharing of information,

and development of new and different ways of

planning, operating, and administering the transmission systems. At the same time that unbundling

creates a more urgent need for information sharing,

competitive pressures to withhold timely information will also increase.

The development of acceptable and accurate

estimates of transmission capacity and availability

will be increasingly important in a competitive

environment. There is also a need for more generally

acceptable and understood methods for use in setting

specific transmission system limitations. The analytical methods and standards in use today are

largely the result of cooperative efforts by integrated

utilities and rest heavily on complex system studies,

professional judgments, and agreements among

power system engineers. The criteria can vary from

system to system and region to region. While these
250 ● Electric Power Wheeling and Dealing: Technological Considerations for Increasing Competition

specially tailored standards reflect the complexity of

local bulk power systems, they may make effective

oversight of more flexible transmission pricing and

denials of transmission access unworkably complex.

Without a common and acceptable approach to

questions of transmission availability and capability, it may prove exceedingly difficult for competitors and regulators to resolve transmission access

disputes.

In order to be able to compete effectively in the

marketplace, purchasers and suppliers will want to

know when, where, and at what price they can move

power. If `a transmission entity claims that it lacks

the capacity to accommodate a desired trade, that

judgment could be challenged. Competitors and

regulators will need more acceptable, objective

standards for assessing transmission availability to

assure that control over transmission systems is not

being used to unfair competitive advantage and/or

that transmission utilities are fulfilling their obligations to provide adequate capacity.

In addition, accurate and acceptable measures

must be developed for determining the additional

system costs that wheeling transactions impose on

the primary parties involved and on other systems.

Legislative and Regulatory Initiatives-Most of

the responsibility for assuring that the transmission

system continues to function reliably in a more

competitive structure will necessarily rest on the

electric power industry. But legislators and regulators also have an important role to play because the

provision of transmission services will remain a

monopoly under virtually any credible industry

structure. It is likely that growth of a more competitive generating sector will require much more

vigorous regulation of transmission access and

pricing than currently exercised by Federal and State

regulators. The following are among the major areas

where legislative and administrative actions will be

required if it is decided to expand transmission

access. Some activity in these areas is already

ongoing but to a far lesser extent than actions on

competitive supplies.

An effective regulatory framework will need to be

established to oversee transmission arrangements

and appropriate transmission pricing policies. Compensation policies could be developed for inadvertent flows and constraints imposed on other systems

from wheeling transactions. To the extent that the

existing system does not provide this guidance, this

will likely require action at both the Federal and

State levels.

Congress could require the Federal Energy

Regulatory Commission to establish guidelines or

rules for determining and allocating the costs of

providing unbundled transmission services, including additional support services related to system

reliability. (FERC could also move to establish these

regulatory standards on its own initiative.)

State regulators could encourage or require

integrated utilities to consider overall regional

transmission capacity needs in their planning activities. The costs of providing all or part of an adequate

transmission capacity could be included in the

ratebase.

Congress could require a more detailed study of

the technical and institutional changes required for

successful transition to a more open transmission

system under one or more preferred competitive

systems. The study might be coordinated by FERC

or the Secretary of Energy. (Such a study would be

useful even if the policy choice is to expand

opportunities for transmission access and to allow

competition among generating sources to evolve

slowly under existing law and regulation.)

Federal and State Governments could fund necessary studies for resolving common problems in

establishing standards for transmission availability,

in costing and pricing of transmission services, and

in minimum contract provisions for wheeling services. Alternatively, Federal and State regulators

could provide a forum for development of a consensus approach by regulators, utilities, nonutility

generators, and bulk power customers.

Creating a Stronger and More Flexible

Transmission Network To Accommodate

Industry Change and National Needs

Many proposals for expanding competition either

have assumed that adequate transmission capacity

would be available to allow the growth of competitive markets or have ignored transmission capability

issues. The existing transmission networks already

support higher levels of bulk power transfers than

just 10 years ago, according to industry experts. At
Chapter 8-Public Policy Issues and Legislative Strategies ● 251

times, during record-setting peak demands in the

summer of 1988, transmission line constraints prevented power transfers to avoid voltage reductions

and brownouts in New England. And although

NERC reports that transmission capabilities are

generally adequate for projected needs, its periodic

reliability assessments note a number of key transmission constraints that it says could affect reliability and system security.4

Are the Nation’s existing transmission systems

and coordinated operations adequate to support

expanded competition and increased wheeling?

There is no clear answer to that question because of

uncertainties over what forms increased competition

will take and where and under what conditions

additional wheeling will be needed. There is also a

lack of consensus over standards for determining

adequacy. In looking at the technical feasibility of

increasing transmission access, OTA found that

there is no independent and systematic review of

existing transmission system constraints and bottlenecks, Some constraints identified by NERC and

others are tied to transmission lines that are the

subject of protracted regulatory or court proceedings. Others involve limitations on particular wheeling transactions, and still others reflect temporary

conditions arising from the loss of specific lines or

power plants or from particular bulk power flow

patterns, Evidence supporting a contention that we

are currently suffering a long-term physical transmission shortage is spotty and anecdotal. OTA’s

own survey of electric utilities elicited a few

examples of transmission constraints, but according

to the respondents, few were of sufficient magnitude

to offset the costs of correcting them.

Assessing Transmission Capability: Legislative

and Regulatory Strategies

In the absence of any systematic and credible

assessment of the strength and flexibility of the

Nation’s transmission system to support the growth

of competitive bulk power markets, specific recommendations for physical system improvements cannot be made. Concerted efforts by Federal and State

Governments and the utility industry will be vital to

securing an adequate appraisal of the capabilities of

our interconnected transmission networks.

Better assessments of transmission capability

could lead to greater consensus over corrective

actions and additional capacity and how to pay for

them. Better analysis is needed on the adequacy and

availability of transmission capacity for transmission system planning and regulatory oversight. More

information is needed and improved analytical

methods must be devised to carry out this task,

however. Data are needed both for individual utility

systems and for the larger interconnected grids.

There are several ways of addressing these information problems.

On a national level, it maybe an appropriate time

to commission a new detailed study of the capability

of the Nation’s transmission systems to serve

projected needs and to respond to emergency

situations. There have been at least two previous

federally sponsored studies of the national power

grids and it is generally agreed that the studies

resulted in improved system operations.

There is a need for more frequent assessments of

regional transmission capabilities and constraints to

aid regulators, system planners, and transmission

users. One approach is to continue relying on the

transmission utilities and voluntary organizations,

such as the North American Electric Reliability

Council (NERC), to provide that information. This

“voluntary” approach has at least several obvious

disadvantages. First, their conclusions may be

viewed with suspicion by regulators and competitors, particularly among independent power producers and public power agencies. Second, they may be

unwilling to assume the increased responsibilities

and risks for reporting and analysis without some

regulatory concessions. Third, voluntary associations may lack the necessary authority to gain access

to critical technical information or to share it with

others. In a more diverse electric power industry,

these organizations, which have traditionally been

dominated by large integrated utilities, may need to

expand to include wider participation in order to

remain credible.

An alternative approach is to revise existing

government reporting requirements at the State and

Federal level to assure that sufficient information is

obtained periodically to monitor the health of the

transmission systems. It would be useful to involve

4Sce discussion in ch. 6 of this rCpOfl.
252 ● Electric Power Wheeling and Dealing: Technological Considerations for Increasing Competition

the utilities, voluntary industry associations, energy

planners, and regulators in identifying the necessary

information and any additional reporting requirements.

Fundamental to the success of increased efforts to

monitor the capability of transmission systems will

be the development of standard methods for monitoring and measuring transmission capacity and

availability. As noted above, despite their shortcomings, these standards are also needed for more

effective transmission system oversight by regulators and could be developed through the regulatory

process. Alternatively, government agencies could

sponsor and participate in joint efforts with industry

to develop appropriate technical guidelines to assess

transmission capability under a competitive system.

In addition to improved reporting requirements,

regulators may elect to require utilities to include

more frequent and detailed assessments of their

transmission systems with particular attention to

analysis of potential physical improvements for

increasing capacity or reducing bottlenecks and the

costs and benefits of such actions. This transmission

assessment could be included in system planning

reports or in periodic reviews of utility operations

and would be available to the public as well.

EXPANDING COMPETITION IN THE

ELECTRIC POWER INDUSTRY—

INSTITUTIONAL AND POLICY

ISSUES

Enhancing Bulk Power Competition

There are four prerequisites for creating a more

competitive generating sector. First, the existing

regulatory and institutional structure must be altered

either through evolution or by political decision to

accommodate changes. Second, there must be a

market opportunity as evidenced by an increased

need for power, a potential for cheaper power, or a

specialized niche such as that provided for qualified

facilities (QFs) by the Public Utility Regulatory

Policies Act (PURPA). Third, potential competitors

must be able to enter the market to sell their services.

Fourth, there must be a market-some mechanism to

bring together buyers and sellers to make offers and

acceptances and to transfer the commodities or

services sold.

In previous sections, we addressed some of the

technical and institutional changes necessary to

establish a foundation for a more competitive bulk

power industry. We suggested a number of possible

legislative and administrative actions that could be

taken to build that foundation. But proposals for

changing the regulatory and institutional structure of

the bulk power industry raise many other legislative

issues. Under different strategies for expanding

competition and different levels of competitive

changes, congressional action will be required for

successful implementation. Without congressional

action, competition may be limited or lopsided and

evolutionary changes may make traditional utility

regulation impractical and/or ineffective in achieving Federal and State electricity policy goals. It is

also possible that in the absence of an aggressive

regulatory presence the growth of a competitive

generation sector may be so extensive that Congress

or regulators may need to slow the process to allow

the regulated transmission and distribution sectors

adequate time to adjust their own operations and

procedures. In this and following sections we outline

some of the legislative issues that are likely to arise

under alternative paths of industry change.

Creating a More Competitive Market Structure

Under Existing Laws

Market forces have already gained a significant

foothold in the electric power industry as a result of

economic pressures on utilities and their customers

and the influence of PURPA. Within fairly broad

boundaries, existing competitive trends and administrative proposals would allow both electric power

regulation and the generating sector to evolve to

include more opportunities for competition among

suppliers and greater reliance on market-based rates

for bulk power. If these changes are viewed as

desirable, Congress might allow administrative efforts to continue, while monitoring the impacts of

limited competition within a regulated industry.

The extent to which a more competitive market

structure is likely to evolve will depend greatly on

the related but separate issues of access to and

pricing of transmission services. In addition, the

Federal Power Act, PURPA, and the Public Utility

Holding Company Act (PUHCA) limit regulators’
Chapter 8-Public Policy Issues and Legislative Strategies ● 253

exclusive reliance on competitively procured power

costs in setting wholesale and retail rates and

constrain broad participation in competitive power

markets by some entities.

Congress could encourage further experimentation with more competitive markets and transmission access at the State level to gain additional

information on possible savings and social costs and

benefits. This might be achieved through congressional oversight of FERC and influence over the

appropriations process. 5 It would of course be

essential that the results of any such experiments be

monitored closely and rigorously analyzed for them

to provide any effective or credible guidance for

further congressional and administrative actions to

change electric power regulation and market structure.

FERC has proposed a shift toward greater reliance

on market forces in regulation in its notices of

proposed rulemaking (NOPRS) on competitive bidding for setting avoided cost capacity payments

under PURPA and ‘‘relaxed regulation and flexible

pricing for IPPs [independent power producers]”

under the Federal Power Act. Some observers note

that FERC also has attempted de facto deregulation

of wholesale economy sales through its general

“hands-off” approach to reviewing negotiated

prices.

Prospects for the growth of an extensive competitive generating sector under FERC’s proposed

approach are somewhat uncertain because of existing statutory constraints on participation by utilities

under PUHCA, the limited exemptions from Federal

and State utility regulation under PURPA, and

general uncertainties over future electric utility

regulatory policies. Questions have also been raised

as to whether FERC’s initiatives may exceed its

statutory authority. On the other hand, the experience with rapid growth in QFs under PURPA and the

appearance of some IPPs indicates that the current

system can support at least some increased level of

competitive supplies.

Legislative Actions To Promote Broader

Participation in a Competitive Generating Sector

If the growth of a competitive generating sector is

consistent with other national goals in energy policy

and utility regulation, Congress may wish to reconsider several existing legislative restrictions that

may limit some potential participants in a competitive generating sector. By modifying or repealing

provisions of the Federal Power Act, PURPA, and

PUHCA, Congress could significantly expand the

ranks of eligible competitors in the bulk power

markets. However, changes in these laws would be

highly controversial and could jeopardize other

important public interests and national policies.

Moreover, it is not clear that such actions are

necessary to draw new participants into the bulk

power industry. Most of the restrictions in existing

laws are not absolute barriers to participants who

want to build generating plants and sell electric

power. Nevertheless there are some critics who

would like to see the laws changed to expand

exemptions from Federal and State public utility

regulation. Under current law, most generators who

sell power are considered public utilities. As a result,

a generator might:

1. be required to file extensive financial and cost

information with Federal or State regulators,

2. be limited in its ability to sell electricity at

market rather than cost-based prices,

3. be required to maintain a “balanced” capital

structure, and

4. be restricted from engaging in extensive nonutility businesses.

Some industry observers in FERC and elsewhere

believe that the threat of being treated as a public

utility deters potential investors in competitive

generation. Electric utilities are al~u somewhat

constrained from competing to sell power in areas

remote from their interconnected system areas by the

limitations in PUHCA, either because their operations as registered holding companies are highly

restricted, or they fear losing their exempt status.

slt ~ou]d ~w ~~SS1b]e for Congcss t. enact Iegls]atlon providing a Iimi[cd exemption from c~fiain provisions of PUHCA ~d WA, similar 10

those allowed under PURPA, to atlow competitive market c~perimenls 10 take place either for a limited dura(ion or for specific classes of competitors.

Congress could require that FERC closely monitor and report on any savings achicvcd, any additional system costs, and the effects on system operations

and reliability.
254 Electric Power Wheeling and Dealing: Technological Considerations for Increasing Competition

PURPA offers a limited exemption from State and

Federal public utility regulation, including PUHCA,

to certain qualified facilities. These entities have

been able to operate somewhat freely under the

existing regulatory structure. Indeed, many utilities

have joined the ranks of QFs through joint ventures

with other parties to build and/or operate qualifying

plants. Changes to the size, technology, and utility

ownership restrictions for QF eligibility would be

one way of expanding competition, however, this

change could undercut a fundamental goid of

PURPA to promote cogeneration, alternative energy

technologies, and small power production.

On the other side, there are many utilities, State

regulators, and consumer groups that would oppose

any relaxation of laws governing public utilities

either to attract new entrants to the industry or to

ease the limitations on the competitive activities of

regulated utilities. They argue that existing laws

provide ample latitude for both utility and nonutility

participation in competitive markets and that where

certain activities may be constrained there may be

important public policy considerations that would

support maintaining the protections of existing laws,

such as PUHCA.

Expanding Access to Transmission ServicesLegislative Issues

A potentially significant mechanism for expanding competition in electric power generation would

be to assure that potential competitors can gain

access to needed transmission services at reasonable

rates. Transmission access allows generators outside

a host utility’s territory to compete to provide

electric power. As a prerequisite for expanding

transmission access, there must be adequate transmission capacity available and arrangements to

preserve system reliability.

Actions Under Existing Law-At present, most

transmission access and wheeling arrangements are

voluntarily negotiated between the power purchaser

and the wheeling utility. FERC oversees the terms

and conditions of transmission agreements. FERC

has very limited authority to order a utility to provide

transmission service or to build new lines, although

many public power utilities argue that FERC has not

used its existing authority aggressively enough.

State authority is also believed to be limited. A range

of approaches have been suggested to promote

greater access to transmission services that do not

require legislative changes. The following five

approaches are representative.

One--relying on voluntary arrangements and the

growth of competitive bulk power markets to create

sufficient economic incentives for transmission utilities to open up their grids to other competitive

suppliers. This approach leaves existing provisions

unaffected. There has been some movement in

several regions towards providing greater access to

transmission services, notably in the Northeast and

the Pacific Coast. A major limitation in this approach is that utilities may be unwilling to provide

wheeling services to allow their current wholesale

and large retail customers to shop for power from

alternative sources. Even where a refusal to wheel

can be found to be an unlawful anticompetitive

practice, reliance on traditional antitrust enforcement to provide an effective and timely remedy may

be impractical. A further objection to the current

system is the lack of any provision for compensation

to other utilities for unintended flows over their lines

from other bulk power transactions.

Two--Changing the administrative process and

policies to encourage voluntary access by providing

more public information on wheeling arrangements

and rates, setting deadlines for negotiating wheeling

requests, providing a mechanism for mediation of

disputes over wheeling, and collecting more data on

the costs of providing wheeling services so that they

can be more fully reflected in rates. This approach

is similar to the first in that it does not require a

change in legislation and could be accomplished

administratively. This approach also suffers many of

the disadvantages of the first approach, but may

offer some incentive to utilities who might otherwise

be unwilling to provide services. The change in the

process could also provide a more detailed evidentiary record to support antitrust actions in cases of

refusals to wheel.

Three-Using transmission pricing incentives to

encourage transmission utilities to provide services

and expand capacity. Some industry analysts have

asserted that voluntary access could be encouraged

if regulators were to change transmission pricing

from a strict embedded cost basis to other approaches, such as “flexible” pricing, that include

additional economic incentives. Other analysts have
Chapter 8--Public Policy Issues and Legislative Strategies ● 255

suggested that improvements in cost-based transmission pricing would also be beneficial. FERC has

approved several experimental transmission agreements with alternative pricing schedules.6

Four---Using existing authority to require access

as a condition of participating in a competitive

market. Because of Federal court decisions and

various FERC decisions, the extent of FERC authority to require a utility to agree to provide transmission access as a condition for receiving favorable

FERC action on the treatment of certain wholesale

transactions is open to question. Some observers

believe that FERC has such authority, while others

do not. FERC has requested comment on this issue

in its competitive bidding NOPR.

Five-Encouraging joint ownership and participation in transmission line construction and upgrades through conditioning authority, antitrust

review, and authority over Federal power marketing

agencies and cooperative loans, and Federal ownership and influence over rights-of-way. FERC and

State agencies could encourage transmission utilities to allow participation in new transmission

capacity by other utilities by conditioning approval

of rates, transmission agreements, and other regulatory actions on such agreement by a petitioning

utility. FERC has used its approval of Pacific Power

& Light’s acquisition of and merger with Utah

Power & Light to expand access to the new utility’s

transmission lines under its authority to approve

mergers under section 203 of the Federal Power

Act. 7 Bonneville Power Authority has been pressured to expand access to its transmission capacity

to regional utilities. Federal land agencies granting

rights-of-way over public land might condition such

grants on sharing of the transmission capacity under

a policy to maximize joint use of right-of-way

corridors.

Changes in Federal Law To Expand Transmission Access-If reliance on existing law and administrative action to provide transmission services

proves unworkable, ineffective, or undesirable, Congress could take legislative action on transmission

access issues. Perhaps the most direct approach

would be to amend the Federal Power Act and

PURPA to provide more effective wheeling authority for FERC, as outlined in the five following

approaches.

One-Providing new Federal wheeling authority

as a remedy for refusals to wheel. Because of

restrictive statutory provisions and court decisions,

FERC and others contend that it has little effective

authority to order a utility to provide wheeling

services after it has refused to wheel in an exercise

of monopoly power to restrict competition. Congress could amend the Federal Power Act to provide

explicit authorizations for such remedial wheeling

orders and could also authorize FERC to order a

utility to increase transmission capacity if needed to

comply with a remedial order. In amending the

Federal Power Act, Congress could make clear that

the PURPA amendments did not restrict wheeling as

a remedy to monopoly or anticompetitive abuses.

This change could also be coupled with pricing

changes to provide more adequate compensation for

transmission services and procedural changes to

shift the burden of proof to the party denying access.

One possible alternative mentioned in our discussion of scenarios would be the option of transferring

greater authority over instate wheeling, retail wheeling, and regional wheeling arrangements to State

commissions.

Two--Providing Federal wheeling authority under

a broad public interest standard. This approach,

which forms the basis of the wheeling provisions in

OTA’s scenarios 2, 3, and 4, would allow FERC to

order wheeling whenever it determined it was in the

public interest. Essentially, this amendment would

drop many of the restrictive conditions placed on

mandatory wheeling authority under PURPA, espeWhese include two bulk power marketing experiments: Southwest Experiment, FERC opinion No. 203, Docket No. ER84-155-O(K), Dec. 30, 1983

(see box 5-E in ch. 5 of this report); and the Western Systems Power Pool, Order Accepring Everhenral Rues for Fding, FERC Docket No.

ER87-97-001, Mar. 12, 1987 (box 5-Finch. 5). In 1988 FERC approved twotransmission agreements with novel pricing schcmcs:Pac@Gus & Electric,

FERC Docket No. ER88-219-000, Mar. 31, 1988, 42 F. E.R.C. 61,406, clarification issued JMe 1, 1988 (contract between PG&E and the lhrlock

Irrigation District); and Pacific Gas & Efectric, FERC Docket No. ER88-302-001, JUIY 5, 1988, ~ F.E.R.C. 61,010 (contract with the Modesto Irrigation

District). The ‘Mock agr~ment is briefly discussed in ch. 5, box 5-G.

TT~re ~ &eWy im~ces of joint OWndtip and operation of transmission by utilities in Georgia, Indiana, South Dakota, and Minnesota. For

example, in Georgia, the statewide transmission grid is owned by a consortium of a private power company, municipat electric utilities, and rural electric

cooperatives. Operating charges are assessed according to each group’s use of the grid. Larry Hobart, American Public Power Association, personal

communication, Nov. 21, 1988.
256 ● Electric Power Wheeling and Dealing: Technological Considerations for Increasing Competition

cially the requirement that the order must not disturb

existing competitive relationships. As an additional

option, included in OTA scenario 2, wheeling orders

for very large retail customers might also be

allowed, perhaps with a requirement that appropriate

State regulatory agencies be consulted about potential impacts on other wholesale and retail customers

and State policies.

Three--Providing for Federal action to reduce

monopoly power over transmission services. The

Federal Power Act could be amended to provide that

if FERC determines that a major utility controlling

significant transmission systems in a region either

exercises or has a substantial potential to exercise

monopoly power over transmission to the detriment

of other utilities or the public interest, the transmission utility may be ordered to open up a portion of

its capacity as a common carrier to other regional

utilities and to maintain adequate transmission

capacity to serve regional needs. Such an action

would be a dramatic expansion of the FERC action

in the Utah Power & Light decision where it found

that approval of the proposed merger would likely

result in unlawful monopoly control over regional

transmission services unless conditions requiring

expanded access for other utilities were adopted.

Finally, two additional approaches to expand

access to transmission services involve a more direct

Federal role in encouraging capacity expansion

through more cooperative State planning efforts and

expansion of the Federal role in providing regional

transmission services.

Four--Authorizing the creation of multi-State

regional transmission planning compacts. Congress

could enact legislation that would establish regional

compacts to promote regional cooperation and

planning for transmission capacity. This approach

was suggested by the National Governors’ Association and is based in part on the regional nuclear

waste compacts and the legislation creating the

Northwest Power Planning Council.8

The authority of the regional commissions would

be limited to assessing and planning for transmission

needs. They would not site, certify, or approve

transmission lines. However, States could individually require that lines be consistent with regional

needs as identified in the regional plan in order to be

approved by State regulatory authorities. Similar

conditions could be imposed on approval of federally owned transmission facilities and on the use of

Federal lands for rights-of-way.

Five—Authorizing the creation of new federally

authorized transmission entities to provide wheeling

services. The Federal Power Marketing Agencies

(FPMAs) currently exist to market and transmit

power produced from federally financed power

facilities of the Bureau of Reclamation and the

Corps of Engineers. The regional agencies are

authorized to build and operate transmission lines to

move power to customers and to contract with

private utilities for wheeling services. From time to

time, it has been suggested that the power marketing

agency concept be expanded to provide regional

transmission services for public power agencies,

consumer cooperatives, and other utilities. The new

agencies could be either directly under Federal

control or federally authorized multi-State regional

commissions. Another possible structure is to create

federally chartered private corporations to own and

run the transmission systems. Under scenarios 4 and

5, which would result in dramatic restructuring of

the industry, creation of publicly owned transmission entities would be one way of disaggregating the

transmission sectors to provide coordinated transmission services.

Restoring a Balance in Federal and State

Regulatory Jurisdiction—

Legislative Issues

Current competitive trends in the electric power

industry have served to increase the tension that has

always existed between Federal and State regulatory

jurisdictions. Federal court and agency decisions

and changing industry practices have tilted the

balance toward a more dominant Federal influence

over wholesale, and thus retail, power prices perhaps

to a degree not anticipated in PURPA or the Federal

Power Act. This trend will accelerate under a

competitive bulk power market structure unless

Congress changes existing laws to limit or override

Federal court and agency decisions.

8Nationa] Govcmors’ As~.ialion, Moving Power Flexibili~’ for tht’ Furure, Report of Ihc Committee on Energy and Enwronment Task Force on

Electricity Transmission, 1!X17.
Chapter 8-Public Policy Issues and Legislative Strategies ● 257

Under the Federal Power Act, Federal regulation of interstate wholesale sales was seen as a

necessary measure to fill a gap in State regulatory

jurisdiction. With increasing interconnections among

utilities, corporate restructuring, and an expansive

interpretation of the jurisdictional provisions of the

Federal Power Act, virtually all wholesale power

sales involving privately owned utilities, except for

those in Alaska, Hawaii, and parts of Texas, come

under exclusive FERC jurisdiction. The same is true

for transmission agreements, including those between utilities that are in the same State and

otherwise subject to State jurisdiction.

Restoring State Primacy to Utility Regulation

If Congress wanted to reform Federal utility

regulation to restore and strengthen the traditional

model of State regulated utilities within a limited

Federal system, possible legislative actions might

include:

1.

2.

3.

Limiting the application and/or extension of

the Mississippi Power case on preemption of

any inquiry into prudence of wholesale sales at

the State level. This would allow State regulators to examine and rule on the reasonableness

of wholesale power contracts by State jurisdictional utilities.9

Amending the Federal Power Act to return

jurisdiction over most instate wholesale power

and wheeling transactions to State authorities.

This would in effect be accomplished by a

legislative override of the Colton case preempting State jurisdiction over instate wheeling and

power sales. 10

Requiring FERC to defer to State agency

decisions in matters that historically have been

governed by State law, such as prudence and

resource planning. Congress could require that

FERC defer to prior State decisions on approved utility resource plans and the prudence

of wholesale power purchase arrangements

and to consult with State regulators on such

matters in any FERC rate proceeding.

4.

5.

6.

Modifying the Federal Power Act to provide

that the creation of a utility holding company

consisting of separate, but formerly integrated,

generation, transmission, and distribution companies would not create a wholesale relationship subjecting transactions among these entities to exclusive Federal jurisdiction. This

would limit the ability of utilities to escape

State oversight by forming holding companies

or generation subsidiaries to sell power to

retail distribution subsidiaries that are either

directly or indirectly controlled by the same

parent corporation.

Amending the Federal Power Act to provide

State regulators with access to interstate holding company books and records needed for

State oversight and requiring FERC to cooperate in obtaining and sharing the information

needed. This might include a FERC inquiry as

to whether it collects adequate and appropriate

information to oversee the utility industry.

Closing this information gap for State regulators would allow more effective State oversight of multi-State transactions. States could

certify to FERC their need for obtaining

information from companies selling or transmitting power operating in interstate commerce.

Providing for a State role in any new Federal

wheeling authority. FERC might be required

to notify and consult with State regulators on

wheeling petitions on such local matters as the

potential impacts on native utilities and ratepayers or the desirability of retail wheeling.

Creating an Expanded Federal Role

in Utility Regulation

If on the other hand, Congress concludes that a

primary Federal role over wholesale sales is appropriate and that most State regulatory inquiries should

effectively be preempted, it may want to consider

whether FERC authority or procedures should be

modified to provide equivalent protections for

consumers, wholesale customers, and State and

9Mississ1pp1 Power & Light Co, V. Mi~s~sippi ex rcl AfOOre, No. 86-1970, June 24, 1988. For suggestions by one State regtdatoron possible changes

to Federal laws to give States a more effective role in regulating more competitive bulk power markets, sec “Testimony of the Honorable Ashley C.

Brown, Commissioner, Ohio Public Utilities Commission” m Oversight Hearing on independent Power producers and the Public Utility Holding

Company Act Before the Subcommittee on Energy and Powerof the House Committee on Energy and Commerce, IOOth Cong., 2d sess., Sept. 14,1988.

IOFedera/ power CoMlsslon v, Southern Cu/lfornla E~ison Co,, also known as c’@ Of Colton V. .$ou[hern C~l~ornia Edison CO , ?76 U.S. 205

(1%8).
258 ● Electric Power Wheeling and Dealing: Technological Considerations for Increasing Competition

local governments that have commonly been available in many States.

Alternatives to Competition for Achieving

Reliability and Economy

Generation competition and expanded transmission access are but two reforms that have been urged

as a means of making the electric power industry

more economically efficient and providing lowest

cost power to retail customers. Congress and other

policymakers may want to investigate the extent to

which other changes in the industry could yield

many of the same benefits without requiring significant and possibly irreversible institutional changes.

Examples include:

1.

2.

3.

Promoting greater cooperation and more effective use of utility resources through expansion

of power pools and coordination arrangements

with increased use of central dispatch and

interconnection agreements.

Encouraging experiments in facilitating economy bulk power markets such as the Western

Systems Power Pool and the Florida Power

Broker.

Allowing continuation of the trend toward

consolidation of regulated private utilities with

close Federal and State oversight and appropriate conditions to prevent growth of monopoly

abuse particularly in the area of transmission.

Impacts on Other Public Policy Goals

Changes in the electric power industry structure

could have consequences in other public policy

areas such as environmental regulation, consumer

protection, and energy policy. Among the specific

policy areas that might be affected by legislative and

regulatory changes to promote creation of a more

competitive electric power industry include:

●

●

●

conservation and least cost management programs of utilities and State regulatory agencies;

PURPA incentives for cogeneration and alternative electric power technologies, including

whether required QF purchases at avoided cost

continue to be effective in meeting PURPA’s

energy policy goals;

consumer representation and access to information for retail rate hearings at the State and

Federal level;

●

●

the effectiveness of current regulations in

achieving environmental protection goals such

as permitting standards for new electric plants,

fuel mix, and plant repowering, and shifts in

environmental impacts of power generation

among regions and technologies; and

energy R&D programs including impacts on

industry funded efforts and on the viability of

Federal incentive programs from a more competitively constrained and disaggregate industry.

These areas deserve particular oversight to ensure

that the indirect impacts of expanding competition

are as constructive as possible.

Better Information and Analysis for

Public Decisionmaking

OTA found a notable lack of accurate and relevant

information and analysis on many aspects of both

existing bulk power transactions and competitive

markets. The areas where improved information and

analysis would be beneficial for policy makers include:

●

●

●

●

information on patterns of bulk power trades

and wheeling transactions (e.g., how much

power is bought, sold, and wheeled, where,

when, and at what prices);

more accurate and complete information on the

emerging competitive generating sector including nonutility generators (QFs and IPPs) and

self-generators, (e.g., location, size, ownership,

dispatchability, operating status, contract terms,

and problems encountered);

more analysis and identification of actual

potential efficiency gains from competition;

and

more analysis of opportunities for and potential

benefits of bulk power transactions. -

To address this lack of information and analysis,

Congress could require the Energy Information

Administration and FERC to review existing data

collection, analysis, and reporting activities and to

report to Congress on: 1) proposals to revise or

expand existing activities to provide more adequate

coverage of electric power industry data and trends,

and 2) recommendations for expanded data collection and reporting authority to cover any gaps in

existing law or regulation.
Chapter 8-Public Policy Issues and Legislative Strategies ● 259

Power Frequency Fields and Public Health

It now seems possible, based on the state of

scientific research, that exposure to electric and

magnetic fields, such as those produced by electric

power systems, could pose a hazard to human health.

While it is not yet possible to demonstrate that such

hazards do in fact exist, and they may not, it is no

longer possible based on emerging scientific evidence to assert categorically that they do not. The

research results are complex and inconclusive.

Nevertheless, concern is growing among policy makers and people living near existing or proposed

transmission lines.

Power frequency fields from high voltage AC

transmission and distribution lines are but one

source of exposure. Electric blankets, household

appliances, lighting fixtures, and inside wiring also

create low-frequency electric and magnetic fields.

These sources are far more common than transmission lines and may play a far more significant role in

human health.

Policy makers are faced on the one hand with the

possibility that people are being exposed to previously unrecognized hazards, and on the other with

potentially unnecessary costs and delays in transmission construction. These uncertainties will persist under any strategy for expanded competition.

Among the possible actions that Congress might

consider are:

1.

2.

3.

Funding additional research on potential

health effects (including reexamination of

research priorities in Federal military and

civilian programs on biological effects) and on

methods of shielding humans from exposure to

electric and magnetic fields from powerlines,

building wiring, electric equipment, and appliances.

Funding research necessary to determine the

possible extent of health problems (e.g., actual

field strength and exposure measurements,

population studies, epidemiological studies).

Funding research into methods for establishing

exposure guidelines for use in siting or relocating transmission lines to avoid exposure where

it can be done prudently and without excessive

cost.
Appendixes
Appendix A

List of Acronyms and Terms

AC:

ACE:

AGC:

ANSI:

CWIP:

DC:

DOE:

DSG:

ECAR:

ECC:

EHV:

ELF:

EMS:

ERCOT:

FERC:

FPA:

HVDC:

IPP:

kV:

kW:

kWh:

LOLP:

MAAC:

MAIN:

MAPP:

MW:

NARUC:

NEPA:

NEPOOL:

NERC:

NOPR:

NRC:

PJM:

NPCC:

NUG:

PSD:

Puc:

PUHCA:

PURPA:

QF:

SCADA:

SERC:

SPP:

VAR:

Acronyms

alternating current

area control error

automatic generation control

American National Standards Institute

Construction Work in Progress

direct current

Department of Energy

dispersed source of generation

East Central Area Reliability Coordination

Agreement

energy control center

extra high voltage

extremely low frequency

energy management system

Electric Reliability Council of Texas

Federal Energy Regulatory Commission

Federal Power Act

High voltage direct current

Independent power producer

1,000 volts (kilovolt)

1,000 watts (kilowatt)

kilowatthour

loss of load probability

Mid-Atlantic Area Council

Mid-American Interconnected Network

Mid-Continent Area Power Pool

1 million watts (megawatt)

National Association of Regulatory Utility

Commissioners

National Environmental Policy Act of 1969

New England Power Pool

North American Electric Reliability Council

notice of proposed rulemaking

Nuclear Regulatory Commission

Pennsylvania/New Jersey/Maryland Interconnection

Northeast Power Coordinating Council

nonutility generation

prevention of significant deterioration

public utility commission

Public Utility Holding Company Act of 1935

Public Utility Regulatory Policies Act of

1978

qualifying facility

supervisory control and data acquisition

Southeastern Electric Reliability Council

Southwest Power Pool

volt-amps-reactive

V/m: volts per meter

WSCC: Western Systems Coordinating Council

Terms

Alternating Current (AC): Electric current that reverses

direction many times per second (120 times per second

in the United States); almost the entire U.S. power

system uses AC except for some long-distance direct

current (DC) transmission lines.

Automatic Generation Control (AGC): A system used

to control the output of electric generators in a control

area to balance the supply and demand of power and

execute power transactions with neighboring control

areas.

Bulk Power System: Includes generating units, transmission lines, and related equipment.

Capacity Margin: The difference between generation

capacity and peak load expressed as a percentage of

capacity.

Circuit: A conductor or system of conductors that forms

a closed loop through which current flows.

Cogeneration: Production of both electrical (or mechanical) energy and thermal energy from the same

primary energy source.

Conductors: Bundled strands of wire that carry electric

current.

Control Area: A region with an energy control center

responsible for operating the power system within that

area.

Coordinating Transactions: Involves the scheduling

and control of generation to implement power transfers, as well as monitoring and recording the transactions for billing or for other compensation.

Direct Current (DC): Electric current that flows continuously in one direction.

Distribution lines: Power lines delivering electricity to

customers at relatively low voltages typically between

110 and 69,000 volts.

Economic Dispatch: A system for selecting generating

units to operate to balance supply and demand at

minimum cost.

Economy Transfers: Power purchased by one system

from another because it is less expensive than power

produced by the first system’s own generating facilities.

Electric Field: The electric force that a charged object is

capable of exerting on other charges in its vicinity.

Hertz (Hz): Frequency measured in cycles per second;

power systems in the United States operate at “60 Hz.

–263–
2&? ● Electric Power Wheeling and Dealing: Technological Considerations for Increasing Competition

Load Management: The manipulation of customer

demand by economic and/or technical means.

Loop Flows: Parallel path flows crossing utilities’

boundaries along paths not contracted for or scheduled.

Loss of Load Probability (LOLP): A measure of the

long-term expectation that a utility will be unable to

meet customer demand.

Magnetic Field: The magnetic force that a charged object

is capable of exerting on other charges in its vicinity.

Qualifying Facility (QF): Generating unit qualifying for

special regulatory treatment under the Public Utility

Regulatory Policies Act of 1978.

Radial or Feeder lines: Transmission lines connected to

the grid at only one end; the other end is connected

either to a power plant or distribution system.

Ramp Rate: The rate at which a generator’s power output

can change.

Reactance: A phenomenon of AC power in which the

voltage and current are out of phase, that is, they do not

peak simultaneously.

Reactive Power: Power which is stored by reactive

elements in a power system; called VARs (Volt-ArnpsReactive).

Real Power: The rate at which energy is delivered to a

load to be transformed into heat, light, or physical

motion.

Reliability: The ongoing ability of a power system to

avoid outages and continue to supply electricity with

the appropriate frequency and voltage to customers.

Reserve Margin: The difference between generating

capacity and peak load, expressed as a percentage of

peak load.

Retail Wheeling: Wheeling for delivery of power to a

retail customer.

Security: The ability of the bulk power system to

withstand sudden disturbances, such as the failure of a

generator or transmission line.

Speed Governor: A device on a generating unit which

adjusts the unit’s power output to maintain the exact

frequency.

Stability: The ability to maintain synchronous operation

following disturbance.

Substations: A collection of power system equipment,

such as voltage transformers, circuit breakers, and

switches.

Supervisory Control and Data Acquisition: Telemetry

and control equipment which monitors voltages and

power flows and coordinates the transmission line and

voltage control equipment.

Telemetry: Monitoring and communication equipment.

Transmission Access: The ability to use a transmission

system.

Transmission System: An interconnected group of

individual lines, which transport electricity over long

distances.

Volt: A unit of electromotive force or the electrical

pressure that can push a current through a circuit; can

be positive or negative.

Voltage: A measure of the difference in volts between any

two conductors or between a conductor and the

ground, which is considered to be zero.

Watt: The unit of measure of electrical power or the rate

of doing work.

Wheeling: The use of the transmission facilities of one

system to transmit power produced by other entities.

Wholesale Wheeling: Wheeling for delivery to a utility

system.
Appendix B

Contractor Reports

Background Paper (available from Superintendent of Documents, U.S. Government Printing Office):

• Biological Effects of Power-Frequency Electric and Magnetic Fields; Carnegie Mellon University.

Working Papers of Volume 11 (available from the National Technical Information Service):

. Transmission Line Certification and Siting Procedures and Energy Planning Processes; Public Utilities Commission

of Ohio and the West Virginia Public Service Commission.

. Electric Utility Generation and Transmission Planning and Coordination: Summary of Utility Responses; Public

Utility Commission of Ohio.

. Summary of Responses of the Regional Reliability Councils; Public Utility Commission of Ohio.

. Planning and Coordination of Utility Bulk Power Supplies and Transmission Capacity.. Interview Data,” Ohio Public

Utilities Commission.

• Case Studies on Increasing Transmission Access; Casazza, Schultz & Associates, Inc.

● Case Studies of Transmission Bottlenecks; Casazza, Schultz & Associates, Inc.

. Technological Considerations in Proposed Scenarios; Power Technologies, Inc.

. Technical Background and Considerations in Proposed Wheeling, Transmission Access, and Non-utility Generation;

Power Technologies, Inc.

• Competition and the Role of the Capital Markets in Restructuring the Electric Power Industry; Investor

Responsibility Research Center.

● The Siting of EHV Electric Transmission Lines,- James S. Cannon.

. Environmental Effects of Increased Competition in the Electric Power Industry; Kennedy P. Maize.

• Economic and Planning Implications of the FERC Notice Of Proposed Rulings on Independent Power Producers;

The Energy Center, University of Pennsylvania.

● Survey of Power Industry Competition; OTA.

• Competitive Procurement of Generation Capacity: Summary of Procedures in Selected States; Boston Pacific Co.,

Inc.
Assessments in Progress as of May 1989

Technological Risks and Opportunities for Future U.S. Energy Supply and Demand

High-Temperaturc Superconductors: Research, Development, and Applications

Technology, Innovation, and U.S. Trade

Superfund Implementation

Training in the Workplace: Implication for U.S. Competitiveness

Advanced Space Transportation Technologies

Monitoring and Preventing Accidental Radiation Release at the Nevada Test Site

Agricultural Approaches To Reduce Agrichemical Contaminationof Groundwater in the United States

U.S. Universities and Development Assistance: Technical Support for Agriculture, Natural Resources, and

Environment

Emerging Agricultural Technology and the 1990 Farm Bill

Renewable Resources Planning Technologies for Public Lands

Monitoring of Mandated Vietnam Veteran Studies

Unconventional Cancer Treatments

Drug Labeling in Developing Countries-Phase II

Federal Response to AIDS: Congressional Issues

Preventive Health Services Under Medicare

Adolescent Health

Rural Health Care

Medicare’s Prescription Drug Benefit: Alternative Payment Policies

Methods for Locating and Arranging Health and Long-Term Care Services for Persons With Dementia

New Developments in Neuroscience

Genetic Testing in the Workplace

Forensic Uses of Genetic Tests

Biotechnology in a Global Economy: Options for U.S. Strategy

Communications Systems for an Information Age

Copyright and Home Copying

securities Markets and Information Technology

Information Technology and Research

New Clean Air Act Issues

Catching Our Breath: New Steps for Reducing Urban Ozone

Municipal Solid Waste Management

Managing Low-Level Radioactive Waste

Climate Change: Ozone Depletion and the Greenhouse Effect

Potential for Mineral Resources Development in Antarctica and the Convention of the Regulation of Antarctic

Mineral Resource Activities

Infrastructurc Technologies: Rebuilding the Foundations

Technologies for Lcarning at a Distance

NOTE: For brief descriptions of these studies in pmgxess, see OTA’S booklet on “Assessment Activities’ ’-available from

OTA’S Publications Office, 224-8996.