New Electric Power Technologies:

Problems and Prospects for the 1990s

July 1985

NTIS order #PB86-121746
Recommended Citation:

New Electric Power Technologies: Problems and Prospects for the 1990s (Washington,

DC: U.S. Congress, Office of Technology Assessment, OTA-E-246, July 1985).

Library of Congress Catalog Card Number 85-600568

For sale by the Superintendent of Documents

U.S. Government Printing Office, Washington, DC 20402
Foreword

This report responds to a request from the House Committee on Science and Technology and its Subcommittee on Energy Development and Applications to analyze a range of

new electric power generating, storage, and load management technologies.

OTA examined these technologies in terms of their current and expected cost and performance, potential contribution to new generating capacity, and interconnection with the

electric utility grid. The study analyzes increased use of these technologies as one of a number

of strategies by electric utilities to enhance flexibility in accommodating future uncertainties, The study also addresses the circumstances under which these technologies could play

a significant role in U.S. electric power supply in the 1990s. Finally, alternative Federal policy initiatives for accelerating the commercialization of these technologies are examined,

OTA received substantial help from many organizations and individuals in the course

of this study. We would like to thank the project’s contractors, who prepared some of the

background analysis, the project’s advisory panel and workshop participants, who provided

guidance and extensive critical reviews, and the many additional reviewers who gave their

time to ensure the accuracy of this report.

JOHN H. GIBBONS

Director

. . .

I l l
Related OTA Reports

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NOTE: Reports are available through the U.S. Government Printing Office, Superintendent of Documents, Washington, DC 20402, (202)

783-3238; and the National Technical Information Service, 5285 Port Royal Road, Springfield, VA 22161, (703) 487-4650,
OTA Project Staff—New Electric Power Technologies

Lionel S. Johns, Assistant Director, OTA

Energy, Materials, and International Security Division

Richard E, Rowberg, Energy and Materia/s Program Manager

Project Staff

Peter D. Blair, Project Director

Mary Procterl

David Kathan (Economic and Financial Analysis)

Robert Lempert (Solar Technologies)

Lynn Luderer (Regional Analysis)

David Strom (Interconnection)

Nicholas Sundt (Technologies and Industry Structure)

Administrative Staff

Lillian Chapman Edna Saunders

Contractors and Consultants

Gibbs & Hill, Inc., New York, NY

Battelle Memorial Institute, Columbus, OH

Investor Responsibility Research Center, Inc., Washington, DC

Lotus Consulting Group, Palo Alto, CA

Peter Hunt Associates, Alexandria, VA

Electrotek Concepts, Inc., Mountain View, CA

Strategies Unlimited, Inc., Palo Alto, CA

E. S. Pechan Associates, Washington, DC

Howard Geller, Washington, DC

Paul Maycock, Arlington, VA

David Sheridan, Chevy Chase, MD

Other OTA Contributors

Jenifer Robison Robert M. Friedman Eugene Frankel Paula Wolferseder

‘ Project Director through Mdy 1984
New Electric Power Technologies Advisory Panel

George Seidel, Chairman

Brown University

Edward Blum

Merrill Lynch Capital Markets

Byron R. Brown

El. du Pent de Nemours & Co.

Bill D. Carnahan

City of Fort Collins Light & Power

Mark Cooper

Consumer Federation of America

Brian E. Curry

Northeast Utilities

Janice G. Hamrin

Independent Energy producers

William B. Harrison

Southern Co. Services, inc.

Eric Leber

American Chemical Societyl

Paul Maycock

Photovoltaic Energy Systems

Charles McCarthy

Southern California Edison Co.

Anne F. Mead

New York State Public Service Commission

Alan Miller

World Resources Institute

Bruce W. Morrison

Westinghouse Electric Corp.

Fred Schweppe

Massachusetts Institute of Technology

Jon Veigel

North Carolina Alternative Energy Corp.

I Formerly with the American Public Power Association.

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

vi
Workshop on Regulatory Issues Affecting Developing

Electric Generating Technologies

Sam Brown David Owens Andrew Varley

Virginia Electric Power Co. Edison Electric Institute Iowa Commerce Commission

George Knapp Elizabeth Ross Jon Wellinghoff

Nixon, Hargrove, Devans & Birch, Horton, Bittner, Office of the Attorney General

Doyle Pestinger & Anderson State of Nevada

Therrell Murphy, Jr. Richard Schuler

Southern Co. Services, Inc. Cornell University

Workshop on Investment Decisions for Electric Utilities

James Stukel, Chairman

University of Illinois

jack Davey

Middle South Utilities

Scott Fenn

Investor Responsibility

Research Center, Inc.

Jerry Huck

Illinois Power Co.

Sally Hunt

Consolidated Edison Co.

Jim Liles

Federal Energy Regulatory

Commission

Workshops on Cost

New Electric Power

Lynn Maxwell

Tennessee Valley Authority

Charles Mengers

Philadelphia Electric Co.

Thomas Mockler

Standard & Poor’s

James Mulvaney

Electric Power Research

Institute

Dave J. Roberts

General Public Utilities

Service Corp.

John L. SeeIke

Florida Power & Light

and Performance of

Technologies

James W. Bass, Ill

Tennessee Valley Authority

Robert A. Bell

Consolidated Edison Co.

Elliott Berman

ARCO Solar, Inc.

Chris Bluemle

Southern California Edison Co.

Peter B. Bos

Polydyne Corp.

J.J. Buggy

Westinghouse Electric

Jay Carter, Jr.

Carter Systems

Thomas A.V. Cassel

Technecon Consulting

Inc.

G.P. James Dehlson

Zond Wind Resource

Development

Group,

Sam Shepard

Southern Co. Services, Inc.

Dwain F. Spencer

Electric Power Research

Institute

Rodney Stevenson

University of Wisconsin

Carl Weinberg

Pacific Gas & Electric Co.

H.D. Williamson

Hawaiian Electric Co., Inc.

David R. Wolcott

New York State Energy

Research & Development

Authority

Carel DeWinkel

Wisconsin Power & Light

John Dorsey

Maryland Public Service

Commission

Charles M. Finch

McDonnell Douglas

Astronautics

Richard W. Foster-Pegg

Westinghouse Electric

vii
Robert Greider

Geothermal Resources

International

Ray Hallett

McDonnell Douglas

Astronautics

Waker A. Hansen

Babcock & Wilcox

Bernard Hastings

Detroit Edison Co.

Robert Lacy

San Diego Gas & Electric Co.

Janos Laszlo

ASME Congressional Fellow

Senator Hecht’s Office

Peter Lewis

public Service Electric & Gas

Roger Little

Spire Corp.

William J. McGuirk

Arizona public Service Co.

Tom Morton Jeff Serfass

Fluor Engineers & Constructors, Fuel Cell Users Group

. . . Vlll
Acknowledgments

In addition to panel members and workshop participants, many institutions and individuals contributed to

this report by providing information, advice, and substantive reviews of draft materials. OTA thanks the following who took the time to provide information or review all or part of the study.

Institutions

Applied Economics, Inc.

ARCO Solar Inc.

Argonne National Laboratory

Arizona Public Service Co.

American Public Power Association

Babcock & Wilcox

Battelle Pacific Northwest Laboratories

Birch, Horton, Bittner, Pestinger &

Anderson

Brown-Boveri Corp.

California Energy Commission

Carter Systems

California Energy Commission

Congressional Research Service

Consolidated Edison Co.

Consumer Energy Council of America

Cornell University

Detroit Edison Co.

Edison Electric Institute

Electric Power Research Institute

Electrotek Concepts, Inc.

Energy Conversion Alternatives, Ltd.

Energy Development Associates

Energy Information Administration

Environmental Policy Institute

Environmental Protection Agency

EXXON

Federal Energy Regulatory

Commission

Florida Power & Light

Fluor Engineers & Constructors, Inc.

Fuel Cell Users Group

Individuals

Marshall Alper

Seymour Al pert

Bob Annan

James Arnett

C.J. Aulisio

Shimon Awerbach

Don Bain

Robert Barber

Richard Bellows

Michael Bennet

Sandra Bodmer-Turner

James Bresee

Sam Brown

Larry Bruneel

Doug Carter

Don Cerini

Bill Coleman

Wilfred Comtois

Alice Condren

Marie Corio

George Crane

David Curtice

Mike DeAngeles

Edgar DeMeo

Bruce Edelston

Walter Esselman

Sherman Faire

Merrilee Fellows

Arnold Fickett

Tony Fung

Dom Geraghty

Tom Gray

Leon Green

Robert Hayden

Evan Hughes

Robert Johnson

Alvin Kaufman

Kevin Kelly

Gas Research Institute

General Electric Co.

General Public Utilities Services Corp.

Geothermal Resources International

Hawaiian Electric Co., Inc.

Houston Lighting & Power

Illinois Power C O .

Investor Responsibility Research

Center, Inc.

Iowa Commerce Commission

jet Propulsion Laboratories

Lurgi Corp.

Maryland Public Service Commission

Massachusetts Institute of Technology

McDonnell Douglas Astronautics

Merrill Lynch Capital Markets

Middle South Utilities

National Regulatory Research Institute

New York Consumer Protection Board

New York State Energy Research &

Development Authority

New York State Public Service

Commission

Nixon, Hargrove, Devans & Doyle

North American Electric Reliability

Council

Oak Ridge National Laboratory

Oregon Department of Energy

Pacific Gas & Electric Co.

Philadelphia Electric Co.

Photovoltaic Energy Systems

Polydyne Corp.

Potomac Electric Power Co.

Public Service Electric & Gas

Pyropower Corp.

Renewable Energy Institute

San Diego Gas & Electric Co.

Sandia Laboratories

Scientific Atlanta

Solar Energy Research Institute

Solar Energy Industries Association

Southern California Edison Co.

Southern Co. Services, Inc.

Spire Corp.

Standard & Poor’s

State of Alaska

State of Nevada

Technecon Consulting Group, Inc.

Tennessee Valley Authority

Texas Public Service Commission

U.S. Department of Commerce

U.S. Department of Energy

U.S. Wind power

United Technologies

University of Illinois

University of Wisconsin

Utah Power & Light

W.A. Vachon & Associates

Virginia Power

Westinghouse Electric

Wisconsin Power & Light

Zond Wind Resource Development

Thomas Key

Ron Kukulka

Albert Landgrebe

L. Lilleleht -

E. Lin

Bert Louks

Bob Lynette

Larry Markel

Bill Meade

William Miles

James Mulvaney

James Neely

John Otts

David Owens

John Parkes

James Phillips

Edward Pope

Kevin Porter

Margaret Rands

Tom Reddoch

Joe Reeves

David Rigney

Edward Sabinsky

Dick Salkov

Robert San Martin

Bob Schainker

Peter Schaub

Martin Schlect

Ralph Scott

Jeff Serfass

Bob Sherwin

Harold Sielstad

Fereidoon Sioshansi

Fred Sissine

Jetf Skeer

Al Skinrod

Art Soinski

Bruce St. John

Ian Straughan

David Streets

Fred Strnisa

Tom Tanton

Stratos Tavoulareas

Roger Taylor

James Todd

William Vaughn

Stan Vejtasa

Herman Velasquez

Blaine Vincent

William Wagers

Byron Washon

Michel Wehrey

Richard Woods

F.R. Zaloudek

ix
Contents

Chapter Page

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

I, Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7

2. Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19

3. Electric Utilities in the 1990s: Planning fo ran Uncertain Future . . . . . . . . . . . . . . . . . 41

4. New Technologies for Generating and Storing Electric Power. . . . . . . . . . . . . . . . . . .

5. Conventional Technologies for Electric Utilities in the 1990s . . . . . . . . . . . .........133

6.The Impact of Dispersed Generation Technologies on Utility System

operations and Planning . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..........161

7. Regional Differences Affecting Technology Choices for the 1990s . ..............183

8.Conventional v. Alternative Technologies: Utility and Nonutility Decisions . .......219

9.The Commercial Transition for Developing Electric Technologies. . . .............253

10. Federal Policy Options . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ........285

Appendix A. Cost and Performance Tables . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ......303

Index. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..................323
Overview and Findings

During the 1970s, the environment within

which utilities made investment decisions

changed from a relatively predictable continuation of past trends to a highly uncertain and complicated maze of interrelated financial, regulatory,

and technology considerations. As electric utilities face the 199os, the experiences of the 197os

have made them much more wary of the financial risk of guessing wrong and overcommitting

to large central station coal and nuclear plants.

At the same time, the possibility of being unable

to meet electricity demand exists, causing growing concern among utilities as the next decade

approaches.

As a result, utilities are now taking steps to enhance their flexibility in accommodating future

uncertainties. [n addition to continued and primary reliance on conventional technologies, supplemented by coal combustion technology enhancements to reduce pollution emissions and

increase efficiency, utiIities are considering a variety of less traditional options. These include life

extension and rehabilitation of existing generating

facilities, increased purchases from and shared

construction programs with other utilities, diversification to nontraditional lines of business, increased reliance on less capital-expensive options

such as load management and conservation, and

smaller scale power production from a variety of

conventional and alternative energy sources.

Such options offer utilities the prospects of more

rapid response to demand fluctuations than traditional, central station powerplants.

The Role of New Technologies

This report focuses on a number of alternative

generating technologies, as well as on energy

storage and load management technologies that

are new or have not traditionally been used by

utilities or other power producers. It examines

their technical readiness and the conditions under which they could contribute to meeting electricity demand in the 1990s. The study does not

examine in detail the more traditional technologies of central station coal or nuclear, nor does

it analyze advanced nuclear or combined-cycle

systems and enhancements to pulverized coal

plants such as supercritical boilers, limestone injection, or advanced scrubber systems. In addition, we do not discuss more mature renewable

technologies such as low-head hydropower or

refuse- or wood-fired steam plants. Many of these

options are discussed in other OTA reports. It is

important to note, however, that these traditional

options and their variations are Iikely to remain

the principal choice of electric utilities i n the

1990s.

It is convenient to divide the technologies considered i n this assessment into two basic groups

in order to discuss appropriate policy options:

1.

2.
2 ● New Electric Power Technologies: Problems and Prospects for the 1990s

may be able to realize notable financial benefits

from smaller scale capacity additions, even when

the capital cost per kilowatt of smaller units is as

much as 10 percent more than that of large-scale

capacity additions. other attractive features of

these technologies include reduced environmental impacts, the potential for fewer siting

and regulatory barriers, and improved efficiency

and fuel flexibility.

Despite these long-term advantages, however,

at the current rate of development very few of

these technologies are likely to be deployed extensively enough in the 1990s to make a significant contribution to U.S. electricity supply. In

both groups of technologies, the ultimate goal of

research, development, and demonstration is to

reduce costs and increase performance so that

these new technologies can compete with more

traditional technologies.

For the first group, the likelihood of long

preconstruction and construction lead-times—

up to 10 years— is the primary constraint. Although these technologies have the potential for

much shorter lead-times—5 to 6 years—problems

associated with any new, complex technology

may require construction of a number of plants

before that potential is met. If the longer leadtimes are needed, deployment in the 1990s will

be limited because of the short time remaining

to develop the technologies to a level utilities

would find acceptable for commercial readiness.

Technologies in the second group are likely to

have shorter lead-times and are often smaller in

generating capacity. For most of them to make

a significant contribution in the 1990s, however,

their development will have to be stepped-up

in order to reduce cost to levels acceptable to

utility decisionmakers and nonutility investors,

and to resolve cost and performance uncertainties.

In addition to new generating and storage technologies, load management is being pursued actively by some utilities. Widespread deployment

among utilities in the 1990s, however, will depend on: continued experimentation by utilities

to resolve remaining operational uncertainties;

further refinement of load management equipment including adequate demonstration of communications and load control systems; development of incentive rate structures; and a better

understanding of customer response to different load controls and rate incentives.

For load management as well as certain generating technologies—specifically fuel cells, photovoltaics, solar thermal technologies, and batteries—economies of scale in manufacturing

could reduce cost substantially. Of course, these

reduced costs will not be realized without substantial demand from utilities or other markets.

Finally, the relative advantages of both groups

of new generating technologies and load management varies by region. Factors such as demand

growth rates, age and type of existing generating facilities, natural resource availability, and regulatory climate all influence technology choice

by utility and nonutility power producers.

Steps for Accelerated Development

and Deployment

If electricity demand growth should accelerate

by the early 1990s, the first choice of utilities is

likely to be conventional central station generation capacity. Because of many well-documented

problems, however, there may be severe difficulties in relying on this choice alone and utilities

could face serious problems in meeting demand.

AS a consequence, it may be prudent to accelerate the availability of the technologies discussed

in this study. Although not all the technologies

would be needed under such conditions, if they

were available, the market would be able to offer a more versatile array of choices to electricity producers.

The steps necessary to make these technologies

available vary. With the first group of technologies, it is necessary first to resolve cost and performance uncertainties within the next 5 to 6

years, and then to assure the 5- to 6-year leadtime potential is met for early commercial units.

In the wake the experiences of the last decade,

utility decisionmakers, in particular, are now very

cautious about new technology, and they impose

rigorous performance tests on technology investment alternatives. This conservatism makes advanced commercial demonstration projects even
Overview and Findings ● 3

more important. For the basic designs of the

AFBC, IGCC, and utility-scale geothermal plants,

the current development and demonstration

schedule appears adequate to allow these technologies to be ready by the 1990s. The cooperative industry-government demonstration efforts,

managed by the utilities, have a good track record. The transition from demonstration to early

commercial units, however, will have to be accelerated if the technologies are to produce a

significant amount of electricity in the 1990s.

Moreover, variations in basic designs or more advanced designs to enhance performance characteristics further will require additional research

and development.

Lead-times being experienced by some early

commercial projects in both groups of technologies have been longer than anticipated, partially

due to the time required for regulatory review.

Working closely with regulators and taking steps

to assure quality construction for the early commercial plants could greatly assist the achievement of shorter lead-times. Emphasis on smaller

unit size—200 to 300 MW—wou!d facilitate

these actions.

For the technologies in the second group defined earlier, where cost and performance are

of greatest concern, one approach to accelerating development would be to increase or concentrate Federal research and development

efforts on these technologies. This could be particularly effective for photovoltaics, solar thermal parabolic dishes, and advanced small geothermal designs.

There are other approaches, though, in which

Federal efforts can assist technology development. The reemergence of non utility power production as a growing industry in the United States

is providing, and can continue to provide, an important test bed for some of these new generating technologies. For nonutility power producers, the Renewable Energy Tax Credit (RTC) and

the recovery of full utility avoided costs under

the Public Utility Regulatory Policies Act of 1978

(PURPA) have been crucial in the initial commercial development and deployment of wind

and solar power generating technologies. I n particuIar, with declining direct Federal support for

renewable technology development, the RTC has

supported both development of advanced designs as well as commercial application of mature designs,

Without some continuation of favorable tax

treatment, based either on capacity or production, development of much of the domestic

renewable power technology industry may be significantly delayed. Some technologies such as

geothermal and wind have advanced to the point,

however, where industry probably would continue development, although at a much slower

pace, even if the RTC were withdrawn.

Cooperative agreements among utilities, public utility commissions, and the Federal Government can provide another mechanism for supporting advanced commercial demonstration

projects of technologies from both groups. A

portion of such projects could be financed with

an equity contribution from the utility and the

remainder through a “ratepayer loan” granted

by the public utility commission, possibly guaranteed by the Federal Government,

Other Actions

The rate of deployment of new generating technologies also will be affected by the extent to

which utilities and nonutility power producers

can resolve such issues as interconnection stanciards, coordination with utility resource plans, and

procedures for gaining access to transmission for

interconnection and wheeling of power to customers or other utilities.

The contribution of new generating technologies is likely to be enhanced if utilities are

allowed to enjoy the full benefits afforded to

qualifying facilities under PURPA and if the restrictions on the use of natural gas in power generation are removed. The latter wouId allow the

use of natural gas as an interim fuel during the

development of “clean coal” technologies, and

give utilities and nonutility power producers

added flexibility.

The new generating technologies that appear

to show the most promise for significant deployment in the 1990s are those that can serve ad-
4 ● New Electric Power Technologies: Problems ancl prospects for the 1990s

ditional markets beyond the domestic utility

grid. Such markets are particularly important

while the need for new electric generating capacity is low, and while the cost and performance of these technologies are uncertain in gridconnected applications. Indeed, if priorities must

be set in supporting developing technologies,

it is important to note that broad market appeal

is as important as commercial readiness to their

timely development. In this respect, Federal efforts to help industry exploit foreign markets

could be especially important.

The rate of new generating technology deployment also is tied closely to future trends in

avoided cost and other provisions established by

PURPA, Long-term energy credit and capacity

payment agreements between utilities and nonutility power producers could accelerate deployment. So could mandatory minimum rates or

fixed price schedules for utility payments to nonutility power producers or for use as a basis for

cost recovery by utilities themselves.

Finally, to increase the number of nonutility

power projects employing new electric generating technologies, steps to streamline the mechanisms for wheeling of power through utility service territories might open up new markets for the

electricity they produce and thereby stimulate

their development.
Chapter 1

Introduction
CONTENTS

The

T he

Page

Policy Context . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7

Players . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10

Objectives of This Assessment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12

List of Figures

Figure No. Page

1-1111111-

1-2.

1-3.
Chapter 1

Introduction

THE POLICY CONTEXT

For the U.S. electric power industry, the 1970s

was a decade of unprecedented change. Beginning with the 1973-74 Arab oil embargo, forecasts

of electricity demand growth and costs, based

solely on past trends, proved virtually useless.

Utility decision makers found themselves caught

in a complicated and uncertain maze of interrelated financial, regulatory, and technological

considerate ions.

Utilities had to pay, on average, 240 percent

more for oil and 385 percent more for natural gas,

in real dollars, in 1984 than in 1972. These price

increases drove them to “back out” of oil- and

gas-fired generation and in favor of coal and nuclear plants. Oil dropped from 16 to 5 percent

in the utility fuel mix and gas from 22 to 12 percent between 1972 and 1984. But construction

costs of new powerplants, particularly nuclear,

rose dramatically during this period due to a combination of factors–increased attention to environmental and safety issues (leading to extended

construction lead-times and added equipment

costs), an unpredictable reguIatory environment,

an inflation-driven doubling of the cost of capital, and poor management in some cases. The

higher costs of fuel and capital meant higher electricity costs, and utilities sought higher rates for

the first time in decades. in addition, most utilities seriously underestimated the price elasticity

of electricity demand. Growth in demand plummeted from 7 percent a year to less than 2.5 percent by the end of the decade as consumers used

less electricity and used it more efficiently.

During the 1970s some electric utilities were

brought to the brink of bankruptcy when forced

to cancel large, unneeded powerplants; commitments to these plants had been made long before it was realized that electricity demand had

been overestimated. The eroding revenue base

accompanying declining demand growth coupled with the increasingly costly construction programs already underway left the industry for the

most part struggling financially as bond ratings

and stock prices fell precipitously.

Even now in the mid-l980s, although utilities

have for the most part recovered from the financial trauma of the 1970s, ’ the scars remain. The

process by which utilities initiate, analyze, and

implement investment decisions was changed

fundamentally by the 1970s experience. In the

1960s, power system planners analyzed capacity expansion plans based on life cycle electricity

costs of alternative plans. System planners now

work much more closely with financial planners

to analyze carefully the cash flow of the alternatives as well as the flexibility of alternative plans

i n accommodating unanticipated changes i n demand, capital cost, interest rates, environmental

regulation, and a host of other considerations.

In short, their decisionmaking process has become much more financially cautious as well as

more complex.

While power system planners for most utilities

continue to focus on conventional generating

technologies, as well as advanced combinedcycle systems or enhancements to pulverized

coal plants such as supercritical boilers, limestone

injection, or advanced scrubber systems, they

now consider a much broader range of strategic

options, including: life extension and rehabilitation of existing generating facilities; increased purchases from and shared construction programs

with neighboring utilities; diversification to nontraditional lines of business; increased reliance

on load management; and increased use of smallscale power production from a variety of both

conventional and alternative energy sources. in

1 Actually, even though 1984 was a tery good yedr for utlllty stocki

on average, as of early 1985, uti [ i ties ta I I rough Iy Into t h ree categoric+ o{ stock performance wrne with little or no con~tructton

are q u Ite ~t rong, some m it h IOIV to modest con ~t ruct ion programs

are sta hle but Iac k Iu ster i n performance, and fi na I [y wme w It h large

nuclear taci Ilttes u rider corlstruction (or recently canceled) are \tl II

ciolng very poorly,

7
addition, most utilities have greatly expanded

their conservation programs, both because it now

offers the lowest cost means of meeting demand

in many cases, and it provides the utility with a

way to reduce future demand uncertainty. In considering these various options, utilities hope to

chart an investment course that will enable them

both to meet the largely unpredictable demand

for electricity in the future and to maintain their

financial health.

The most critical legacy of the 1970s is the 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 erratic as well. Users of electricity were

able to alter the quantity they used much more

quickly than utilities could accommodate these

changes with corresponding changes in generating capacity. Moreover, as of 1985, there is saturation in some markets—many major appliances

in homes—and the future of industrial demand

is clouded as many large industrial users of electricity, such as aluminum and bulk chemicals, are

experiencing decline in domestic production due

to foreign competition, At the same time, rapid

growth continues in other areas such as space

conditioning for commercial buildings, industrial

process heat, and electronic office equipment.

predicting the net impact of these offsetting factors, along with trends toward increased efficiency, has greatly complicated the job of forecasting demand,

Since requirements for new generating capacity over the next two decades depends primarily

on electricity demand growth (as well as the rate

at which aging plants are replaced with new capacity and, in some regions, net imports of bulk

power from other regions), planning for new capacity has become a very risky process. To illustrate the demand uncertainty, this assessment

looks at a range of different growth rates–1 .5,

2.5, 3.5, and 4.5 percent increases in average annual electricity demand through the end of the

century. This range is based on analysis carried

in the 1984 OTA study, Nuclear Power in an Age

of. Uncertainty. Figure 1-1 correlates these different demand growth rates with the currently

planned generating capacity for 1993 in the regions of the United States defined by the North

American Electricity Reliability Council (N ERC)–

the NERC regions are defined in figure 1-2. In all

regions, capacity surpluses are now projected by

1993 if annual demand growth is 1.5 percent; and

in seven of the nine regions, there would be capacity surpluses if demand growth is 2.5 percent.

But a 3.5 percent growth rate could mean capacity shortfalls in five of the nine regions; and with

a 4.5 percent growth, there could be shortfalls

in all regions.

At the center of the policy debate over the future of electricity supply is the mix of power generation technologies that will be deployed by either utility or nonutility power producers over the

next several decades. Those anticipating a strong

resurgence in electricity demand in the 1990s

support the building of more large powerplants.

They cite economies of scale of such plants that,

in their view, would minimize electricity costs

over the long run. Others, who believe demand

growth to be more uncertain, favor a strategy of

flexibility which includes the possibility of smallscale capacity additions as well as increased reliance on other methods of dealing with demand

uncertainty such as conservation and load management.

Complicating this controversy is the utilities’

evolving attitude toward new technology, another

consequence of the 1970s. While traditionally

conservative in adopting new technology, the

electric utility industry has grown particularly cautious in the wake of its experience with nuclear

power. Utilities now impose rigorous economic

performance tests on new technology investments. Perhaps because of this caution, projects

initiated by nonutility power producers under the

Public Utility Regulatory Policies Act (PURPA)

since 1978 have served as the principal test bed

for first generation commercial applications of

many new generating technologies.
Ch. I—introduction ● 9

Figure l-l.— 1993 U.S. Generating Capacity Surplus or Shortfall

Under Alternative Peak Load Growth Scenariosa

25

20

15

10

5

0

-5

-lo

-15

-20

U.S. peak demand growthb

L
10 ● New Electric Power Technologies: Problems and Prospects for the 1990s

—

Figure l-2.—Map of North American Electric Reliability Council (NERC) Regions

~ ~

THE PLAYERS

Any Federal policy decision affecting the elec- These participants, depicted in figure 1-3, are as

tric power industry affects a wide range of inter- follows:

ests. The changing conditions of the 1970s along

with increased activity in new technology development have increased the number of partici- ●

pants who affect the industry. Each brings a very

different perspective to electricity policy issues,

especially with respect to new technologies.

Electric utilities, both public and investor

owned, differ widely in financial health, existing facilities and fuel use, and in their attitudes toward new technology.
●

●

SOURCE: Off Ice of Technology Assessment,

●

●

construction programs, as well as toward

new technology. -

Federal regulators such as the Federal Energy Regulatory Commission, the Nuclear

Regulatory Commission, and the Environmental Protection Agency, in carrying out

their assigned missions, affect the electric

power industry profoundly. The prospect of

extensive deployment of new technologies

over the next several decades may hinge as

much on the regulations promulgated by

these agencies as on the competitive cost

and performance of the technologies.

Ratepayers’ response to electricity prices as

well as their attitudes on issues such as nuclear power costs, nuclear safety, coal pollution, and acid rain, etc., will play major

roles in determining the future of the electric power industry. In particular, ratepayers’

response to prices—i.e., their demand for
72 . New E/ectric Power Technologies: Problems and Prospects for the 1990s

electricity, and attitudes on electricity supply-related issues–will largely determine the

technologies that will be employed in power

generation.

● Investors’ attitudes on the comparative risks

in selecting future utility and nonutility

power generation projects are important

considerations and will affect the financial

health of both industries. As the utility industry recovers from a financially troubled

period, the degree to which investors are

willing to put their money into large new

generating plants again will greatly affect utility investment decisions. Similarly, the access

of new electricity-generating technologies to

traditional (other than venture) capital sources,

which is so critical to the continued development of many of these technologies, will

depend on investors’ perceptions of the technologies’ cost and performance prospects.

Ž Vendors of conventional power generating

technology have enjoyed a long relationship

with the electric utility industry, This relationship heavily influences new technology investment decisions.

● Vendors of developing technologies include

many businesses that have not traditionally

dealt with the electric utility industry. New

technology developers, which in many cases

also include traditional vendors, range from

giant petroleum companies and aerospace

firms to small independent firms. In many

cases, the newcomers are only beginning to

establish working business relationships with

electric utilities and other nonutility power

producers. For some technologies, these

firms are much more diverse in terms of age,

size, financial position, etc., than conventional technology vendors. The relationship

between such firms and the utilities as well

as non utility power producers is still evolving and will affect future investment decisions.

● Research and development (R&D) establishments such as the U.S. Department of

Energy and the Electric Power Research institute (EPRI) are now important forces in the

development of new electric power technologies, Traditionally, until the 1970s, research,

development, and demonstration of new

electric power technologies was primarily

within the province of a handful of equipment vendors cited above, i n some cases

supported by the Federal Government. Increasing Federal involvement in energy R&D

in the 1970s and establishment of EPRI in

1972 contributed to expanding the range of

public and private entities involved in commercial development of new electric technologies.

OBJECTIVES OF THIS ASSESSMENT

Electric power supply issues have been actively

discussed in recent years in Congress as well as

by regulators, electric utilities, and other interested parties. All parties have expressed renewed

interest in alternatives to large, long lead-time

powerplants. In 1981 the House Committee on

Banking, Finance, and Urban Affairs requested

that OTA examine the prospects of small power

generation in the United States, citing that:

. . . considerations of energy policy have not

taken adequately into account the possibilities

of decentralizing part of America’s electrical generating capabilities by distributing them within

urban and other communities.

At this time, the effects of the implementation

of PURPA were beginning to appear. This act defined a role for grid-connected, nonutility small

power producers in U.S. electricity generation,

requiring utilities to interconnect and pay these

producers for electricity provided to the grid.

During the early 1980s, it became clear that the

most active nonutility area of small power production would be (and still is) industrial cogeneration of steam and electricity. Consequently,

in 1983 in response to the Banking Committee’s

request, OTA completed an assessment of industrial and commercial cogeneration.2
As the cogeneration assessment was underway,

the effects of errors in electricity demand forecasts and continued demand uncertainty on utility decision making were beginning to be felt

throughout the industry as proposed new plants

were canceled or deferred indefinitely. These

cancellations were particularly damaging to the

nuclear power industry which was already struggling to deal with increasing public opposition.

OTA completed an assessment of the future of

nuclear power which was released early in 1984. s

In the course of that study, the possibility of resurgent electricity demand growth in the 1990s (argued by some as quite likely) was raised as a very

difficult planning issue for the utility industry, particularly if utilities continued to rely on large powerplants at a time when they were financially

stressed. To address these issues and to explore

benefits of small-scale, shot-t lead-time alternatives

to central station powerplants, the House Science

and Technology Committee requested that OTA

examine the status of such technologies as photovoltaics, fuel cells, wind turbines, selected

geothermal technologies, solar thermal-electric

powerplants, atmospheric fluidized-bed combustors, coal gasification/combined-cycle plants,

advanced utility-scale electricity storage technologies, and load management.

In response, in late 1983 OTA undertook this

assessment of developing electric generating

technologies. The assessment addresses four major issues:

1..

2

What is the current status of new electric

generating technologies compared with conventional alternatives and how is their status likely to change over the next 10 to 15

years? I n addition, what are the most promising R&D opportunities that could affect the

deployment of these technologies over this

period and beyond?

What is the nature of the industry supporting these technologies (vendors and manufacturers)? And how sensitive is their viability to electric utility orders over the next 10

to 15 years, Federal support (e.g., tax incen3.

4.

tives and/or demonstration programs), and

foreign competition?

What are the regional differences that affect

the attractiveness of these technologies to

electric utilities and nonutility power producers, particularly compared to other strategic

options in those regions such as increased

purchases of power from neighboring utilities, life extension of existing facilities, conservation, and so on?

What are the alternative public policy initiatives (e. g., tax credits, loan guarantees,

demonstration projects, etc.) for accelerating the commercial viability of these technologies?

This OTA assessment focuses on the group of

newer developing generating technologies that,

while not fully mature, couId figure importantly,

under some scenarios, in the plans of utility or

nonutility producers in the 1990s. Those technologies considered relatively mature including conventional coal and nuclear plants, conventional

gas turbines, conventional combined-cycle plants,

biomass technologies, vapor-dominated geothermal technology, low-head hydroelectric faciIities,

and others are not considered in detail. It is important to note, however, that in many cases

these technologies are the principal benchmarks

against which the technologies considered here

will be compared in the 1990s. Also not considered are technologies not likely to contribute

significantly to the U.S. generation mix by the

1990s—e.g,, fusion, ocean thermal energy conversion, magneto hydrodynamics, and therm ionic

energy conversion.

This assessment was carried out with the assistance of a large number of experts reflecting

different perspectives on the electric power

industry—utility executives, system planners, financial planners, State public utility commissioners, environmental and consumer groups,

Federal regulators, engineers, technology vendors, nonutility small power producers, and the

financial community. As with all OTA studies, an

advisory panel comprised of representatives from

all these groups met periodically throughout the

course of the assessment to review and critique

interim products and this report, and to discuss

fundamental issues affecting the analysis. Con-
14 ● New Electric power Technologies: Problems and Prospects for the 1990s

tractors and consultants also provided a wide

range of material in support of the assessment.

Finally, OTA convened a series of workshops

to clarify important issues to be considered in the

assessment and to review and expand upon contractors’ analyses.

The first workshop dealt with investment decisionmaking in the electric utility industry. It focused on how the decision making environment

is changing in the industry and on identifying the

principal considerations by utilities in making new

technology investments. in addition, the workshop addressed utility approaches to accommodating non utility power production, the Federal

role i n commercialization of new electric power

generating technologies, and major policy contingencies that could affect the relative attractiveness of alternative generating technologies over

the next several decades. For example, such contingencies as acid rain control policies and increased availability of natural gas for electric

power generation were considered.

About midway into the assessment, OTA convened a series of seven workshops dealing with

the cost and performance of new generating and

load management technologies. These workshops reviewed and refined the benchmark cost

and performance figures generated by OTA contractors and identified the most important R&D

opportunities necessary for continued advancement of the technologies being considered. The

results of these workshops, coupled with the subsequent contractor and OTA staff analyses, formed

the basis of the comparative assessment of generating technologies and the likelihood of their

contributing significantly to U.S. electric power

generation in the next two decades under various policy scenarios.

The final workshop convened in the course of

this assessment dealt with economic regulatory

issues affecting the development and deployment

of new generating technologies. The principal issues addressed were regulatory treatment of research and development by electric utilities, implementation of PURPA, regulation of affiliated

electric utility interests involved in new generating technology, and scenarios for deregulating

electric power production.

Based on the workshop discussions, advisory

panel recommendations, contractor and consultant reports, and OTA staff research, a set of

alternative policy options were developed and

analyzed. Advisory panel members, workshop

participants, contractors, and other contributors

to this assessment are listed in the front of this

report.

This report is organized as follows:

●

●

●

●

●

●

●

Chapter 2 is a summary of the entire report.

Chapter 3 establishes the context in which

electric utility investment decisions are made.

In particular, it examines the range of strategic options being considered by utilities

and the relative importance of new generating technologies with those options.

Chapter 4 defines plausible ranges of cost,

performance, uncertainty, and risk which are

likely to characterize new electric generating and storage technologies in the 1990s,

In addition, the prominent R&D needs are

identified and discussed.

Chapter 5 establishes benchmark cost and

performance figures for the conventional

technologies against which the new technologies are likely to compete over the next two

decades. In addition, the prospects for rehabilitating or extending the lives of existing

generating facilities and for increased reliance on load management as alternatives to

new generating capacity are considered.

Chapter 6 discusses the impact of decentralized power generation on the performance of electric power systems. The focus

is on questions of standards for and costs of

interconnecting such sources with the grid

as well the effects of increasing penetration

of such sources on power system control,

operation, and planning.

Chapter 7 analyzes the differences among

U.S. regions that could influence the potential usefulness of new electric generating

technologies in those regions. The principal

differences include electricity demand growth

and peaks, existing fuel use and generating

facilities, indigenous energy resources, and

interregional transmission capabilities.

Chapter 8 compares the competitiveness of

new technologies with conventional tech nol-
Ch. 7—/ntroduction ● 1 5

ogies, I n particular, the sensitivity of investments in different technologies to factors

such as demand growth, construction lead

time, cost and performance, Federal tax policy, and environmental regulation.

● Chapter 9 examines the industry supporting

new generating and load management technologies. For each of the technologies considered, the market infrastructure, obstacles

to domestic industry development, alternative development paths, and foreign competition are discussed.

● Chapter 10 presents a n u m ber of a Iterative

policy options that cou Id affect the development of new electric power generating and

load management technologies over the next

two decades. The implications of different

policy strategies employing these options are

discussed.
Chapter 2

Summary
CONTENTS

Introduction. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

New Generating Technologies for the 1990s . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Cost and Performance. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Lead-Times . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Specific Generating Technologies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Conventional Alternatives in the 1990s. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

New Capacity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Plant Betterment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Load Management. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

impact of Dispersed Generating Technologies on System Operation . . . . . . . . .

Nonutility Interconnection Standards . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Interconnection Costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

19

19

21

21

22

25

25

25

25

29

29

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

-

2 9

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

Existing Generation Mix . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Interregional Bulk Power Transactions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Load Management . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Reliability Criteria . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Renewable Resources . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Utility and Nonutility Investment Decisions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Utility Investment . . . . . . . . . . . . . . . . . . . . . . . . . .

Nonutility Investment . . . . . . . . . . . . . . . . . . . . . . .

Current and Future State of Alternative Technology

Federal Policy Options.. . . . . . . . . . . . . . . . .....

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

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

ndustry. . . . . . . . . . . . . . . .

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

Research, Development, and Demonstration . . . . . . .....+... . . . . . . . . . . . .

Other Policy Actions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Renewable Energy Tax Credits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

29

29

30

30

30

31

31

31

32

32

33

33

35

36

List of Tables

Tab/e/We. Page

2-1 . Selected Alternative Generating and Storage Technologies:

Typical Sizes and Applications in the 1990s . . . . . . . . . . . . . . . . . . . . . . . . . .

2-2. Areas of Principal Research Opportunities:

Developing Technologies for the 1990s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

2-3. Developing Technologies: Major Electric Plants Installed or

Under Construction by May 1, 1985 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

2-4. Policy Goals and Options . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

List of Figures

21

26

27

34

Figure No. Page

2-1. Tax Incentives for New Electric Generating Technologies: Cumulative

Effecton Real Internal Rate of Return . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37
Chapter 2

Summary

INTRODUCTION

As utilities face the 1990s, the experiences of

the 1970s have made them much more wary of

the financial risk of guessing wrong and overcommitting to large central station coal and nuclear plants. At the same time, there is growing

concern by utilities about the possibility of being unable to meet demand, particuIarly in view

of increased uncertainty about future demand

growth. In addition, the provisions of the Public

Utility Regulatory Policies Act of 1978 (PURPA),

have made the role of non utility power producers increasingly important to the future of U.S.

electricity supply. As discussed in chapter 1, one

of the strategies being pursued by utilities to operate in this new environment is through increased

utilization of smaller scale power production by

a variety of both conventional and nontraditional

energy conversion technologies.

if electricity demand grows at an average annual rate below 2.5 percent through the 1990s

(current estimates range from 1 to 5 percent), the

need for new generating capacity is likely to be

relatively modest. Responses that include life extension and rehabilitation, increased power purchases, and construction of realizable amounts

of conventional generation are likely to suffice.

But if demand growth should accelerate, these

options may not be enough, and the availability

of an array of generating technologies that provide a utility with greater flexibility for meeting

load requirements may be desirable.

NEW GENERATING TECHNOLOGIES FOR THE 1990s

A number of developing technologies for electric power generation are beginning to show considerable promise as future electricity supply

options. Some of these technologies, such as

atmospheric fluidized-bed combustion (AFBC)

and integrated coal gasificatiordcombined-cycle

(IGCQ conversion, and fuel cells, could pave the

way for clean and more efficient power generation using domestic coal resources.

In box 2A, the renewable and nonrenewable

technologies considered in this assessment are

listed and briefly discussed. Table 2-1 shows those

technologies grouped according to the sizes and

applications in which they would most likely appear if deployed during the 1990s. Also shown

in the table are the principal conventional alternatives against which these technologies are most

likely to compete. Applications are divided between those in which electrical power output is

controlled by the utility (dispatchable) and those

where it is not (nondispatchable). Dispatchable

applications are further broken down into base,

intermediate, and peaking duty cycles. Nondispatchable applications are divided between those

with and without storage capabilities.

Many of these technologies offer modular

design features that eventually could allow utilities to add generating capability in small increments with short lead-times and less concentration of financial capital. Other attractive

features common to some but not all of these

technologies include fewer siting and regulatory

barriers, reduced environmental impact, and increased fuel flexibility and diversity. Virtually all

of the technologies considered in this assessment

offer the potential of sizable deployment in electric power generation applications beyond the

turn of the century. At the current rate of development, however, most developing technologies will not be in a position to contribute more

19

Ch. 2—Summary ● 2 1

Installation

size (MW)

Greater than

250 MWe

51-250 MWe

1-50 MWE

Less than

1 MWe

Table 2-1 .—Selected Alternative Generating and Storage Technologies:

Typical Sizes and Applications in the 1990s

Typical configurations in the 1990s

Dispatchable applications

Base load Intermediate load Peaking load

(60-700/0 CF) (30-400/0 CF) (&150/o)

Geothermal Atmosphere fluidized- Compressed air storage

bed combustor (maxi CAES)

Atmospheric fiuidized- Compressed air storage

bed combustor (maxi CAES) Solar thermal (w/storage)

Geothermal Fuel cells Compressed air storage

Atmospheric fluidized- Compressed air storage (mini CAES)

bed combustor (maxi CAES) Battery storage

Fuel ceils Solar thermal (w/storage) Fuel cells

Solar thermal (w/storage)

Nondispatchable applicationsb

Intermittent Others

(w/o storage) (not utility controlled)

Solar thermal Atmospheric fluidizedWind bed combustor

Solar thermal (w/storage)

Solar thermal Atmospheric fluidizedWind bed combustor

Photovoltaics Geothermal

Fuel cells

Solar thermal (w/storage)

Battery storage

Compressed air storage

(mini CAES)

Geothermal

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

Combustion turbine

Solar thermal Fuel cells

Wind Battery storage

Photovoltaics

SOURCE. Office of Technology Assessment

than a few percent of total U.S. electric generating capacity in the 1990s, and therefore, will

not be of much help in meeting accelerated demand, should it occur.2

Cost and Performance

The current cost and performance characteristics (including the uncertainty in both cost and

performance) of most new technologies are not

generally competitive with conventional alternatives. s Cost reductions, performance improvements, and resolution of uncertainties will all occur as these technologies mature. The rate at

‘Here and elsewhere in this report, a contribution to U.S. electricity supply is considered “significant” when it amounts to more

than 5 to 10 percent of total generating capacity, or the equivalent

in terms of electricity storage or reduced demand.

31 n pa~icu Iar, with conventional generating capacity in smaller

unit sizes such as conventional combustion turbines, advanced

combined cycle plants, slow-speed diesels, and participation in conventional cogeneratlon projects.

which this maturity occurs depends on: 1 ) sustained progress in research, development, and

demonstration to reduce cost, improve performance, and reduce uncertainty in both cost and

performance; and 2) continued active demonstration of the technologies, particularly in utility applications to develop the commercial operating

experience necessary before utility decisionmakers will consider a new technology seriously.

Utility and nonutility interest in these technologies is also affected by a wide range of other

factors relating to environmental benefits, siting

requirements, and public acceptance.

Lead-Times

Common to the deployment of all electric generating technologies is the need for planning, design, licensing, permitting, other preconstruction

activities, and finally construction itself. These

steps with some technologies, for early units at
22 . New Electric Power Technologies: Problems and Prospects for the 1990s

a minimum, may take long periods of time—up

to 10 years or more. This means that if those technologies still undergoing development are to be

commercially deployed in the 1990s, there may

be as little as 5 or 6 years in which to complete

development and establish in the minds of investors that their costs, performance, and other attributes fall within acceptable ranges.

Specific Generating Technologies

The relative importance of efforts to improve

cost and performance versus the need to shorten

lead-times in order to attain commercial status

varies by technology. This distinction, i n particular, makes it convenient to divide the technologies considered here into two basic groups:

1.

2.

In

The first consists of technologies envisioned

primarily for direct electric utility applications, and includes IGCC plants; large (> 100

MW) AFBC; large ( >100 MW) compressed

air energy storage (CAES) facilities; large

(>50 MW) geothermal plants; utility-owned

fuel cell powerplants; and solar thermal central receivers.

The second group consists of technologies

that are characterized as suitable either for

utility or nonutility applications, and includes

small ( <100 MW) AFBCs in nonutility cogeneration applications; fuel cells small

(< 100 MW) CAES; small ( <50 MW) geothermal plants; batteries; wind; and direct

solar power generating technologies such as

photovoltaics and parabolic dish solar thermal.

both groups, the goal of research, development, and demonstration is to improve cost and

performance characteristics to a point where the

technologies are commercially competitive. For

the first group of technologies, however, the

likelihood of long lead-times for early commercial units is the primary constraint to extensive

use in the 1990s. Technologies in the second

group are likely to have shorter lead-times and

are often smaller in generating capacity. For most

of them to make a significant contribution in the

199os, however, their research, development,

and demonstration will have to be stepped-up

in order to reduce cost to levels acceptable to

utility decision makers and nonutility investors,

and resolve cost and performance uncertainties.

It is important to note that the distinction between these two groups of technologies is not

rigid. Technologies in the first group also could

benefit from accelerated research and development while those in the second group could be

held back by long lead-times.

In addition, many of the technologies in the

second group are small enough to qualify as small

power producers employed in nonutility power

generating projects operating under the provisions of PURPA. The existence of a wide variety

of markets and interested investors outside the

electric utilities increases the likelihood that at

least some of these technologies will be deployed.

Because of its modular nature and positive

environmental features, the IGCC has the potential for deployment lead-times of no more than

5 to 6 years. Early commercial units, however,

may require longer times—up to 10 years—

because of regulatory delays, construction problems, and operational difficulties associated with

any new, complex technology; and it may take

a number of commercial plants before the short

lead-time potential of the IGCC is realized. In addition, despite the success of the Cool Water

demonstration project, a 100 MWe IGCC plant

that has increased electric utility confidence in

the technology, more operating experience is

likely to be required before there will be major

commitment to the IGCC by a cautious electric

utility industry. Therefore, unless strong steps are

taken to work closely with regulators and to assure quality construction for these initial plants,

there may be insufficient time remaining after

utilities finally make a large commitment to the

IGCC for the technology to make a significant

contribution before 2000. As has been shown

in the Cool Water project, though, such steps are

possible, and they may be facilitated if initial commercial units are in the 200 to 300 MWe range

rather than the current design target of 500 MWe.

The first large (about 150 MW), “grass-roots”

(i.e., not retrofits of existing facilities) AFBC installations for generating electricity also may be
Ch. 2—Summary . 23

subject to long lead-times. Moreover, a large

AFBC demonstration unit probably will not even

be operating until 1989. It now appears unlikely

that the operation of that unit will be sufficient

to justify large numbers of orders within the first

few years of the 1990s. The AFBC, however, also

has the potential for needing lead-times on the

order of only 5 years. Further, favorable experience with smaller AFBC cogeneration units and

AFBC retrofit units which will be in service by

1990 may provide the commercial experience

needed to accelerate deployment of the larger

units.

Foremost among new technologies offering

the potential of significant deployment in the

1990s are small (below 100 MWe) AFBC plants

in cogeneration applications and larger (100 to

200 MWe) AFBC retrofits to existing coal-fired

powerplants. By 1990, plants of both types will

be operating. Over a dozen commercial cogeneration plants using AFBC have been started by

non utilities, and two large utility retrofit projects

are underway. These first plants appear capable

of producing electricity at lower costs than their

solid-fuel burning competitors (including the

IGCC and large, electric-only, grass-roots AFBCs)

in the 1990s. The prospects are good that additional orders—perhaps mostly from nonutilities—

will be forthcoming and that large numbers of

these AFBC units could be operating by the end

of the century.

While the prospects for wind turbines are

clouded by the anticipated termination of the

Renewable Energy Tax Credits (RTC) and other

potential tax changes, the outlook nevertheless

appears promising. By the end of 1984, an estimated 650 MWe were in place in wind farms in

the United States, mostly in California (550

MWe). Over the early 1980s, capital costs have

dropped rapidly and performance improved

swiftly, Improvements are expected to continue,

and the cost of electric power from wind turbines, even unsubsidized ones, in high-wind

parts of the country may soon be considerably

lower than power from many of their competitors. The rate of improvement will be heavily influenced by future trends in the avoided costs or

“buy-back rates” offered by utilities to nonutility electricity producers. Should these costs be

low or uncertain, technological development and

application will be slowed. Conversely, high

avoided costs, stimulated perhaps by rising oil

and gas prices or shrinking reserve margins of

generating capacity, might considerably accelerate their contribution.

Although geothermal development has been

substantial compared to other technologies, most

of this development has occurred at The Geysers

in California, an unusual high-quality dry steam

resource (one of only seven known in the world)

that can be tapped with mature technology. All

other geothermal resources in the United States

require less developed technology to generate

power. Two developing geothermal technologies,

though, are currently being demonstrated on a

small scale and show promise for commercial applications in the West. Current evidence indicates

that these technologies—dual flash and binary

systems—are very close to being commercial, and

that cost and performance will be competitive.

Small binary units (about 10 MWe) are already

being deployed commercially. These developments, coupled with the fact that the technologies

can be put in place with lead-times of 5 years or

less, suggest that they could produce considerable electric power in the West by the end of the

century. As is the case with wind power, t he

growth rate of geothermal power will be sensitive to Federal and Mate tax policy.

Initial commercial application of fuel cells

should appear in the early 1990s, primarily fired

with natural gas. The large and potentially varied market (it includes both gas and electric utilities as well as cogenerators), the very short leadtimes, factory fabrication of components, and a

variety of operational and environmental benefits all suggest that when cost and performance

of fuel cell powerplants become acceptable, deployment could proceed rapidly. The principal

obstacle to fuel cells making a significant contribution seems to be insufficient initial demand

to justify their mass production. For such demand to appear in the 1990s, extensive commercial demonstration in the late 1980s will probably

be necessary,

The development rate of photovoltaics (PV)

has been considerable in recent years, but the

technical challenge of developing a PV module

38-743 0 - 85 - 2
24 . New Electric Power Technologies: Problems and Prospects for the 1990s

that is efficient, long-lasting, and inexpensive

remains. While technical progress and deployment of photovoltaics in the United States are

likely to be slowed by termination of the RTC or

by other changes in Federal or State tax law, or

by declining avoided costs, industry activity is

likely to remain intense. Aided by interim markets of specialized applications and consumer

electronics, PVS could develop to the point where

competitive grid-connected applications at least

begin to appear in the 1990s. In the 1990s, overseas markets may dominate the industry’s attention, stimulating and supporting improvements

in cost and performance, and encouraging mass

production to further reduce costs. However,

European and Japanese vendors, assisted by their

respective governments, have been more successful than U.S. vendors in developing these

markets, Foreign competition is likely to be a

major concern for U.S. vendors over the next

decade.

Of the solar thermal technologies, solar parabolic dish technologies offer the most promise

over the next 10 to 15 years; although with current uncertainty in cost and performance, solar

troughs may be competitive as well. Characteristics of some solar dish and trough designs indicate that they could be rapidly put in place in

areas such as the Southwest. The cost of power

generation using these designs in such regions

could be very close to those of conventional alternatives. Some demonstration and subsidized

commercial units already are operating. Full commercial application, however, will require further demonstrations of the technologies over extended periods of time; such demonstrations

must be started no later than 1990 if the technologies are to be considered seriously by investors in the 1990s. The likelihood of such

demonstrations appears now to depend on the

availability of some kind of subsidy. In particular, development of the technology to date has

depended heavily on the RTC.

Other solar thermal technologies, including

central receivers and solar ponds, while showing long-term promise, are unlikely to be competitive with other electric generating alternatives

or have sufficient commercial demonstration experience to yield any significant contribution

through the 1990s. The central receiver, however, is of continuing interest to a some Southwestern utilities in the long term because it offers

a favorable combination of advantages including

the potential for repowering applications, high

efficiency, and storage capabilities.

Along with new generating technologies, this

assessment examined two electric energy storage

technologies—compressed air energy storage

(CAES) and batteries–that show long-term promise in electric utility applications.

Because of potentially long lead-times, CAES

appears to have only limited prospects in the

1990s. The large-scale ( >100 MW) version of this

technology (called maxi-CAES) currently has an

estimated lead-time of 5 to 8 years; of this, licensing and permitting and other preconstruction

activities is expected to take 2 to 4 years. Moreover, while commercial installations are operating in Europe, no plant yet exists in the United

States. Despite strong evidence that this technology offers an economic storage option, CAES is

unlikely to be the target of much investment until a demonstration plant is built. No plans for a

demonstration plant currently exist. Further,

while a demonstration project should prove the

technology, the peculiar underground siting

problems and unfamiliarity with the CAES concept may still limit early application.

A smaller alternative–mini-CAES ( <100 MW)

–promises to have a much shorter lead-time due

to modularity of the above-ground facilities and

short (30-month) construction lead-times. Here

too, however, unless a demonstration plant is

started in the next few years, extensive deployment before the end of the century is improbable.

Resolution of a variety of cost and performance

uncertainties remains before extensive use of advanced battery storage systems can be anticipated. If the technical problems can be resolved

i n a timely fashion and demonstration programs

are successful, however, rapid deployment in

electric utility applications could occur, due to

the short lead-times and cost reductions associated with mass production. Of the candidates,

lead-acid and zinc-halogen batteries appear to

show the most promise.
Ch. 2—Summary ● 2 5

Table 2-2 summarizes the most promising areas velopment through the 1990s. Table 2-3 summaof research and development identified by OTA rizes the major electric power generating projects

for the technologies analyzed in this assessment. utilizing these technologies installed or under

Atention to these research and development op- construction as of May 1985.

portunities could accelerate commercial their deCONVENTIONAL ALTERNATIVES IN THE 1990s

The contribution of developing technologies

over the next two decades depends in part on

the relative cost and performance of conventional

generating options as well as a variety of options

for extending the lives or otherwise improving the

performance of existing generating facilities.

New Capacity

To the extent that new generating capacity is

needed at all over the next two decades, conventional pulverized coal plants, combustion

turbines, and advanced combined-cycle plants

will continue to be the principal benchmark

against which utilities and others will compare

developing generating technologies. Utilities are

very interested, however, in smaller unit sizes

of even these technologies. Also, if nuclear

power is to become a realizable choice again for

utilities, it is likely to involve smaller, standardized units.

If hydroelectric opportunities are available, they

are likely to be exploited in both run-of-river and

pumped storage applications; few new hydroelectric opportunities, though, are likely through

the 1990s. Similarly, refuse steam plants, biomass

technologies (e. g., wood waste-fired power generation), slow-speed diesels, and vapor-dominated geothermal plants all use mature technologies so that where opportunities exist, they are

likely to be chosen over newer technologies.

In addition, enhancements to conventional

plants such as limestone injection in coal boilers,

coal-water fuel mixtures, and others will all be

reviewed carefully along with new generating

technologies as utilities plan for new capacity.

The availability of such enhancements could significantly affect the relative attractiveness of new

technologies in the 1990s.

Plant Betterment

By 1995, the U.S. fossil steam capacity will

have aged to the point where over a quarter of

the coal and nearly half of the oil and gas steam

units nationwide will be over 30 years old. In

the past, the benefits of new technology often

outweighed the benefits of extending the useful

lives of existing generating facilities, rehabilitating such facilities to improve performance or upgrade capacity, or even repowering such plants

with alternative fuels. Ail of these so-called plant

betterment options are receiving renewed interest by utilities because plants “reaching their 30th

birthday” over the next decade have attractive

unit sizes (100 MW or larger) and performance

(heat rates close to 10,000 Btu/kWh). For that reason, rehabilitating or simply extending the lives

of such units, frequently at much lower anticipated capital costs than that of new capacity,

are often very attractive options for many utilities. Prospects are particularly bright if units are

located at sites close to load centers and the rehabilitation does not trigger application of New

Source Performance Standards, i.e., more stringent air pollution controls.

In many instances, plant betterment can also

improve efficiency up to 5 to 10 percent and/or

upgrade capacity. Additional benefits from such

projects include possible improvements in fuel

flexibility or reduced emissions of existing generating units at modest cost relative to that of new

capacity. Finally, an initial market for some new

technologies such as the AFBC are in repowering applications, e.g., where an existing pulverized coal plant is retrofitted with an AFBC boiIer.

Load Management

Load management refers to manipulation of

customer demand by economic and/or techni-
26 ● New Electric Power Technologies: Problems and Prospects for the 1990s

Wind:

1. Development of aerodynamic prediction codes

2. Development of structural dynamic codes

3. Fatigue research

4. Wind-farm wake effects

5. Development of acoustic prediction codes

Solar thermal electric:

General:

1. Low cost, reliable tracking hardware

Solar ponds:

1. Physics and chemistry

2. Design and performance analysis

3. Construction techniques

4. Operation and maintenance

Central receivers:

1. Physics and chemistry

2. Development and long-term testing of cheap and

durable scaled-up molten-salt subsystems (including

receiver, pumps, valves, and pipes)

Parabolic dishes:

1. Durable engines

2. Cheap, high-quality, durable reflective materials

(polymers)

3. Long-life Stirling and Brayton heat engines

Parabolic troughs:

1. Inexpensive, long-lived, high-temperature thermalstorage media

2. Cheap, leak-resistant, well-insulated receiver-tubes

3. Cheap, high-quality, durable reflective materials

(polymers)

Photovo/talcs:

1. Highly efficient, long-lived, mass-produced cells;

especially those suitable for use with concentrators

2. Cheap semiconductor-grade silicon

3. Cheap, durable, and reliable modules and module

subcomponents (especially the optics and cell

mounts for concentrator modules)

4. Reliable, inexpensive and durable “balance of

systems, ” especially tracking systems and power

conditioners

Fluidlzed-bed combustors:

Circulating-bed AFBCS:

1. Cheap, durable, and reliable equipment for

separating solids from gas streat

2. Erosion- and corrosion-resistant materials and

designs

Bubbling-bed AFBCs:

1. Adequate sulfur capture by limestone sorbent

2. Effective fuel-feed systems

3. Erosion- and corrosion-resistant materiais and

designs

Integrated gasificatlon/combined.cycie:

1. Cheap, durable, reliable, and efficient combustion

turbines and combined-cycle systems

2. Erosion- and corrosion-resistant materials

3. Gasifiers capable of effectively converting a variety

of fuels

1.

2.

3.

4.

5.

Corrosion-resistant equipment (especially turbine

blades and underground equipment)

Durable, reliable, and inexpensive recuperator

(recuperator discharges heat from combustion

turbine gases to incoming compressed air)

Lower cost of existing underground storage sites

Improved recovery of compression heat

Geologic response to air cycling in reservoir

Load management technologies:

Meters:

1. Mass-produced, inexpensive, durable, reliable solidstate devices capable of operating in adverse

environments

2. Meter capable of sustaining operation during power

outages

Communications systems:

1. Inexpensive, reliable, and durable residential

receivers or transponders

Logic systems:

1. Development of appropriate software

Fuel cells:

1. Lower cost and more efficient catalysts

2. Less corrosive and temperature-sensitive structural

materials

3. Higher power densities via:

a. Improved coolig systems

b. Improved oxygen flows

c. Improved cell geometry

4. More stable electrolytes

5. Longer stack life

Geothermal:

1. Inexpensive, durable, and reliable down-hole pumps

2. Detailed resource assessment

3. Inexpensive, durable, and reliable well casing

materials

Dual flash:

1. Cheap, durable, and reliable equipment for removing

noncondensable gases and/or entrained solids from

brines

2. Reliable operation in highly saline environments

Binary:

1. Inexpensive, durable working fluids

2. Equipment durability and reliability in highly saline

environments

SOURCE: Office of Technology Assessment.
Ch. 2—Summary ● 2 7

Table 2-3.—Developing Technologies: Major Electric Plants Installed or Under Construction by May 1, 1985

California wind farms

U.S. wind farms outside

of California

All US. wind farms

Nonutility

100+ MWe (gross)c Nonutility

? MWed Nonutility Under construction (1986)

(1986)

(1985)

(1985)

(1985)

(1985)!

(1985)’

(1989)

(1987)

(1986)

(1986)

(1985)

(1986)

(1987)

(1986)

Solar thermal electric:

Central receiver . . . . . . . . Daggett, CA Utility, nonutility, and

Government

Utility, nonutility, and

Government

Nonutility

Nonutility

Government

Nonutility

Nonutility

Nonutility

Installed

0.75 MWe Albuquerque, NM Installed

Parabolic trough . . . . . . . .

Parabolic dish , . . . . . . . . .

Daggett, CA

Daggett, CA

Palm Springs, CA

Various locations

Various locations

Warner Springs, CA

Installed

Under construction

Installed

Installed

Under construction

Installed

Solar pond . . . . . . . . . . . . .

Photovoltaics:

Flat plate . . . . . . . . . . . . . . 1 MWe (de, gross)

1 MWe (de, gross)

1 MWe (de, gross)

6.5 MWe (de, gross)

0.75 MWe (de, gross)

4.5 MWe (de, gross)

1,5 MWe (de, gross)

3.5 MWe (de, gross)

Utility and Government

Utility and Government

Nonutility

Nonutility

Nonutility

Nonutility

Nonutility

Nonutility

Installed

Under construction

Installed

Installed

Under construction

Installed

Installed

Installed

Concentrator. . . . . . . . . . .

Geothermal:

Dual flash . . . . . . . . . . . . . 10 MWe

10 MWe

47 MWe (net)

32 MWe (net)

Brawley, CA

Salton Sea, CA

Heber, CA

Salton Sea, CA

fnstalled

Installed

Under construction

Under construction

Binary:

Small . . . . . . . . . . . . . . . Installed

Installed

Installedh

Installed

Installed

Installedh

Installedh

Under construction

Under construction

Installed

2 x 3.5 MWe

3 x 0.3 MWe

3 x 0.4 MWe

10 MWe

1 x 0.75 MWe (gross)

3 x 0.35 MWe (gross)

3 x 0.45 MWe (gross)

4 x 1.25 MWe (gross)

3 x 0.85 MWe (gross)

45 MWe (net)

Mammoth, CA

Hammersly Canyon, OR

Hammersly Canyon, OR

East Mesa, CA

Wabuska, NV

Lakeview, OR

Lakeview, OR

Sulfurville, UT

Sulfurville, UT

Large . . . . . . . . . . . . . . . Heber, CA

Fuel cells:

Large . . . . . . . . . . . . . . . . .

Small J 

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

None

38 x 0.04 MWe (net) Various locations

Various locations

Utility, nonutility, and

Government

Utility, nonutility, and

Government

Installed

Small Under construction J 

. . . . . . . . . . . . . . . . . 5 x 0.04 MWe (net)

Fluidized.bed combustors:

Large grass roots. . . . . . .

Large retrofit. . . . . . . . . . .

Utility k and Government

Utility k

Utility k

Nonutility

Nonutility

Nonutiiity

Nonutility

Nonutility

160 MWe

100 MWe

125 MWe

125 MWe

30 MWe

25 MWe

15 MWe

67 MWe

Paducah, KY

Nucla, CO

Burnsville, MN

Brookesville, FL

Colton, CA

Fort Wayne, IN

lone, CA

Chester, PA

Under construction

Under construction

Under construction

Under construction

Under construction

Under construction

Under construction

Under construction

Small cogeneration . . . . .

aincludes small. and medium-sized wind turbines.

bApproximately ~ MWe were ~paating in California at the end of 1984. It is not known how much additional caPacitY waS installed by May 1985.

cApProximately 100 MWe were Opwating outside of &lifornia at the end of 1984, It is not known how much additional Capacity had been installed outside California

by May 1985.

dlt is not known ~w much capacity Was under corlstwctiofl Orl May 1, 1985,

~his facility, the Solar One Pilot plant, is not a commercial-scale plant and differs in other important ways from the type of system which might be deployed commercially in the 1990s.

fThis installation ~nsists of only Ow electricity producing module; a commercial installatiofl probably would consist of hundreds Of modules

gorily I(J percent of the modules were operating at the time because of problems with the power conversion systems,

hlnstalled but not operating, pending contractual negotiations with IJtilitie$.

iThe equipment~dules have been delivered to the site; s~!e preparation, however, has nOt started.

jThese units are not commercial-sc~e units,

klncluding the El~tric Power Rese&ch Institute.
28 . New Electric Power Technologies: Problems and Prospects for the 1990s

Table 2.3.—Developing Technologies: Major Electric Plants Installed or Under Construction

by May 1, 1985—Continued

SOURCE’ Office of Technology Assessment

cal means. It is done for the mutual benefit of

both utility and customer, usually as a means to

provide maximum productivity of the utility’s

generation and distribution capacity. While load

management is not a permanent substitute for

new capacity, it can enable a given capacity to

satisfy a greater customer base, and operate at

maximum efficiency. It is now employed by some

utilities and being seriously considered by many

others to improve their load factor—the ratio of

average to peak load. Since base load generating equipment is generally more thermally efficient than peak load equipment, one of the principal goals of load management is to encourage

a shift of demand to off-peak periods. The other

is to defer the need for costly new generating capacity by inhibiting demand during peak periods.

This assessment focuses on technology-based direct load control technologies employing advanced meters and utility-owned or controlled

load control systems. A potentially important feature of load management is that it can help reduce future demand growth uncertainty if the

saturation and use of load management devices

can be more accurately predicted. If such predictions are not possible, however, then increased

load management may actually increase demand

uncertainty.

Based on the results of current load management programs and ongoing experiments, load

management technologies are expected to be

able to be deployed at costs below those associated with many conventional generating alternatives. In many instances, however, these costs

cannot be reached without substantial utility demand to encourage manufacturers to realize volume production economies.

Widespread deployment of load management

in the 1990s will depend on continued experimentation by utilities to resolve operational uncertainties; the refinement of load management

equipment and techniques, including adequate

demonstration of communications and load

control systems; development of incentive rate

structures; and a better understanding of customer acceptance. Commitments to initiate load

management systems will also depend on the nature of a utility’s demand patterns and capacity

mix, the attitudes of utility decision makers, and

on public utility commission actions. The degree

of public utility commission support, in particular, is likely to be very important over the next

decade.
Ch. 2—Summary ● 2 9

IMPACT OF DISPERSED GENERATING TECHNOLOGIES

ON SYSTEM OPERATION

As the participation in U.S. electric power systems of non utility owned and operated dispersed

generating sources (DSGs) increases, the implications for system operation, performance, and

reliability are receiving increased attention by the

industry. For the most part, however, the technical aspects of interconnection and integration

with the grid are fairly well understood and most

utilities feel that the technical problems can be

resolved with little difficulty. State-of-the-art

power conditioners are expected to alleviate utility concerns about the quality of interconnection

subsystems. A number of nontechnical problems

remain, though, which could inhibit the growth

of DSGs.

Nonutility Interconnection Standards

More utilities are developing guidelines for interconnection of DSGs with the grid. A number

of national “model” guidelines are being developed by standard-setting committees for the Institute of Electrical and Electronic Engineers, the

National Electric Code, the U.S. Department of

Energy, and the Electric Power Research Institute,

although none has yet released final versions and

REGIONAL

A particularly important factor affecting the

relative advantages of new electric generating

storage, and load management technologies is

the region in which a utility or prospective nonutility power producer is located. U.S. regions differ markedly in industrial base, demographic

trends, and other factors affecting electricity demand; the age and composition (particularly fuel

use) of existing generating facilities; the nature

and magnitude of available indigenous energy resources; regulatory environment; transmission infrastructure and prospects for bulk power transfers; and other factors affecting the selection of

electric power technologies.

widespread utility endorsement is still uncertain.

As a result, DSG owners are likely to face different and sometimes conflicting interconnection

equipment standards well into the 1990s. These

differences may hamper both the use of DSGs

as well as the standardized manufacture of interconnection equipment.

Interconnection Costs

The costs of interconnection have declined dramatically in recent years, particularly for smaller

DSGs. Typical costs range from $600/kW for 5

kW units to less than $100/kW for 500 kW or

larger units. The interconnection costs for multimegawatt DSGs are only a small fraction of the

total cost of the facility. While future technological advances in microprocessor controls and less

costly nonmetallic construction could bring costs

down even further, the major cost decrease is expected to come from volume production of

equipment. As mentioned above, though, this

volume production may be delayed until national

model interconnection guidelines are agreed on

for interconnection equipment.

DIFFERENCES

Existing Generation Mix

The regional mix of existing generating facilities is likely to profoundly affect the relative attractiveness of new generating capacity. While

most electric utility systems with substantial oil

and gas capacity are expected to decrease use

of these fuels over the next decade, reliance on

these fuels is expected to be strong enough in

some areas, i.e., New England, the Gulf and

Mid-Atlantic States, the Southeast, and the West,

that the economics of competing technologies

will remain particularly sensitive to the price and

availability of oil and gas. This will apply even
30 . New Electric Power Technologies: Problems and Prospects for the 1990s

more strongly in the few States such as Florida

where, due to expectations of high demand growth

and continued decreases in (or stabilization of)

oil prices, utility systems are actually forecasting

increased use of oil.

in California oil- and gas-fired generation, while

declining, is projected to remain above 33 percent of the total electricity generation in the State

through the end of the century (oil alone will be

Is percent). Similarly, if present trends continue

in Texas, oil and gas is projected to account for

35 percent of total generation and about so percent of total capacity over the same time period.

In both States, high avoided cost rates resulting

from continued reliance on oil and gas enhances

the attractiveness of cogeneration, in particular,

whiIe the favorable tax climate in California enhances the attractiveness of renewable power

generation projects initiated under PURPA. In

some States where oil and gas are the dominant

fuels, especially California, Louisiana, and

Texas, cogeneration may constitute a significant

fraction of total installed capacity by the end

of the century. Some utilities in Texas, for example, are already planning for cogeneration contributions of as much as 30 percent.

The age of existing power generating facilities

varies widely among U.S. regions. As a result, the

prospects for life extension and plant rehabilitation vary as well. For example, Texas, the Southeast, and the States west of the Rockies will have

the highest percentage increases in plants that

would be logical candidates for such options between now and 1995, i.e., those generating units

that will have been in operation more than 30

years. in terms of total installed capacity, the opportunities for life extension will be greatest in

the Mid-Atlantic, Southeast, Gulf, and Western

States. Site-specific economics will determine actual implementation levels.

Interregional Bulk Power Transactions

It appears that existing interutility and interregional transmission capabilities are being

nearly fully utilized in the United States. Hence,

the prospects for large increases in bulk power

purchases among utilities using existing transmission capabilities will be limited. Some regions,

however, such as portions of the West and Midwest, are continuing to expand generation and

transmission facilities in anticipation of serving

the bulk power markets. In addition, major transmission projects are underway in New York, New

England, the upper Midwest, and the Pacific

Northwest to allow these regions to purchase

lower cost hydroelectric power generated in Canada from existing and proposed facilities.

Load Management

OTA has found that the prospects for increased load management in future utility resource planning vary by region. Perhaps more

importantly, they also vary significantly by utility

within reliability council regions. Moreover, utilities’ objectives for pursuing load management

vary as well. For example, utilities with very high

current or anticipated reserve margins (many in

the Midwest), are interested in load management

to better use existing base load capacity, i.e., to

stimulate increased demand in off-peak periods.

Other utilities with very low current or anticipated

reserve margins are pursuing load management

primarily to reduce peak demand and defer the

need for new capacity additions. Municipal utilities and rural cooperatives, which accounted for

most of the points controlled by load management in 1983, are expected to continue to provide a strong load management market in all regions through the 1990s.

Reliability Criteria

An important indicator of a region’s need for

new generating capacity is reflected in measures

of projected power system reliability. Such measures include the reserve margin—i. e., amount of

installed capacity available in excess of the peak

load, traditionally expressed as a percentage of

the total installed capacity. Reserve margins, as

well as other reliability measures, are sensitive

to demand predictions, scheduled capacity additions and retirements, and other factors such

as scheduled maintenance and adjustments for

forced outages or firm power purchases and sales

from other utilities.

The anticipated reserve margins over the next

several decades vary considerably by region. Un-
Ch. 2—Summary ● 31

der medium demand growth (2.5 percent average annual growth through 1995), reserve margins are expected to dip as low as 15 percent (in

the upper Midwest in the early 1990s) and peak

as high as 47 percent (in the West in the mid1980s). Under higher demand growth, power

pools in all regions may fall below acceptable

reliability levels in the early 1990s. Under low demand growth (less than 2 percent), reliability

levels are likely to be adequate in all regions

through the early 1990s.

Renewable Resources

Increased use of solar, wind, and geothermal

resources in U.S. electric power generation will

vary regionally due to both the relative cost of

alternative generation and the availability of highquality renewable resources. For example, while

wind regimes are promising for wind turbines in

many areas across the country, they are currently

being deve!Gped mostly in California where high

utility avoided cost and a favorable tax climate

have encouraged their development in nonutility

power production applications under PURPA. In

addition, a State-sponsored wind resource assessment program has spurred development. A similar situation exists for photovoltaics and geothermal power, although geothermal development

is much more regionally limited to the West. Solar thermal power generation, for the next several decades at least, may be viable only in the

Southwest and perhaps the Southeast where solar insolation characteristics may be sufficient to

make projects competitive and where land availabiIity is not a major constraint on development.

UTILITY AND NONUTILITY INVESTMENT DECISIONS

Prior to the 1970s, maintaining power system

reliability was treated as a prescribed constraint

and utilities had little difficulty earning their regulated rate of return on investment while achieving steady reductions in the cost of electricity by

building larger, less capital-intensive powerplants,

Hence, utility decision making objectives of maintaining service reliability, maximizing corporate

financial health, and minimizing rates could generally be pursued simultaneously.

Because of the complex and uncertain investment decision environment that has evolved

since the 1970s, utilities have begun to consider

offering varying levels of service reliability and

to more sharply weigh trade-offs between stockholders’ and ratepayers’ interests in making new

plant investment decisions. In many instances,

utilities are avoiding making large-scale plant

commitments and, indeed, are considering the

host of options cited earlier that can defer the

need for such commitments.

Utility Investment

of particular interest to many utilities are the

potential benefits of increased planning flexibility and financial performance offered by

small-scale, short lead-time generating plants.

For example, OTA modeling studies indicate that

with uncertain demand growth, the cash flow

benefits of such plants can be considerable. This

is true, in some cases, even when the capital cost

per kilowatt of the smaller plants is as much as

10 percent more than for large plants. In addition, the corresponding revenue requirement under a small plant scenario can be lower over a

30-year period.

Electric utility efforts to exploit these financial

benefits and nonutility interest in exploiting potentially attractive investment opportunities under PURPA have already stimulated considerable

interest from both types of investors in smaller

scale generating technologies. Other benefits are

important as well, including less environmental

impact, less “rate shock” to consumers by adding generating units to the rate base in smaller

increments, increased fuel diversity, and reduced transmission requirements if generating

units can be sited closer to load centers.

Most of the generating technologies considered

i n this assessment offer the small-scale moduIar

features attractive to many utilities as a means of

coping with financial and demand uncertainties.

This is likely to make the long-term prospects of
32 ● New Electric Power Technologies: Problems and Prospects for the 1990s

these technologies very bright, Despite this longterm promise, however, in most regions for the

next 10 to 15 years most of the new generating

technologies are not likely to be competitive

with other often more cost-effective strategic options cited earlier–life extension and rehabilitation of existing generating facilities, increased

purchases of power from other systems, and intensified conservation and load management

efforts.

Nonutility Investment

Nonutility interest is likely to continue to be

limited for the most part to more mature technologies that can be implemented in cogeneration applications or can qualify for favorable tax

treatment, e.g., combustion turbines, wind, and

more recently AFBC.

Investors in nonutility power projects seek to

maximize the risk-adjusted return on their invested capital. Depending on the type of investor, other considerations are important as well

including tax status, timing of the investment,

cash flow patterns, and maintenance of a balanced portfolio of investments with varying risk.

In order to finance a new nonutility project, the

major risks (technology, resource, energy price,

and political) must either by mitigated or incorporated in contingency plans. Common risk reduction techniques used to date include vendor

guarantees (or having the equipment vendor take

an equity position in the prospective venture) or

take-or-pay contracts with utilities.

CURRENT AND FUTURE STATE OF

ALTERNATIVE TECHNOLOGY INDUSTRY

Many of the new generating technologies considered in this assessment are being developed

by a much wider range of firms than has traditionally dealt with the electric utility industry.

Moreover, many firms involved in deploying

some new technologies, to the extent that they

are being deployed, are small independent firms,

less than 3 years old. For example, the wind industry’s equipment sales have for the most part

been to third-party financed wind parks selling

power to utilities under PURPA; many of these

parks have been developed by the wind manufacturers themselves. Other developers are large

aerospace, petroleum, or other companies that

have also not traditionally dealt with electric utilities, and many of them are only beginning to develop working business relationships with them.

Most of the technologies considered in this

assessment are in a transition phase of their development, i.e., between pilot- and commercialscale demonstrations or early commercial units.

Some of these technologies are progressing

through this transition aided by the existence of

auxiliary markets (in many cases foreign) other

than the grid-connected power generation market. For example, small-scale AFBC technology

has matured in the industrial marketplace, primarily in process heat applications. Similarly,

while the PV technology that will ultimately begin

to penetrate grid-connected power generation

markets is not yet clear, the various candidates

(flat plate, amorphous silicon, concentrators, etc.)

are maturing in other markets such as consumer

electronics or remote power applications.

As most of these technologies mature and the

relationships of vendors and manufacturers with

utilities and nonutility power producers develop, the nature of negotiated agreements between the parties initiating commercial demonstrations or early commercial units may dictate

the pace of commercial deployment of the technologies. In particular, the allocation of risks in

the form of performance or price guarantees or

other mechanisms will be especially important

for the electric utility market. For example, an

equipment manufacturer’s agreement to hold an

equity position in early commercial projects

might be viewed by many utilities as an adequate

performance guarantee.

One of the problems facing increased deployment of some new generating technologies in the
Ch. 2—Summary ● 3 3

1990s, as mentioned earlier, was that of potential delays in lead-times of early commercial

projects. While the features of smaller scale and

modular design for many of these technologies

offer ultimate promise for very short lead-times,

experience to date indicates that the rate of deployment of some new generating technologies

is being lowered because lead-times being experienced by early commercial projects have

been longer than anticipated, partially due to

the time needed to complete regulatory reviews.

As regulatory agencies become more familiar

with the technologies, the time to complete such

reviews should decrease, although this is by no

means guaranteed as evidenced by the history

of other generating technologies.

The pressures of competition from foreign vendors, many of whom are heavily supported by

their governments, as well as the current lack of

U.S. demand for some of these new technologies

in grid-connected power generation applications,

and the pending changes in favorable tax treatment throw into doubt the continued commitment of U.S. firms who are currently developing these technologies. For some technologies,

such as wind turbines, solar thermal-electric technologies, and photovoltaics (at least those focusing on concentrator technologies), the survival

of some domestic firms may be at stake. Many

domestic firms may not be able to compete in

world markets over the next decade. However,

in some cases foreign markets are considered to

be interim markets for technologies as they mature to the point where they can compete in the

U.S. grid-connected power generation market.

FEDERAL POLICY OPTIONS

Accelerated demand growth, coupled with current problems in building conventional, central

station powerplants, could lead to serious difficulty in meeting new demand in the 1990s. A s

a result it may be prudent to ensure the availability of an array of new generating technologies. Then, the buyers in the market for generating technologies will have a broader range of

technologies from which to choose. To ensure

this availability will probably require a sustained

Federal involvement in the commercialization of

new electric power generating, storage, and load

management technologies. The most logical goals

for the Federal initiatives are:

●

●

●

●

reduce capital cost and performance uncertainty,

encourage utility involvement in developing

technologies,

encourage nonutility role in commercializing developing technologies, and

resolve concerns regarding impact of decentralized generating sources (and load management) on power system operation.

The first three are primary goals while the

fourth is less critical although still important. The

relative importance of these goals as well as the

efforts to achieve them are at the center of the

debate over future U.S. electricity policy. A range

of possible initiatives is summarized in table 2-4

along with the Federal actions that would most

likely be required to implement them.

Research, Development,

and Demonstration

Perhaps foremost among the options necessary

to accelerate technology development is a sustained Federal presence in research, development, and demonstration of new electric generating and load management technologies. While

most of these technologies are no longer in the

basic research phase, development hurdles are

still formidable and the importance of research,

development, and demonstration remains high;

if these hurdles are overcome the result could

be a quick change in competitive position for

many of these technologies. For example, proof

of satisfactory reliability during a commercial

utility-scale demonstration of AFBC could substantially accelerate its deployment among electric utilities. As noted, the technology already is

beginning to be deployed very quickly in smaller

scale commercial cogeneration applications.
34 ● New Electric Power Technologies: Problems and Prospects for the 1990s

Table 2-4.—Policy Goals and Options

Reduce capital cost, improve performance, and resolve

uncertainty:

1.

2.

3.

4.

5.

Increase Federal support of technology demonstration

Shorten project lead-times and direct R&D to near-term

commercial potential

Increase assistance to vendors marketing developing

technologies in foreign countries

Increase resource assessment efforts for renewable

energy and CAES resources (wind, solar, geothermal,

and CAES-geology)

Improve collection, distribution, and analysis of

information

Encourage nonutility role in commercializing developing

technologies:

1. Continue favorable tax policy

2. Improve nonutility access to transmission capacity

3. Develop clearly defined and/or preferential avoided

energy cost calculations under PURPA

4. Standardize interconnection requirements

Encourage increased utility involvement in developing

technologies:

1. Increase utility and public utility commission support

of research, development, and demonstration activities

2. Promote involvement of utility subsidiaries in new

technology development.

3. Resolve siting and permitting questions for developing

technologies

4. Other legislative initiatives: PIFUA, PURPA, and

deregulation

Resolve concerns regarding impact of decentralized

generating sources on power system operation:

1. Increase research on impacts at varying levels of

penetration

2. Improve procedures for incorporating nonutility

generation and load management in economic

dispatch strategies and system planning

SOURCE: Office of Technology Assessment.

A critical milestone in utility or nonutility

power producer acceptance of new technology

is completion of a successful commercial demonstration program. The utility decisionmaking

caution cited earlier confers added importance

to advanced commercial demonstration projects, While there is considerable debate in the

industry over what constitutes an adequate demonstration, two basic categories are often distinguished: One is a proof-of-concept phase which

provides the basic operational data for commercial designs as well as test facilities designed to

prove the viability of the technology under nonIaboratory conditions and to reduce cost and performance uncertainties. The other involves multiple applications of a more or less mature

technology designed to stimulate commercial

adoption of the technology. Generally, activities

in the first category are necessary for demonstrating commercial viability and activities in the second category are necessary for accelerating commercializat ion.

The length of the appropriate demonstration

period will vary considerably by technology.

However, adequate demonstration periods (perhaps many years for larger scale technologies) are

crucial to promoting investor confidence. Moreover, the nature of the demonstration program

—i.e., who is participating, who is responsible

for managing it, and the applicability of the program to a wide variety of utility circumstances

—is of equal importance. Among the most successful demonstration ventures have been and

are likely to continue to be cooperative ventures

between industry (manufacturers and either utilities or nonutility power producers) and the Federal Government, with significant capital investments from all participants in the venture. The

current AFBC, IGCC, and geothermal demonstrations are good examples. In particular, for larger

scale technologies in utility applications, cooperative industry-government demonstration efforts, managed by the utilities, have a good track

record. For accelerated deployment, similar

projects would be required for fuel cells, CAES,

advanced battery technologies, and central receiver solar thermal powerplants.

The relationship between utilities and public

utility commissions in early commercial applications of new generating and load management

technologies is an important factor that will affect the deployment of these technologies in the

1990s. In particular, increased research, development, and demonstration activity will require

utilities and utility commissions to agree on

appropriate mechanisms for supporting such

activities. Direct support alone from the rate base

for research activities (e.g., as the allowance for

contributions to the Electric Power Research institute) may be desirable and important, but they

are not sufficient to assure extensive deployment

of these technologies by the 1990s. Much larger

commitments that involve large capital investments such as major demonstration facilities

may only be justified by a sharing of the risk between ratepayers, stockholders and, if other utilities would benefit substantially, taxpayers. One
Ch. 2—Summary Ž 35

mechanism for supporting such projects is to finance a portion of a proposed project with an

equity contribution from the utility and the rest

through a “ratepayer loan” granted by the public utility commission. The public utility commission might argue that a candidate demonstration

project is too risky for the ratepayer to be subsidizing it, particularly if other utilities could benefit substantially from the outcome if successful

and are not contributing to the demonstration,

i.e., sharing in the risk. In such cases, there could

be a Federal role; for example, the ratepayer contribution to the demonstration could be underwritten by a Federal loan guarantee.

Other Policy Actions

In addition to maintaining a continued presence in research, development, and demonstration and implementing environmental policy

affecting power generation, several other Federal policy decisions affecting electric utilities

could influence the rate of commercial development of new generating technologies over the

next several years. These include removal of the

Powerplant and Industrial Fuel Use Act (PIFUA)

restrictions on the use of natural gas, and making PURPA Section 210 benefits available to

electric utilities. These steps could increase the

rate of deployment of developing generating

technologies, but their other effects will have to

be carefully reviewed before and during implementation.

A more liberal power generation exemptions

policy under PIFUA or an outright repeal of the

Act could, in addition to providing more shortterm fuel flexibility for many utilities, be an important step toward accelerated deployment of

“clean coal” technologies such as the IGCC

which can use natural gas as an interim fuel.

Some new technologies such as CAES and several solar thermal technologies use natural gas

as an auxiliary fuel and would require exemption

from PIFUA.

Permitting utilities to participate more fully

in the PURPA Section 210 benefits of receiving

avoided cost in small power production is likely

to result in increased deployment of small modular power generating technologies, particularly

cogeneration. For example, utilities are currently

limited to less than 50 percent participation in

PURPA qualifying cogeneration facilities. In addition, with full utility participation in PURPA,

ratepayers likely would share more directly in any

cost savings resulting from these kinds of generating technologies. Allowance of full PURPA benefits for utilities, however, could cause avoided

costs to be set by the cost of power from the cogeneration unit or alternative generation technology. Such avoided costs would likely be lower

than if they were determined by conventional

generating technologies as now is the case. Lower

avoided costs would reduce the number of cogeneration and alternative technology power

projects started by nonutility investors. Expanded

utility involvement, though, may more than compensate for this decrease.

In relaxing the PURPA limitation potential problems require attention, including ensuring that

utilities do not show preference for utility-initiated

projects in such areas as access to transmission

or capacity payments. Moreover, project accounting for PURPA-qualifying projects would

probably need to be segregated from utility operations and non-PU RPA qualifying projects in order to prevent cross-subsidization which would

make utility-initiated projects appear more profitable at the ratepayers’ expense. These concerns

can be allayed through carefully drafted legislation or regulations, or through careful State review of utility ownership schemes.

Finally, as perhaps a logical next step to PURPA,

a number of proposals for deregulation of the

electric power business have been proposed in

recent years, ranging from deregulation of bulk

power transfers among utilities, to deregulation

of generation, to complete deregulation of the

industry. While OTA has not examined the implications of alternative deregulation proposals,

such proposals, if enacted, would almost certainly

have an impact on new generation technologies.

The experiences of PURPA and the Southwest

Bulk Power Transaction Deregulation Experiment

will be important barometers for assessing the future prospects and desirability of deregulating

U.S. electric power generation. It is important to

note that allowance of full PURPA benefits for utilities would be a significant step toward deregu-
36 . New Electric Power Technologies: Problems and Prospects for the 1990S

Iation of electric power generation, at least for

smaller generating units.

Renewable Energy Tax Credits

Along with direct support for research and development and joint venture demonstration

projects, an important component of the Federal

program for new generating technology commercialization has been favorable tax treatment

through such mechanisms as the Renewable

Energy Tax Credits (RTCs), the Investment Tax

Credit (ITC), and ACRS depreciation allowances.

The RTC, in particular, coupled with recovery

of full utility avoided costs (under PURPA) by

nonutility power producers have been crucial

in the initial commercial development and deployment of wind and solar power generating

technologies. With declining direct Federal support for renewable technology development, the

RTC has supported development of advanced

and innovative designs as well as commercial

deployment of mature designs. Without continued favorable tax treatment, deployment of

solar, wind and geothermal technologies is likely

to be slowed significantly—certainly in nonutility applications. Without existing tax incentives,

many of the mostly small firms involved in development projects will lose access to existing

sources of capital. Even large, adequately capitalized firms may lose their distribution networks,

making industry growth more difficult.

With favorable tax treatment, some new technologies, such as geothermal and wind, have become important sources of new and replacement

generating capacity in the West and Southwest.

However, they must compete with more mature,

modular technologies, e.g., conventional cogeneration technologies. And these modular technologies will continue to account for an important share of the new generating capacity, in the

form of both utility and nonutility owned (and

perhaps joint) ventures.

Figure 2-1 shows the cumulative effect of tax

benefits, including accelerated depreciation allowances (ACRS), ITCS, and RTCs on the real internal rate of return for technologies considered

in this assessment under the condition of nonutility ownership. (IGCC is not included in this

figure since it is unlikely to be developed in nonutility power projects.) The figure shows that the

RTC may be crucial to the commercial survival

of the renewable technologies with the possible exception of wind which may be mature

enough to survive without these credits. The

number of firms involved in wind technology

development, however, would probably decrease markedly without these credits.

The role of the RTC in accelerating commercial development seems to have changed. The

original Federal policy was to provide direct research support to develop the technology and the

RTC to accelerate commercial deployment. With

decreased Federal research and development

support, the RTC appears to be supporting research and development in the field; this might

partially explain the wide variation in performance of wind projects in recent years.

A frequently proposed alternative to the RTC,

in order to ensure performance of projects claiming a credit, is a Production Tax Credit (PTC)

which provides benefits only with electricity production. OTA analysis of the PTC shows that geothermal and wind technologies benefit most from

a PTC. others such as CAES and the direct solar technologies are aided only by a very large

PTC. Similarly, tax benefits tied to production

discourages producers from testing innovative

designs since, if the design does not perform as

expected, no benefits will be realized. Another

potential problem with the PTC is that monitoring electricity production may be difficult, particularly in applications that are not grid connected.

Other actions cited earlier for stimulating development in new technology within electric utilities may be more effective than tax preferences.

For example, the decrease in the Ievelized per

kilowatt-hour busbar cost for the renewable technologies considered in this assessment, with a 15

percent tax credit over and above the existing tax

benefits currently afforded to utilities, is less than

10 percent for all cases.
Ch. 2—Summary • 37

60

50

Figure 2-1 .—Tax Incentives for New Electric Generating Technologies:

Cumulative Effect on Real Internal Rate of Returna

1

,

.

voltaics turbines thermal cells”

Atmospheric

fluid ized-bedb

SOURCE: Office of Technology Assessment, U S Congress.
Chapter 3

Electric Utilities in the 1990s:

Planning for an Uncertain Future
CONTENTS

3-1.

3-2.

3-3.

3-4.

3-5.

3-6.

3-7.

3-8.

3-9.

List of Figures

Figure No. Page

3-1. Utility Investment Alternatives . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41

3-2. Alternative Power Generation in California . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 43

3-3. Projetions of U.S. Electric Load Growth . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 45

3-4

3-5

3-6

3-7

3-8

3-9

3-1o

3-11

3-12

3-13

3-14

3-15
Chapter 3

Electric Utilities in the 1990s:

Planning for an Uncertain Future

INTRODUCTION

Overview

In the early 1970s, the U.S. electric power industry entered a new era. Long a stable force in

the U.S. economy, the industry as a whole

emerged in the 1980s under considerable financial

stress and uncertainty, precipitated by skyrocketing fuel prices, escalating capital and construction costs, and a declining and erratic demand

growth.

Even as utilities recovered from the shocks of

the 1970s, it was clear that they would not return to business as usual, circa 1960s. The highly

uncertain decision environment has forced utilities to reexamine their traditional business strategies as they look to the 1990s and beyond. indeed, the basic procedures traditionally used by

utilities in making future investment decisions

have, in many cases, been drastically changed

by the utilities themselves as well as by security

analysts, investors, regulators, and ratepayers.

In this chapter we examine the strategic options

being considered by utilities over the next two

decades and, in particular, focus on the circumstances under which investment in new generating technologies might play a significant role

for electric utilities through this period, compared

with other strategic options. These other cptions

include continued reliance on conventional supply sources, life extension and repowering of existing plants, increased purchases of power from

neighboring utilities, or diversification to other

nonutility lines of business (see figure 3-1). In addition, we review the arguments for and against

the use of alternative technologies under different planning scenarios.

Figure 3-1 .—Utility Investment Alternatives

●

● Financial impact:

— Cash flow

— Coverage ratio

— Return on equity

— Capital requirements

— Percent of rate

capitalized

— Internal cash generation

— AFUDC percent of

earnings

— Construction costs

● Cost/benefit of reliability

. Risk:

— Fuel availability

— Operational security

● Financial exposure:

— Construction delays

— Licensing uncertainties

— Rate base asset
The extent to which new generating technologies might play a role in electric utilities in the

1990s depends on how favorably such technologies compare with capital investments in conventional generation alternatives. It also depends

on the managerial skills and financial resources

of individual utilities. The role of nonutility producers of electricity is discussed later.

A number of 1982 surveysl suggested that utilities are not very interested in investing in new

generating technologies. A variety of contingencies—such as persistent cost-control problems

with large, central-station coal or nuclear plants

now under construction or increased environmental control requirements, e.g., to reduce acid

rain—however, are beginning to make such

investments look much more appealing to utilities in the 1990s.

Currently, much of the investment in new electric generating technologies in the United States

is not being undertaken by utilities at all, but by

nonutility owners generating power under the

provisions of the Public Utility Regulatory Policies

Act of 1978 (PURPA) (see box 3A). To date, much

of this investment has gone into cogeneration.

in some utility service areas, e.g., in California,

the rate of growth of new generating technologies

is steadily increasing (see figure 3-2).2 Hence, the

degree to which nonutility investment in new

generating technologies (and load management)

affects the total generation mix is also an important ingredient in the future of the U.S. electric

power system.

The ultimate penetration of new technologies

over the next two decades in many regions may

well hinge on the relationship which evolves between utilities and nonutility owners. It will

depend on the stringency of the utilities’ interconnection requirements and on the rates the

1“Plans and Perspectives: The Industry’s View, ’’EPR/ journal, October 1983; Douglas Cogan and Susan Williams, Generating Fnergy

Alternatives: Conservation, Load Management, and Renewable

Energy at America’s E/ectric Uti/ities (Washington, DC: Investor

Responsibility Research Center, Inc., 1983); A Review of Energy

Supply Decision Issues in the U.S. Electric Utility Industry (Washington, DC: Theodore Barry & Associates, September 1982).

ZTh is rate of growth has been so fast in California that the State

declared a temporary moratorium on cogeneration projects in late

1984; the figure shows both utility and nonutility involvement in

alternative technoloev Droiects.

nonutility electricity producers receive for their

electricity from the utilities. At present, these requirements and rates vary greatly across the

United States (see chapter 7).

“, , J
Ch. 3—E/ectric Utilities in the 1990s: Planning for an Uncertain Future ● 4 3

Figure 3-2.—Alternative Power Generation in California (utility and nonutility owned capacity)

Wind— Geothermal Small Cogeneration IGCC Biomass

hydroelectric

1996 2004

operating characteristics in the industry. Perhaps

the most important feature of this legislation was

not so much its guidelines for standardization,

but more its general mandate for the industry:

Provide an abundant supply of electric power

with the greatest possible economy and with regard to proper utilization and conservation of

natu rat resources.

In practice, this mandate was interpreted as requiring the provision of power at any time of day

and in any quantity demanded.4 As a result, the
44 . New Electric Power Technologies: Problems and Prospects for the 1990s

primary objective of electric utility operations in

the United States is to meet the collective demand

presented by all of its customers. The Federal

Power Act required that this demand be met in

an economically efficient manner both in dispatching generators to meet the daily load as well

as in developing plans for new construction.

Until the late 1960s, electric utilities had been

able to reliably and economically plan additions

to their installed generating capacity to meet future demand while retiring aging plants. Until that

time, demand growth forecasts had been reasonably accurate, powerplant construction lead

times had been reasonably predictable, and construction as well as fuel cost changes had been

small. Construction costs (per kilowatt installed)

in fact decline as power-plants are scaled up in

size. Electric utilities were viewed as sound investment opportunities by the capital markets.

Thus, capital was available at relatively low cost.

Since the late 1960s, however, several factors

have combined to create problems for the electric utilities. Both their financial performance and

ability to make system planning decisions using

the planning tools of the past have deteriorated

as a result. Among these factors (discussed in

more detail in the next section) are: 1 ) the growing difficulty of making demand forecasts—the

industry as well as nearly all interested parties

consistently underestimated the potential for conservation, i.e., the price elasticity of demand; 2)

the dramatic increase in environmental protection costs resulting from the public’s growing concern over the environmental effects of electric

power production, especially air pollution from

coal; 3) the unprecedented and escalating cost

of new powerplants, especially nuclear powerplant construction due to unexpected delays, inflated capital costs, stricter safety standards (especially after Three Mile island), unpredictable

regulation, and uneven project management; and

4) high as well as uncertain fuel prices and supplies. The legacy of this traumatic period has been

an industry in which both investors and utility

managers are acutely aware of the industry’s financial fragility and uncertain demand outlook

and are therefore more cautious about committing their capital to large new coal and nuclear

plants.

The prognosis for the power industry is uncertain. While it is possible that demand growth rates

may increase once again over the next decade,

it is also possible that changing industry fuel

choices, saturation of electricity use in buildings,

and improved efficiency of electricity use in all

sectors of the economy as well as other conservation measures may moderate demand growth

to less than 2 percent per year. Most current estimates range from 1.5 to 5 percent per year (see

figure 3-3). The issue of uncertainty in demand

growth is discussed in more detail in a previous

OTA assessments

In the following, the impact these interrelated

financial, regulatory (including environmental),

and cost escalation stresses have had on the decisionmaking environment in the electricity industry are sketched in more detail.

Increasing Fuel Prices and

Supply Uncertainty

Figure 3-4 shows the national average fossil fuel

prices paid by electric utilities in the United States

over the last decade; weighted average fossil fuel

prices more than tripled between 1970 and 1980.

Those utilities relying on significant levels of oil

and natural gas (principally the East and Southwest—see figures 3-5 and 3-6) are shifting their

generation mix to more capital-intensive nuclear

and coal generation due to the uncertain future

costs and supply of oil and natural gas. The recent stabilizing of oil and natural gas prices and

excess supply of natural gas has only added to

the uncertainty about future supply and prices.b

(The regional variations in generation mix, fuels

and other factors are discussed in chapter 7.)

Increasing Powerplant

Construction Costs

Increased attention to environment and safety

issues over the last decade has contributed to

both extended lead times in the siting, permitw,s. congress, office of Technology Assessment, Nuclear Power

in an Age of Uncertainty (Washington, DC: U.S. Government Printing Office, February 1984), OTA-E-216, ch. 3.

%ee U.S. Congress, Office of Technology Assessment, U.S. Mtural Gas Avai/abillty: Gas Supply Through the Year 2000 (Washington, DC: U.S. Government Printing Office, February 1985),

OTA-E-245,
Ch. 3—E/ectric Utilities in the 1990s: P/arming for an Uncertain Future • 45

750

700

650

600

400

350

300

Figure 3.3.—Projections of U.S. Electric Load Growth

Summer peak demand projections

comparison of annual 10-year forecasts

(contiguous United States)

Net energy projections

comparisons of annual 10-year forecasts

(contiguous United States)

.

1 I I I 1 1 1 1 1

74 76 78 80 82 84 86 88 90

Average annual

growth rate (o/o)

projecting 10-years

1974 -7.6

1975 -6.9

1976 -6.4

1977 -5.7

1978 -5.2

1979 -4.7

1980 -4.0

1981 -3.4

1982 -3.0

1983 -2.8

1984 -2.5

Average annual

growth rate (o/o)

projecting 10-years

1974 -7.5

1975 -6.7

1976 -6.3

1977 -5.8

1978 -5.3

1979 -4.8

1980 -4.1

1981 -3.7

1982 -3.3

1983 -3.2

1984 -2.6
46 . New Electric Power Technologies: Problems and Prospects for the 1990s

Fiqure 3-4.—National Average Fossil Fuel Prices

7An investor-owned electric utility today requires about $2.86 of

investment per dollar of annual revenue compared with a dollar

or less of investment per dollar of revenue for manufacturing industries; the electric utility industry (investor-owned) in the United
Ch. 3—E/ectric Utilities in the 1990s: Planning for an Uncertain Future ● 4 7

Figure 3-5.— Regional Net Generation of Electricity by Fuel Type, 1984

I

1

100

90m

\

,

Figure 3-6.—U.S. Generation Mix by Installed Capacity and Electricity Generation

Installed capacity

F

1983 1984

Year

Key:

1993

I

Total net electricity generation

1982 1984 1993

Year
Figure 3-7.—Electric Powerplant Cost Escalation, 1971-84

1971 1978 1982-84

Year

Key:

tion has been permitted by some utility commissions. The issue of allowing CWIP in the rate base

is discussed in more detail in chapter 10. Today,

over a half of the total earnings nationally by

investor-owned utilities is AFUDC (see figures 3-

11 and 3-12).

The generaI deterioration of financial performance of utilities has strained stockholder confidence. Indeed, in an effort to maintain this confidence many utilities have actually borrowed at

short-term high interest rates to pay out dividends

to shareholders.lo Likewise, the consistently high

loperhaps a Milestone irl recent utility history was Consolidated

Ediwn’s missed dividend payment in 1974 (see Foley, op. cit., 1983);

more recently missed dividends by Public Service of New Hampshire, Consumers Power, and Long Island Lighting Co. are signaling concern to investors.
Ch. 3—E/ectric Utilities in the 1990s: Planning for an Uncertain future ● 4 9

Figure 3-8.–Capital Intensity

Utilities, 1982

I

of Electric

“

Electric Fabric Primary Telephone Petroleum Motor Aircraft

3-1 3). Again, these ratings have increased since

1983, but remain below the 1960s’ levels. And,

it did not go unnoticed by investors that the

largest municipal bond default in American history occurred within the electric power industry

in 1983, when the consortium of utilities known

as the Washington public Supply System defaulted on $2.25 billion of bonds on two nuclear

powerplants. Many of the important financial indicators are summarized in table 3-2.

Financial Impacts of the

Nuclear Experience

Beginning in 1983, the difference in financial

performance between utilities involved in nuclear

construction programs and those who are not has

became particularly apparent. It is reflected, for

example, in stock price—see figure 3- I 4. Since

early 1983, the market-to-book ratio for the industry as a whole has risen substantially, but utilities involved in major nuclear projects have

lagged behind. For nearly half of the industry currently involved in nuclear construction programs,

the status of these projects and the economic regFigure 3-9.— Electric Utility Market to Book Ratios, 1962-84

, .O 2.5 3 m

U.S. electric utilities

m Standard & Poor’s 400

Companies

r - l n

’62 ’63 ’64 ’65 ’66 ’67 ’68 ’69 ’70 ’71 ’72 ’73 ’74 '75 ’76 ’77 ’78 ’79 ’80 ’81 ’82 ’83

Year
50 ● New Electric Power Technologies: Problems and Prospects for the 1990s

Table 3-1 .—Electric Utility Rate Applications and Approvals, 1970-84 (millions of dollars)

Number of rate Amounts Amounts Percent

Year increases filed requested approved approved
Ch. 3—Electric Utilities in the 1990s: Planning for an Uncertain Future ● 5 1

Figure 3-11 .—CWIP As a Percentage of Total Investment

Other assets

(1 ”/0) \

Other assets

(8°/0) \

1981

Year

Other assets

(19°/0)

Net plant

Other assets

(17°/0)
52 ● New Electric Power Technologies: Problems and Prospects for the 1990s

Figure 3-12.—AFUDC As a Percentage of Total Earnings”

19

18

17

16

15

14

13

12

11

10

9

8

7

6

5

4

3

2

1

0

Net income

AFUDC

37 ”/0

49 ”/0

420/o

54 ”/0

50%0

54%0

ulatory response to cost overruns, plant abandonments, and excess capacity if the plants are completed, will weigh heavily on these utilities’

financial performance over the next decade. Despite the fact that some utilities have demonstrated that the difficulties with nuclear technology are not insurmountable, 11 OTA concluded

last year that:

Without significant changes in the technology, management, and the level of public ac-

— .

1 ITlle 85 nuclear plarrts operating in the United States today generally have an economical and reliable operating history; this is reinforced by the 227 nuclear plants now operating in foreign countries (a total of 531 plants are now operating, on order or under

construction worldwide); see E. Meyer, et al., “Financial Squeeze

on Utilities: Who Really Pays, ” Public Utilities Fortnight/y, vol. 114,

No. 12, Dec. 6, 1984, pp. 31-35.

ceptance, nuclear power in the United States is

unlikely to be expanded in this century beyond

the reactors already under construction.lz

Moreover, if utility commissions consider generating reserve margins excessive, they may not include all or part of expenditures in the rate base

for some plants currently under construction.

The consequences of economic regulatory

treatment of such plants could range from utility

bankruptcies to large rate increases, often referred to as “rate shock” for customers. Such decisions will bring the issue of the ratepayers’ versus

stockholders’ interests into sharp focus over the

next decade; indeed many alternative proposals

12oT_A, NUC/ear powerin an Age of Uncertainty, op. cit., 1984.
Ch. 3—E/ectric Utilities in the 1990s: Planning for an Uncertain Future Ž 53

Figure 3-13.— Electric Utility Bond Ratings,

1975-84

1975 1980 1983 1984

I JSee, for example, National Science Foundation, Division of policy Research and Analysis, “Workshop on Alternative Electric Power

Plant Financing and Cost Recovery Methods, ” Washington, DC,

May 7, 1984.

And finally, management of nuclear powerplant construction projects in the utility industry

has been very uneven. Problems have occurred

in all phases of nuclear construction programs

from project design through quality control and

cost control .14

Summary

The current state of affairs in the electric utility industry is one of considerable uncertainty

over future demand growth, powerplant costs,

and cost of capital. As a result, few utilities are

willing to increase their investment risk and many

have canceled or at least deferred large-scale,

long lead-time construction programs. And interest by the industry in alternatives to the traditional

strategy of building conventional large-scale generation plants is growing. In particular, these akernatives include intensified load management and

conservation (either through direct load control

or indirectly through the rate structure); rehabilitation of existing generating plant; and increased

interconnection with neighboring utilities.

Another alternative being considered is construction of smaller, and possibly decentralized, generation facilities that permit more flexible tracking of demand growth and reduced exposure to

inflation and capital market fluctuations; morelqsee, for example, James Cook, ‘‘Nuclear FoI lies, ” ~Ofbe5, vol.

135, No. 3, Feb. 11, 1985, pp. 82-1 00; and OTA, Nuclear Power

in an Age of Uncertainty, op. cit., 1984.

Table 3.2.–Financiai Condition of Electric Utilities, 1952-84

“Golden age” “Transition” “Hard times”

Characteristic 1952-66 1966-73 1973-75

Ratio of internally generated funds to capital

expenditures. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0.8 0.5 0.3

Interest coverage ratio (pretax) . . . . . . . . . . . . . . . . . . . . >5.0 3.0 2.4

Interest rate (

0

/0). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . <4. 6 6.0 8.5

Inflation rate (

0

/0) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.25 4.5 8.0

Common stock price (o/o of book value) . . . . . . . . . . . . 250 150 95

Construction activity initiated . . . . . . . . . . . . . . . . . . . . . Average Heavy Cutbacks

Electric rates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Decreasing Steadily Accelerating

increasing

Average return on equity (o/o):

Including AFUDC. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13 12 11

Excludina AFUDC . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12 9 7.2

“Recovery” “Present”

1980 1984

0.42

3.0

15.27

13.5

73

Increased

cutbacks

Increasing

0.42

3.38

10.79

3.5

95

Very

little

Still

increasing

11.4 13.9

7.4 7.35

SOURCES: Rand Corp., E/ecfric UtWty Dec/s/orr Mak/rrg and the Nuclear OptIon (Santa Monica, CA: Rand Corp., 1977); Edison Electric Institute (EEI), Statistical Year.

book of the Electric Utility /rrdustry/1983 (Washington, DC: EEI, December 19S4); and Marie R. Corlo and Alice E, Condren, “Utilitles-Electric: Basic Analysis,”

Standard and Poor’s Industry Surveys, Mar. 1, 19S4.
54 . New Electric Power Technologies: Problems and Prospects for the 1990s

Figure 3-14.— Stock. Price Performance of Nuclear

and Nonnuclear Utilities

130

over, the smaller facilities enter the rate base

more quickly. Also, utilities are increasingly interested in the potential contribution of new generating technologies which use both conventional

and renewable energy resources. The question

is how utilities will incorporate the characteristics of these new technologies into both their

planning and operations, because they are generally quite

generating

owners are

role in the

different from those of conventional

alternatives. In addition, nonutility

likely to play an increasingly crucial

application of these technologies.

The next section reviews the traditional decisionmaking process in the electric utility industry and the forces that are changing that process. Of particular importance to the industry over

the next two decades will be the ability of any

given utility’s management to answer the following questions:

●

●

●

Are the benefits of smaller scale, shorter leadtime plants—their lower financial risk, shortterm financial sustainability, and greater flexibility in filling unpredicted demand—compelling enough to consider them more carefully as an alternative to conventional

large-scale, long lead-time plants?

If the benefits of smaller, shorter lead-time

plants are considered sufficient along with

other benefits such as increased efficiency

or reduced emissions, what conventional

small-scale alternatives and what unconventional new technologies will be considered?

To what degree will use of conventional

alternatives preclude significant use of new

technologies?

If unconventional new technologies are perceived as potentially important in a utility’s

future resource plan, what institutional

changes might be necessary to accommodate these technologies? Will nonutility

ownership be encouraged? How?

INVESTMENT DECISIONS BY ELECTRIC UTILITIES:

OBJECTIVES AND TRADE-OFFS

Introduction Investment Decision Objectives

in the most general terms, the principal objec- Maintaining System Reliability

tives of utility decisionmakers are to: 1) ensure

that system reliability is maintained, 2) minimize

their ratepayers’ burden over time, and 3) maintain the financial health of their companies. Any

decision analysis of investments must address

these objectives. Of increasing importance, particularly in evaluating the potential for new technologies, is the degree of uncertainty affecting the

company’s future demand, cost of service, and

performance. Accounting for this uncertainty is

becoming a much more important component

in the decision making process of most utilities.

I Sother measures are reported in General Electric CO., 17e/;ab;/-

ity /nd;ces for Power Systems, final report prepared for Electric

Power Research Institute (EPRI) (Palo Alto, CA: EPRI, March 1981),

EL-1773, RP1 353-1.
analyze peak demand predictions, at full as well

as partial outage estimates of their generation and

major transmission facilities, in order to project

reserve margins required to meet the LOLP constraint.

The critical uncertainties in this reliability analysis include: 1 ) the annual peak demand forecast,

2) scheduled and forced outage occurrences of

needed generating units, 3) the power output of

needed generating units, 4) the on-line dates of

any new generating capacity that may be planned

for the period in question, and 5) the availability

of purchased power. Other factors such as load

management or conservation efforts and dispersed sources of generation, e.g., cogeneration,

add an additional element of uncertainty to the

utility’s reliability analysis. (See chapter 6.) This

is because there is uncertainty regarding the extent to which conservation will moderate electricity demand and load management will alter

demand patterns. Further, there is uncertainty

about the market penetration that will be

achieved by load management devices and by

dispersed sources of generation. There is also uncertainty about their reliability.

In recent years, the traditional treatment of

reliability as a fixed constraint—the prescribed

LOLP level described earlier–is being called into

question. In particular, the trade-off between total

cost and quality of service is becoming an increasing concern. 16 The argument being advanced is

that electricity should be treated more as a commodity in a segmented market (different customer

classes), one aspect of which is quality of service which should be reflected in the commodity

price. The current debate, therefore, centers

around whether electricity should be available

at a uniformly high level of reliability or at increasing degrees of reliability for increasing price

levels.

Minimizing Electricity Rates

The second objective of utility decisionmakers

is to minimize their electricity rates. They must

show their efforts to achieve this objective in their

16 For example, see M. Telson, “The Economics of Reliability for

Electric Generation Systems, ” Bell Journal of Economics, vol. 5,

No. 2, autumn 1975, pp. 679-694.

applications for changes in rates to State public

utility commissions. Generally accepted ratemaking practices are discussed in chapter 8 (box 8A).

The objective of minimizing rates is often measured in terms of revenue requirements or the total

cost per kilowatt-hour of electric energy generated. The principal cost elements to be considered when meeting this objective are:

1.

2.

3,

In

fixed costs associated with the recovery of

capital invested in generation, transmission

and distribution facilities;

fixed and variable production costs associated with operation, maintenance and fuel

expenses for supply facilities; and

overhead costs associated with general

administrative expenses and working capital allowances.

order to compare lifetime rate requirements

of different generating technologies, utilities project, over the lifetime of each plant, each component of cost– return on capital, debt service

cost, fuel and operating cost, and share of overhead–and then they apply a discount rate to

each year’s costs to calculate a Ievelized annual

cost. Utility decision making is complicated by the

fact that pIants with the same Ievelized cost can

have very different year-to-year costs, and that

utility rates are not set according to Ievelized cost

but projected actual costs. During times of high

inflation and high interest rates, the return on capital and the cost of capital-expensive plants is concentrated in the early years of a plant’s life. For

fuel-expensive plants the opposite is true–the

year-to-year cost is initially low but increases over

time. The implications of such trade-offs are discussed in more detail in chapter 8.

Maintaining Corporate Financial Health

The third objective of utility decision makers—to

maintain the financial health of their companies—is typically assessed in terms of some key

parameters such as growth in earnings, debt service coverage ratios, and return on common equity,

System planning decisions which satisfy the two

objectives discussed earlier (i. e., maintaining system reliability while minimizing ratepayers’ burden) are also evaluated in terms of their impact,

over time, on these measures of corporate financial health.

38-743 0 - 85 - 3
Since the electric utility business is so capitalintensive, it relies heavily on its ability to raise

capital from debt and equity sources. The availability and cost of this capital depends, to a large

degree, on a utility’s financial health as evaluated

by security analysts and investment houses.

When evaluating a utility’s financial health,

these analysts weigh a wide range of qualitative

and quantitative factors (see table 3-3). They

seem, though, to emphasize five quantitative factors:

1.

2.

3.

4.

5.

earnings protection—debt coverage,

leverage–equity share of total capitalization,

cash flow and earnings quality—share of

AFUDC in total earnings,

asset concentration—shares of generating capacity compared to shares of the rate base,

and

financial flexibility .17

In addition, they generally consider five qualitative

1.

2.

3.

4.

5.

factors:

prospects for demand growth in the service

territory,

diversity of fuel supply,

quality of management,

operating efficiency, and

regulatory disposition.

Variations Among Utilities and

Conflicting Objectives

Prior to the early 1970s, maintaining reliability was treated as a prescribed constraint and utilities generally had little trouble earning their

allowed rate of return while achieving steady reductions in the cost of electricity, as discussed

earlier. In other words, the three investment objectives could in effect be simultaneously pursued

with little conflict, and the process just described

generally explained utility investment decisions

quite well, at least with respect to technology

choice.

—

I ~homas Mockler (Standard & Poor’s), “Workshop on Investment

Decisionmaking in Electric Utilities,” sponsored by U.S. Congress,

Office of Technology Assessment, Washington, DC, Apr. 17-18,

1984.

Table 3.3.—Elements Considered in the Utility

Financial Rating Process

Economic analysis of service territory:

Population

Wealth

Employment

Size of service area and outlook

Historic and estimated load growth

Demand and energy sales

Type of system:

Self generation

Distribution

Combination

Wholesale and bulk power

Facilities:

Fuel mix, cost, availability, and price

Capacity and reserve

Operating cost

Operating ratio

Dispatching strategies

Capital improvement plans:

Realistic construction cost estimates

Alternatives to own construction

Rate structure:

Likely regulatory climate

Comparative rates

Ability to adjust

Bond security:

Revenues

Debt service reserve

Contingency fund

Capitalized interest

Rate covenant

Additional bonds covenant

Power contracts

Asset concentration

Key ratios:

Environmental concerns

Net take-down

Interest coverage

Debt service coverage

Debt service safety margin

Debt ratio

Interest safety margin

Percentage AFUDC

Percentage internal cost generation

SOURCE: Standard & Poor’s, “Standard & Poor’s Bond Guide for 1983, ” 1983.
Ch. 3—Eiectric Utilities in the 1990s: Planning for an Uncertain Future . 57

The actual implementation of a decisionmaking process varies across utilities, but there appears to be little difference among utilities in the

generally accepted practices for making decisions. The differences, rather, are mostly in

characterizing the alternatives to be considered.

A recent survey of utility decision making18 reported that, in spite of the wide diversity of types

of firms in the industry (see box 36),

there is a high degree of uniformity in the

Plant investment decision making practices followed by U.S. electric power firms, both public

and private, as well as other regulated utilities.

In chapter 8 the analytical tools routinely used

by utilities in making investment decisions are discussed. Also discussed are the differences among

utilities, particuIarly with respect to differences

in cost of capital (considerably different, for example, between public and private utilities), in

discount rates, and in attitudes toward and methods for dealing with risk.

How utilities account for risk is important because it explains in part what might otherwise be

a noneconomic choice in selecting a new technology. For example, uncertainty about demand

growth, long-term financing conditions, or other

“state of the world” factors may prompt more

severe discounting for long-term risk against long

lead-time projects. This has certainly been the

case in recent years in the industry. Similarly, of

particular relevance to this assessment, concern

over a specific technology may swing a close investment decision one way or the other. The Edison Electric Institute19 has classified the critical,

supply-option, technology risks facing utility decisionmakers, these are summarized in table 3-4.

In addition, and reflected in some of these risks,

factors relating specifically to regulatory approval

are of increasing concern and have prompted

utilities to carry out what is often termed “shortperiod analysis. ” In such an analysis, planners

examine how specific areas of uncertainty, such

as future environmental regulations or fuel avail113G. Corey, “Plant Investment Decision-Making In the Electrlc

Power I nciustry, Discounting for Time and Risk in Energy Policy

(Washington, DC: Resources for the Future, 1982), pp. 377-403.

19 Ed i~on E led rlc I nsflt ute ( EE I ), Strategic /mp/lCaliOnS OfA/~ern~~-

tl~e Generat/rrg Technologies (Washington, DC: EEI, April 1984).

ability, might affect the financial performance in

the early years of a project’s life.

This new, more complex investment decision

environment of the 1980s has brought with it the

possibility of conflicting objectives in making investment decisions. It has become possible that

utilities could decide not to pursue the lowest

projected lifetime cost option (minimizing rates)

for future investments because of its implications

for short-term financial performance (maintaining financial health). In the long run, maintaining financial integrity does indirectly affect the

ratepayers’ burden, but the relationship is less

clear.

Perhaps to avoid such conflict, some utilities

in recent years have made substantial changes

in the way they make future investment decisions.

For example, Pacific Gas & Electric’s (PG&E) key

corporate planning goals published in 198320 state

an “adopted direction” including:

● operation within revenue and expense levels

provided by rate case decisions,

● minimize capital expenditures, and

● avoid major commitments of capital to new

energy supply projects.

For PG&E, this meant that “the company will

not be committing capital to any major new electric supply projects, although minimal capital expenditures may result from efforts to keep options

open .“ Variation in how a utility sets its basic

direction for resource planning depends on regulatory pressure, financial position, and, perhaps

most importantly, the character of utility management. Some utilities have substantially modified

their “decisionmaking” mechanisms to better accommodate uncertainty and trade-offs in investment decisions, e.g., the “short-period” analysis described earlier.

The trade-offs among future investments are

likely to be a fundamental issue of debate over

the next decade, and this debate’s outcome

could profoundly affect the deployment of new

technologies as they mature. Another recent industry survey, cited earlier21 reports that, for the

‘Zopacific Gas A EleCtriC CO., Long Term P/arming l?ewks: 1984-

2004, May 1984.

jlTheocfore Barry & Associates, Op. cit., ? 982.

Ch. 3—E/ectr/c Utilities in the 1990s: Planning for an Uncertain Future ● 5 9

Table 3-4.—Technology Risks for Electric

Utility Decisionmakers

1.

2.

3.

4.

5.

6.

7.

8.

.

Technical risk: the probability that a new generator will fail

to come on-line at its anticipated capacity rating.

Lifetime risk: the probability that a new generator’s lifetime will be significantly shorter than anticipated due either

to technical problems or regulatory decision problems.

Cost risk: the probability that a new generation technology will cost significantly more to construct or operate than

anticipated.

On4ime completion risk: the probability that a technology will not come on-line when anticipated because of technical or regulatory problems.

Lead-time risk: the probability construction end time will

be longer than planned. One problem is that events change

such that the probject will no longer be needed or economically viable.

Obsolescence risk: the probability that a given technology will be economically obsolete prior to its planned lifetime. This is analogous to the lifetime risk and could result

from fuel cost changes or new technologies being introduced, etc.

Third-party ownership risk: the probability that a generator owned by a third party will become unavailable to

produce electricity for any reason related to the ownership

by a third party, e.g., bankruptcy of the corporate entity

owning a cogeneration facility so that the steam no longer

exists and the facility is uneconomic without the steam

demand,

Reliability and performance risk: the probability y that a particular technology will be significantly less reliable than

planned.

As utilities emerge from the financially stressed

period of the 1970s and early 1980s, the tradeoffs between financial performance and the ratepayers’ burden will be a subject of continuing debate that may affect the structure of the industry

itself .22

The Current Context for

Alternative Investments

Most utilities have been forced by economic

and regulatory uncertainties to broaden the scope

of their analysis of future investments, but this has

not yet led, in most cases, to investment in new

generating technologies.

——

zz~n one hancf, some economists argue that a solution to the

utility ind ustry’s financial problems over the long term rests in

deregulating portions O( the power generation side of the business:

on the other hand, others (e.g., U.S. Department of Energy (DOE),

Report of the Electrlclty Policy Project, The future otE/ectrlc Power

In America: Economic Supply for Economic Growth (Washington,

DC: National Technical Information Service, June 1983), DOE/PE0045) argue that agglomeration of existing firms into larger regional

entities addresses the financial problems more efficiently.

A 1982 EPRI survey of member utilities23 posed

the question of what strategic options were considered likely in the event of limited capital availability over the next decade. Options involving

new technologies fell well down the list of priorities, behind strategies such as increased conservation, deferral of retirements, rehabilitation

of existing plant, 24 and increased participation in

joint ownership of large conventional plants, The

survey did suggest, however, that utilities are considering new technologies as an option to pursue in the event of unexpected contingencies and

that “utilities revealed an increased willingness

to consider a host of new technologies for generation before the end of this century. ”

Some utilities25 think that there are three major contingencies that could more or less significantly affect the relative attractiveness of new supply technologies over the next decade:

●

●

●

✎

Sudden increases in demand growth.–

Demand growth in the United States in 1983

was 1.9 percent and in 1984 it was 4.6 percent; demand predictions for the next decade vary from 1.5 to 5 percent.

Major reductions in allowable pollution

emissions.—Acid rain and other legislative

initiatives could alter the kinds of coal-bu rning technologies and fuels used over the next

decade.

Limited availability of petroleum.–While

the shortages and price increases of the

1970s prompted considerable shifts away

from oil in U.S. electric power production,

over 10 percent of the Nation’s installed capacity is still oil-fired (see figure 3-7 earlier).

Any dramatic changes in oil availability will

affect the rate at which oil use declines i n

power generation. This issue is discussed in

depth in a recent OTA assessment.26

. . —

ZjTaylor Moore, et a!., Electric Power Research Institute (EPRI),

Planning and Evaluation Division, “Plans and Perspectives: The industry’s View, ” EPR/)ourna/, vol. 8, No. 8, October 1983, pp. 14-19

24Although AFBC retrofits of existing units I nvolvf?s a new technology; this option is being pursued aggressively by many utillties,

~sFor example, Southern Company Services, Inc., Research and

Development Department, “Assessment of Technologies Useful In

Responding to Alternate Planning Contingencies, ” unpublished,

December 1983.

ZGU .S. congress, Office of Technology Assessment, U.S. v’u/nerabi/ify to an Oi/ /mporr Curfai/menf (Washington, DC: U.S. Government Printing Office, September 1984), OTA-E-243.
60 ● New Electric Power Technologies: Problems and Prospects for the 1990s

In the more distant future three additional contingencies could change utilities’ investment decisionmaking priorities:

●

●

●

Natural gas availability .–There is still considerable uncertainty in the domestic resource base for natural gas, although optimism is growing. 27 If reserves are significantly

greater than previous estimates suggest, then

natural gas might once again become an attractive fuel for electric power generation,

although this would require modifications to

the Fuel Use Act.

Dramatic changes in interest rates.–As discussed earlier, due to the industry’s capital

intensity, high interest rates have caused

electric utilities much financial stress. Dramatic decreases in interest rates could

dampen the current interest in short leadtime, modular design technologies relative

to larger central station plants; however, it

could stimulate the interest of non utility producers in such technologies.

Significant technological advances.–Although much less Iikely than in other industries such as communications or computers,

breakthroughs in technology could improve

the likelihood of utility adoption of new technology over the next several decades. The

opportunities for advances in the technologies considered in this assessment are discussed in chapter 4.

In addition, changes in Federal policies such

as the tax system, PURPA, and the Powerplant

and Industrial Fuel Use Act could have a significant impact on investment decisions as well; such

changes are discussed in chapter 10.

While at the current rate of development extensive deployment of new technologies under

any circumstances is unlikely in the 1980s, the

first three contingencies are likely to affect utility decision making with respect to new supply

decisions; the latter three contingencies are not

likely to affect utility decisions until the 1990s.

270TA, (-/.s. ~atura/ GaS Availability: Gas Supply Through the

Year 2000, op. cit., 1985.

Tradeoffs in Allocated Investments

and Strategic Planning

In light of economic and regulatory uncertainties surrounding the industry, many utilities are

now considering, along with traditional central

station powerplants (including joint ventures in

such plants with other utilities), such options as

dispersed generation, increased levels of purchased power, load management (or other enduse related actions), diversification into entirely

new businesses (see figure 3-1 earlier), and new

generating technologies as possible investments.

With an expanded spectrum of investment alternatives along with an uncertain decision environment, the problem then becomes one of comparing options that differ considerably in terms

of production characteristics as well as in terms

of financial risk and return; La for example, how

does one compare a kilowatt of peak-load reduction achieved through load management to a kilowatt of new capacity from wind power?

If, for the moment, one takes the quality of service to be provided by a given utility as a prescribed constraint, as utilities have traditionally

done, investment decisions hinge on the relative

importance of the remaining objectives, namely

minimizing the ratepayers burden and maintaining financial health. In recent years in the electric utility industry, as implied in the last section,

the latter objective has taken on added complexity.

Generally, a utility strives to earn a rate of return at least equal to its cost of capital. Therefore long-term profitability could be defined as

the difference between the return on equity (ROE)

and the cost of capital29 (k). Short-term cash flow

implications of new investments have emerged

as important concerns for many utilities in recent

years, i.e., a utility must generate enough cash

zBDiscUSSecj in Cjetail in D. Geraghty, “Coping With Changing Risks

in Utility Capital Investments, ” unpublished paper, Electric Power

Research Institute, February 1984.

2glf a utility’s rate of return equals its cost of capital, stockholders

still earn a competitive return; see D. Geraghtv, “Coping With Risk

in the Electric Utility Industry: The Value of Alternative Investment

Strategies, ” Second International Mathematics and Computer Society (IMACS) Symposium on Energy Mode/ing and Simulation,

Brookhaven National Laboratory, New York, Aug. 27, 1984.
Ch. 3—E/ectric Uti/ities in the 1990s: Planning for an Uncertain Future ● 6 1

flow to maintain operations, Therefore, sustainability could be defined as the difference between funds generated and funds used at a given

time.

The above definitions of profitability and sustainability are used in figure 3-15 to show the financial performance of utilities over the last two

decades. If profitability is measured on the vertical axis and sustainability on the horizontal axis,

the regulatory target is the origin, i.e., where return is equal to the cost of capital and where

funds generated equal the funds received. In the

1960s, utility investments were both profitable

and sustainable. With the precipitous rise in fuel

prices in the early 1970s, investments became

less sustainable as production costs became unexpectedly higher. With the increase in the share

of earnings earmarked as funds used during construction (AFUDC), investments also became less

profitable. In the 1970s the cost of capital increased further to the point where this industry

could be considered both unprofitable and unsustainable. Current utility steps to increase profitability include requests for increases in allowed

rate of return and efforts to reduce cost; steps to

improve sustainability include requests for CWIP

costs to be included in the rate base and avoidance of new construction projects.

Financial Criteria for Investments

in Capacity

Utilities concerned about both short-term sustainability and long-term profitability of their operations can evaluate investment options in terms

of their impact on a number of measurable paFigure 3-15.—Profitability-Sustainability in Electric Utilities

SOURCE
62 ● New Electric Power Technologies: Problems and Prospects for the 1990s

rameters that relate either directly or indirectly

to sustainability and profitability. These parameters include the debt service coverage, return on

equity, percent internal cash generation, and

growth in earnings.

For example, an important parameter used in

evaluating future cash flow implications is the

debt service or interest coverage ratio which reflects the ability of the utility to repay its debt obligations and is a crucial factor in determining a

utility’s bond rating. s” Table 3-s demonstrates

relationships between interest coverage ratios,

utility bond rating, and average cost of these

bonds. In this connection, year-to-year cash flow

will fluctuate least when new generating plants

are built in small increments and with short leadtimes. Therefore, a utility aiming for a stable debt

service coverage ratio could choose not to build

long lead-time, large powerplants even when

their cost per unit power may be less than the

smaller plants because of engineering economies

of scale (see chapter 8).

Prior studies give some insights into the tradeoffs between short lead-time, smaller scale additions to generating capacity and long lead-time,

large powerplants. Ford and Youngbloodsl show

JOThe interest coverage ratio accounts for as much as 80 percent

of a bond rating decision; see Rand Corp., E/ectric uti/ity Decision

Making and the Nuclear Option (Santa Monica, CA: Rand Corp.,

1977) or Standard & Poor, Standard& Poor’s Bond Guide for 1983

(New York: Standard & Poor, 1983).

JIAndrew Ford and Annette Youngblood, “simulating the planning Advantages of Shorter Lead Time Generating Technologies, ”

Energy Systems and Po/icy, vol. 6, No. 4, 1982, pp. 341-374; and

Andrew Ford and Annette Youngblood, “Simulating the Spiral of

Impossibility in the Electrical Utility Industry, ” Energy Po/icy, March

1983.

Table 3“5.—Electric Utility Debt Cost and Coverage

Ratio Relationships

Coverage ratio Bond ratina Averaae vield

3.0-3.5 AA 1 1.0%0

2.5-2,75 11 .3’?/0

2.0 B#B 12.1 ‘Yo

SOURCES: Standard & Poor, “Standard& Poor’s Bond Guide for 1983,” 1983; and

L. Hyman, Amedca’s Electric Utilities: Past, Present, and Future

(Washington, DC: Public Utilities Reports, Inc., 1983).

that utilities that build plants with short lead-times

can maintain a lower ratio of capacity under construction to installed capacity, when year-to-year

changes in demand growth are very unpredictable. A lower ratio of capacity under construction

would, in turn, allow a higher debt service coverage ratio. (Short lead-times for purposes of this

analysis were defined as 1 to 2 years planning and

permitting and 3 to 4 years construction.)

32Carl E. Behrens, “Economic Potential of Smaller-Sized Nuclear

Plants in Today’s Economy,” Congressional Research Service paper prepared at the request of the Honorable Paul Tsongas, Washington, DC, Jan. 20, 1984, 83-621 ENR.

~JEEI, Strategic /rnp/ications of Alternative Generating Technologies, op. cit., 1984.

JoThe scenario employed assumed a utility with a 5 GW peak

demand, 6 GW of installed capacity, a load factor of 65 percent,

total embedded capital (excluding CWIP) of $9.6 billion (average

yearly cost of 10 percent–real discount rate) and embedded operating costs of 3 cents/kWh. The large plant was 1,000 MW with

a 7-year lead-time at a cost of $2,000/kW (1980 dollars including

interest during construction); small plants were 100 MW with installed costs of $2,200/kW.
Introduction

The spectrum of alternative investments currently available to many utilities was briefly outlined in the last section. This section highlights

the most important considerations in each of

these options. As mentioned earlier, to the extent that new generating capacity is planned at

all over the next decade, the industry as a whole

appears to prefer traditional conventional power

generation technologies (e.g., pulverized coalburning technologies and combustion turbines)

as the mainstay for strategic planning. The EPRI

Annual Industry Survey for 1982, compared with

the corresponding survey for prior years, did indicate, however, that more efficient use of energy

has emerged more prominently in utility strategic plans than in previous years.

The EPRI survey also revealed an increased willingness to consider new generating technologies

before the end of this century, particularly in light

of the future contingencies (see previous section)

that could affect the viability of conventional

alternatives. In some utilities where available

renewable resources are particularly attractive

and plentiful, alternative technologies such as solar, geothermal, and wind may contribute significantly to future resource plans, but continued

development of these technologies was viewed

by the survey as benefiting only a handful of utilities over the next several decades.

Strategic options such as rehabilitation of existing plant and increased purchases of energy

from neighboring utilities have emerged as important alternatives for utilities in the next decade, particularly where capital is in short supply.

Overall, therefore, in considering alternative

strategic options for utilities, it is important to

keep in mind that new generating technologies

now appear to fall well down the list of priorities

for most utilities, though interest in them is increasing as utilities plan for dealing with future

uncertainty.

The business strategies of U.S. utilities, while

actually a continuum, can be classified roughly

into four basic, but not exclusive, categories:35

●

●

●

Modified grow and build strategy .-A number of utilities have continued to view completion of large nuclear and coal plants

initiated in the 1970s as their best option. Allowing for changes in the fuels used in generation, this is a continuation of the strategy

of virtually the entire industry since its beginning. Some utilities, confident of renewed

demand growth in the 1990s, are planning

for continued expansion.

Capital minimization.–Many utilities in the

United States are now reacting to the current regulatory and financial climate in the

industry with a strategy of minimizing capital expenditures by canceling plants both

planned and currently under construction,

increasing use of purchased power, participating in joint ventures if construction is necessary, selling existing capacity, rehabilitating existing plant, and increasing attention

to load management. This strategy is designed to minimize corporate risk.

Renewable and alternative energy supply.–

A few utilities have embarked on a strategy

of significantly increasing reliance on renewable energy sources as well as cogeneration

from conventional sources in an effort to use

small, modular pIants to better track uncertain demand growth and reduce construction lead-times (other reasons are discussed

later). The two large utilities (PG&E and

Southern California Edison) that have made

reliance on these sources an announced part

of their strategy both come from California

where renewable resources are relatively

abundant and avoided energy costs are high.

Many more utilities have initiated increased

research and development programs in new

jJThese categories are defined by S. Fenn, America’s E/ectric Uti/-

ities: Under Siege and in Transdion, op. cit., 1984).
64 . New Electric Power Technologies: Problems and Prospects for the 1990s

●

technologies (discussed later). How many of

these will go on to base a significant part of

their strategic planning on alternative sources

is uncertain.

Diversification.–A majority of investorowned utilities have begun to diversify their

business interests by investing revenues in

potentially more profitable ventures outside

the electric utility business (see table 3-8).

While the level of expenditures in such activities is as yet very small, a large number of

utilities are exploring new business ventures

on a small scale in areas such as real estate,

telecommunications, oil and gas exploration,

and business services.

Conventional Alternatives

The industry surveys cited earlier reveal that

if more capital is available to electric utilities over

the next decade and if emissions requirements

are not tightened, conventional pulverized coal

steam plants are generally the preferred investment option for future generation. The future of

nuclear power remains clouded by management

and regulatory problems as well as by technical

and financial uncertainties. The EPRI survey

found that “business decisions on new nuclear

plants will remain clouded’ ’until such uncertainties are resolved. This conclusion is supported by

the recent OTA assessment on the future of nuclear power as well as by others. 36

As discussed earlier, the cash-flow drawbacks

of the long lead-time, large, conventional coal

and nuclear plants as well as the potential costs

of overbuilding due to uncertain demand growth

have prompted utility interest in designs for these

conventional technologies that permit installation

of smaller, modular units (200 to 500 MW rather

than 800 to 1,200 MW), even at a significant capital cost premium. In addition, in planning for circumstances such as increased regulation of pollution emissions, other utilities have also become

interested in other modifications of conventional

coal technologies. These include limestone injection, advanced coal cleaning techniques, improved scrubbers, and others.37 Such modificaMOTA, NUC/ear Power in an Age of Uncertainty, op. cit., 1984;

or Scott Fenn, The Nuclear Power Debate: Issues and Choices (New

York: Praeger Publishers, 1981).

Jzsee the Southern CO. Services report cited earlier.

tions, while generally outside the scope of the

current study, could significantly affect the relative attractiveness of new technologies under all

the possible future contingencies cited earlier.

Considered in this assessment are advanced coal

conversion processes such as fluid ized-bed combustion and integrated coal gasification/combined-cycle units.

Load Management and Conservation

One of the surveys cited earlier38 found that

72 percent of the utilities they surveyed had initiated formal conservation programs and over

two-thirds have started formal load management

programs (see table 3-6). Fifty percent of these

load management and conservation projects have

appeared since 1980. Total investment in such

programs is expected to increase dramatically

over the next decade, particularly in load management. The survey suggests that “virtually the

entire industry will have incorporated such activities in a formal way” (see table 3-6). Conservation options are not considered in this report but

load management is discussed in chapter S.

Plant Betterment

Many utilities have found it useful to consider

measures of rehabilitating existing generation capacity or improving maintenance to extend their

useful lives.39 Indeed, some studies have found

a high correlation between maintenance expenditures, unit availability, and adjusted return on

equity, i.e., the difference between the earned

return and bond yields. @ Moreover, as life extension options are reviewed more carefully,

many units operating at derated capacities, since

they are approaching the end of their design lives,

can be restored to their original output and more

(up to 10 percent) with improved heat rates and

overall efficiencies.41 Some current researchaz

3Kogan & Williams, Investor Research Responsibility Center, op.

cit., 1983

39 Lee Catalano, “Utilities Eye Unit Life Extension, ” Power, vol.

128, No. 8, August 1984, pp. 67-68.

4oA. Corio, National Emncmic Research Associates, research summarized in “First Annual Maintenance Survey, ” E/ectrica/ Wor/d,

vol. 197, No. 4, April 1983, pp. 57-64.

AIG Fried lander, “Generation Report: New Life Available for old

T/G’s”and Boilers,” E/ectrica/ World, vol. 197, No. 5, May 1983,

pp. 87-96.

qzsummary of ongoing research by Temple, Barker & Sloane, Inc.

given in “Optimum Use of Existing Plant, ” Uti/ity /nvestrnents Risk
Ch. 3—Electric Utilities in the 1990s: Planning for an Uncertain Future ● 6 5

Table 3-6.—Conservation and Load Management Programs of Leading Utilitiesa

Projected

annual

Generating increase Program Projected

capacity in demand adoption Program costs megawatts saved

Company 1982 through 1992 date(s) in 1982 (000) through 1992

32,076

14,526

12,865

16,319

8,085

12,966

15,345

5,899

9,023

0

3,371

9,194

2,736

6,749

5,359

6,162

2,144

7,904

9,458

3,522

2,774

2,495

6,470

10,564

2,751

1977

1975

1980

1976/77

1981

1978/80

1972

1980

1982

1980

1980

1976

1973

1976

1982

1979

1980

1977/81

1968/81

1977

1982

1980

1983

1975

1977

4,000

2,994

2,100

1,871

1,750

1,700

1,500

1,500

956

802

800

800

671

601

600

600

485

465

450

420

412

400

390

370

318

ity has been built since 1970. In addition, these

prospects vary considerably by region (see chapter 7).

Increased Purchases

Interconnection among utilities has always

been common in the electric power industry but

in recent years buIk power transfers have increased dramatically. I n fact, the total volume of

bulk power transfers increased by a factor of 30

between 1945 and 1980 while total electricity

production increased only by a factor of 10.43 In

general, bulk power purchases are undertaken

by a utility if the marginal cost of production in

an interconnected utility is less than it would cost

for the buyer to produce that power itself. The

most significant increases began to occur in the

early 1970s as oil prices forced many utilities

43u S Depa flrnen[ Of Energy, Energy Information Ad WI i n Istratlon,

/nterutl/ity Bu/k Po\~er Transac(lons, (Washington, DC: U.S. Government Prlntlng Office, October 1983), DOE/EIA-0418.
66 ● New Electric Power Technologies: Problems and Prospects for the 1990s

Table 3.7.—Replacement of Powerplants:

Selected Options

Cumulative replacement capacity

GW needed by:

1995 2000 2005 2010

If existing powerplants

are retired after:

30 years. . . . . . . . . . . .

40 years. . . . . . . . . . . .

50 years. . . . . . . . . . . .

If all oil and gas steam

capability is retired as

follows:

All . . . . . . . . . . . . . . . . .

Half . . . . . . . . . . . . . . .

All oil and gas

capacity above 20

percent of region

(3 regions). . . . . . . .

If average coal and

nuclear availability slips

from 70% to:

About 650/o . . . . . . . . .

About 600/0 . . . . . . . . .

155

55

—

152

76

55

21

42

230 395

105 155

20 55

152 152

76 76

55 55

21 21

42 42

510

230

105

152

76

55

21

42

SOURCE: US. Congress, Office of Technology Assessment, Nuclear Power in

an Age of Uncertainty (Washington, DC: U.S. Government Printing Office, February 1984) OTA-E-216; this analysis shows the sensitivity to

North American Electric Reliability Council data projected from 1983,

highly dependent on oil to seek lower cost power

from less oil-dependent neighbors and, as a result, the ratio of power purchases and wholesale

power sales to total electricity sales among utilities varies by region as discussed in chapter 7.

While there are many different types of bulk

power transactions, most fall into one of three

categories:

1.

2.

3.

economy transactions that reduce operating

costs by displacing the buyer’s own higher

cost power with lower cost power from a

neighboring utility;

capacity transactions which permit a utility

to claim additional generating capacity from

a neighboring utility to supplement its own

for a specified period of time (sometimes

called firm power transactions); and

reliability and convenience transactions that

are negotiated to improve system operation

and reliability—e.g., emergency support.

Some utilities will clearly benefit over the next

two decades from increased reliance on purchased power from neighbors that have excess

coal-fired and hydroelectric capacity and adequate transmission capabilities, and this option
Ch. 3—Electric Utilities in the 1990s: Planning for an Uncertain Future . 67

Table 3-8.—Edison Electric Institute Business

Diversification Surveya

Venture Percent of total

Developing Supply and Storage

Technologies

The range of technologies considered in this

assessment that may show promise in electric

power generation through the 1990s are included

in table 3-9. A detailed evaluation of the probable costs and performance of these technologies

is given in chapter 4. Considered here are some

of the generic characteristics of these technologies that might affect a utility’s decision to adopt

them or might encourage nonutility investment

in them.

Table 3-9.-Developing Technologies Considered in

OTA’S Analysisa

Photovoltaics:

Flat plate systems (tracking and nontracking)

Concentrators

Solar thermal electric:

Solar ponds

Central receivers

Parabolic troughs

Parabolic dishes

Wind

Geothermal:

Dual flash

Binary (large and small)

Atmospheric fluidized-bed combustors

Integrated gasification/combined-cy cle

Batteries:

Lead acid

Zinc chloride

Compressed-air energy storage (large and small)

Phosphoric-acid fuel cells (large and small)

aFOr description see box 2A, ch. 2 and ch. 4.

SOURCE: Office of Technology Assessment

Most of the developing technologies listed in

table 3-9 are small in scale relative to conventional alternatives; hence they generally have

shorter lead-times and offer the following

benefits:

●

●

●

Modularity.–Modularity of units, both in

construction and in duplication of plants at

a single site, means that decisions to initiate

new capacity additions can be made closer

to the time the units are actually needed. As

a result, there is more flexibility in both tracking highly uncertain demand growth and in

bringing new capacity on line to correct for

temporary undercapacity. Several of the new

technologies considered in this assessment

(see table 3-9) lend themselves to modular

design–e.g., wind, photovoltaics, fuel cells,

and IGCC. Utilities consider flexibility in periods of highly uncertain demand growth to

be a primary motivation for examining new

technologies. 48 Combustion turbines have

traditionally been used by utilities to reduce

their exposure to risk during periods of uncertain demand growth, but they involve

very high operating costs and use of premium oil and gas fuels. The gas industry is,

however, very optimistic about the future of

combined-cycle plants using natural gas.

Less “rate shock. ’’–Rate increases can be

moderate with small plants or units coming

on line and entering the rate base. If demand

growth is very large, however, many small

plants or units will be required and “rate

shock’ ’could be even more severe since

small plants or units of alternative technologies generally come at a capital cost

premium. A similar rate shock through fuel

adjustment clauses might be experienced

with a strategy of using combustion turbines

to meet such unpredicted, large demand

growth.

Increased reliability.–Generally speaking,

smaller units permit maintenance of a

smaller reserve margin since individual

forced outages of smaller units have less impact, although if the system is mixed, i.e.,

4SW. Gould, 1‘Development of Renewable/Alternative Resou rces

of Electric Energy, ” unpublished, Southern California Edison Co.,

Rosemead, CA, 1983.
with some large and small generators, the

reserve margin must cover the possibility of

a forced outage of the large units. Moreover,

the potential of this benefit is complicated

if the small units are dispersed source generators as discussed in chapter 6.

Improved financial flexibility.–The amount

of capital tied up in construction is substantially reduced by employing short lead-time

technologies. Security rating agencies are

concerned when a utility incurs a significant

“asset concentration risk, ” e.g., placing a

large amount of capital at risk on a single

project which could ultimately account for

50 to 60 percent or more of the utility’s rate

base but only 10 to 15 percent of its installed

capacity.

Improved quality of earnings.–Less capital tied up in construction translates into a

lower level of AFUDC reported in a utility’s

earnings. This, in the eyes of investors, raises

the quaIity of earnings since AFUDC is considered a “paper” earning.

Technology and fuel diversity .–Diversity of

fuel types and technologies employed by a

utility reduces not only technological risk but

also institutional risks such as the impacts of

a coal strike or an oil supply disruption,

addition, many new technologies offer environmental benefits as well as adv~ntages of fuel

flexibility, increased efficiency, the potential of

reduced fuel transportation costs and, in many

cases, the possibility of cogeneration. Moreover,

if a small-scale technology is suitable for dispersed

siting near load centers, additional benefits are

possible:

● Reduced transmission requirements. -Siting

closer to load centers reduces the need for

transmission; large plants generally must be

sited much further away. The potential level

of transmission “credit” possible in small dispersed generating units has been the subject

of much research. 49

● Improved quality of service.-–Outages can

generally be serviced more quickly with disdgsee, for example, S. Lee, et al., Systems COntrOl, Inc., /mPact

of Transmission Requirements ot Dispersed Storage and Generation (Palo Alto, CA: Electric Power Research Institute), December

1979, EM-1 192.

●

persed generation available to be dispatched

locally.

Improved area control.–lf decentralized

sources can be coordinated with energy control centers (where power flow to load centers

is controlled), the result will be better regulation of area control error and hence improved efficiency and quality of power (see

chapter 6).

While all of these potential benefits are in many

cases sufficiently attractive to warrant interest on

the part of utilities, alternative technologies also

pose complications for utility planners in addition to the risk of relying on new technology.

These include:

●

●

●

Load dependence.—The uncertainty associated with impact on the system load curve

of dispersed generating sources is compounded by the fraction of this generation

coming from intermittent alternative energy

sources such as wind, solar, and low-head

hydroelectric systems. Unlike conventional

sources or fossil-based dispersed sources

which are largely independent of load characteristics, alternative sources are often interdependent with load due to such factors

as wind speed, solar energy flux, temperatures, steam flow, etc.

Nondispatchable generation and utility

operations.—As mentioned earlier, nonutility or customer-owned equipment (actually

for both new as well as conventional technologies) operating under the provisions

established by PURPA are not generally included in a utility’s economic dispatch system. Most utilities have treated nondispatchable generation as an expected modification

of the system load curve in the same manner

as load management. As penetration of nondispatchable sources grows, however, utilities will need to account for them more explicitly in dispatching strategies.

Nonutility generation and capacity planning.—As mentioned earlier, nonutility generation has traditionally been treated as a

modification to the system load curve. If significant penetration of such generation is

considered a possibility, as might be the case

in a number of utilities, the capacity plan-
Ch. 3—Electric Utilities in the 1990s: Planning for an Uncertain Future Ž 69

ning process for these utilities could be affected. The attitudes of utilities toward nonutility generation varies markedly among

utiIities in terms of interconnection requirements and conventions for establishing of

avoided cost rates. Interconnection requirements such as insurance, control and safety

equipment, meters, and telecommunications

equipment can all vary according to size of

generating plant, approved design specifications or other factors (see chapter 6). Similarly, avoided cost rates vary according to

procedures for capacity and energy credits,

and availability of “payment tracking mechanisms” that permit nonutility generators to

receive higher revenues in early years of the

project, as is the practice at Southern California Edison. The ultimate contribution of

nonutility generation to the overall U.S.

power generating capacity depends on not

only the performance of the technology and

adequate financial incentives, but also on the

evolving attitudes of utilities, especially as

they apply to rates and interconnection with

nonutility generation. Indeed, interconnection requirements alone can increase nonutility generation cost by over $1,000/kW for

small systems. so Some work is now being

done to incorporate nondispatchable technologies into long-term generation plann i ng. 51

● Rate inequities .—The possibiIity of rate inequities also presents a potential problem in

the case of encouragement of a large penetration of nonutility generation. Rate requirements are estimated for various customer

classes, e.g., residential, commercial, heavy

industrial, etc., based on the total revenue

requirements of the utility and the forecasted

demand of each customer class (including

time of day and cost of service considera-

~Osee u .s. Congress, Office of Technology Assessment, /ndustria/ and Cornrnercia/ Cogeneration (Washington, DC: U.S. Government Prlntlng Office, February 1983), OTA-E- 192; and U.S. Department of Energy (DOE), Survey of Uti/ity Cogenera[ion

/nferconnect/on Pro/t@s and Cost–F/na/ Report (Washington, DC:

DOE, June 1980), DOE/RA/29349-01.

51As discussed In M, Grarnarlis, et al,, “The Introduction of Nondlspatchable Technologies as Decision Variables in Long-Term Generation Expansion Models, ” /nstitute of f/ectricd/ and Electronic

Engfneers (/EEE) Transactions, vol. PAS-101, No. 8, August 1982,

pp. 2658-2667.

●

tions). A situation could arise whereupon the

demand of a particular customer class is reduced by the implementation of end-use devices or third-party generation pIants and,

consequently, customer rates must be increased to meet fixed revenue requirements. 52 Potential rate inequities may result,

particularly to those customers in an affected

rate class who do not use the demand-reducing device.

Research and development and regulatory

treatment.–As we will see in chapter 4,

most new generation technologies, today,

are not yet cost competitive with conventional alternatives. For promising new technologies, part of the difference between

current and mature costs represents the

amortization of R&D expenditures. An oftenused operational rule among many utility

commissions, however, is to permit plants

into the rate base only if they can generate

power at less than full avoided cost.53 T he

issue then becomes clear: to what extent will

the less than full avoided cost benchmark inhibit the commercialization of new technologies? If such a benchmark is relaxed, to

what degree should ratepayers share with

the stockholders the burden of higher per

unit capital costs, greater risk of lower reliability, possibility of complete plant failure,

and possibility of shorter plant life associated

with new technologies? Some studies suggest

that relaxed treatment of the full-avoided

cost benchmark is a prerequisite to significant penetration of many new technologies

(at least for demonstration and early commercial units) in utilities over the next two

decades. 54 This issue is discussed in more detail in chapter 10.

52Thls phenomenon occurred in 1973-74 In San Francisco with

local water utilities. Regional droughts motivated the utilities to subsidize advertising campaigns and various end-use devices for water

conservation. The resulting drop in demand was of such magnitude that the utilities were put in a position of having to fncrease

rates to meet their revenue requirements.

“L. Papay, “Barriers to the Accelerated Deployment of Renewable and Alternative Energy Resources, ” unpublished, Southern

California Edison Co,, December 1982.

$~lbld
70 • New Electric Power Technologies: Problems and Prospects for the 1990s

Current Activities and Interest in

Alternative Technology

Power Generation

The Edison Electric Institutess has observed four

degrees of current involvement (not mutually exclusive) in alternative technology power generation by U.S. utilities:

●

●

Use of alternative technologies as a substantial contributor to future resource plans.–

Some utilities which are historically highly

dependent on premium fuels (and hence

have a very high avoided cost rate), have significant demand growth, and have severe

environmental and regulatory constraints on

using conventional technologies have announced significant plans for reliance on

alternative technologies. As mentioned

earlier in the discussion, only two such U.S.

utilities, namely Southern California Edison

and Pacific Gas & Electric, have done so to

date.

Use of alternative technologies as a response to uncertain load growth.—Some

medium demand growth utilities, in response to environmental and regulatory

pressures, have included alternative technolJJEdison Ele~ric Institute, op. cit., 1984.

ogies as “an important but small” buffer in

future resource plans.

Use of unregulated subsidiaries for equity

participation in cogeneration.-Some financially sound utilities—e,g., Houston Lighting

& Power–in areas with cogeneration potential have been permitted by utility commissions to invest capital in cogeneration ventures with industry to avoid loss of load,

revenue, and earnings. This strategy is

termed “reactive diversification” as opposed

to “proactive diversification” which is aimed

at improving stockholder return on equity.

Active research and development.–Many

utilities, are involved in long-term research

and development with alternative generating technologies as a possible response to

various contingencies discussed earlier that

could limit the use of conventional generating technologies.

So far, the penetration of new technologies has

been very small. A great deal has happened in

the last several years, however, particularly in cogeneration. Most of this cogeneration is using

conventional technology, but some are new technologies such as AFBC. In addition, wind, lowhead hydroelectric, and biomass technologies are

also contributing. For the technologies considered in this assessment we discuss the historical

rate of development in detail in chapter 9.

SUMMARY AND CONCLUSIONS

The electric utility industry has experienced a Still facing a difficult and uncertain investment

period of considerable stress in recent years due decision environment, utilities have had to exto declining electricity demand growth; dramat- pand the scope of strategic options they are willically increasing fuel prices, construction costs, ing to consider over the next several decades to

and capital costs and heightened public demand include such strategies as rehabilitation of existfor better control of air and water pollution and ing plant, increased purchases from neighboring

nuclear safety. The industry emerged from this utilities, increased conservation and load manperiod of stress with significant uncertainties, agement efforts, diversification of investments to

especially about future demand growth, and nonutility lines of business and, finally, a range

financially weakened. While utilities’ financial of new generating technologies. Most utilities are

health appears to be improving markedly, they only beginning to consider such alternatives to

are not returning to their pre-1970s business traditional large-scale, central-station, powerstrategies. plants. In particular, conservation and load man-
Ch. 3—Electric Utilities in the 1990s: Planning for an Uncertain Future • 71

agement are beginning to attract more attention

in utility resource plans; and many utilities have

plant life extension or rehabilitation projects

underway. Similarly, in response to uncertain demand growth, mature smaller scale technologies

are under close scrutiny. For the most part,

smaller scale new technologies are under consideration primarily as a possible response to future contingencies such as oil supply disruption

or imposition of stricter environmental controls

on coal burning. There are a few exceptions,

notably Southern California Edison and Pacific

Gas & Electric in California. They have included

substantial commitments to new technologies in

their long-term resource plans.

To date, nonconventional technologies account

for only a tiny fraction of the Nation’s overall electric generating capacity, the new technologies’

penetration of the market is likely to grow

throughout the remainder of this decade and

throughout the 1990s.

Non utility involvement in new technologies is

increasing steadily under the provisions of PURPA

and the rate of development of new generating

technologies over the next two decades may well

hinge not only on the performance of these in

nonutility applications but also on the evolving

relationship between utilities, nonutility generators of power, and regulatory agencies.
Chapter 4

New Technologies for Generating

and Storing Electric Power

Advanced Batteries . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Summary occurrent Activity . . . . . . . . . . . . . . . . . . . . . . . . . . . .

List of Tables

Table No.

4-1. Developing Technologies Considered in OTA’s Analysis . .

4-2. Selected Alternative Generating and Storage Technologies:

Typical Sizes and Applications . . . . . . . . . . . . . . . . . . . . . . .

P’l<qt’

. . . . . . . . . . . . . . 7.5

. . . . . . . . . . . . . . . . . . . 76

4-3. Advantages and Disadvantages of Solar Thermal Electric Systems. . . . . . . . . . . . 88

4-4. Developing Technologies: Major Electric Plants Installed

or Under Construction by May 1, 1985 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .129

Chapter 4

New Technologies for Generating

and Storing Electric Power

INTRODUCTION

A number of new technologies for generating

and storing electricity are being developed as

alternatives to large-scale, long lead-time conventional powerplants. Of increasing interest are

technologies which are small scale and highly efficient, which are capable of using alternative

fuels, and/or which impose substantially lower

environmental impacts than conventional generating options.

This chapter focuses on new technologies

which, while generally not fully mature today,

could figure importantly in the electric-supply

technologies insta//ed in the 7990s. Not examined in detail are those technologies which already are considered technically mature or those

which are very unlikely to achieve wide deployment during that time. Only grid-connected applications are considered. The chapter also does

not examine closely technologies which recently

have been covered in other OTA reports.1

The new technologies covered in this report

are summarized in table 4-1. In table 4-2, the

technologies are grouped according to size and

application, along with their primary competitors.

They range in size from units less than 1 MWe

to units greater than 250 MWe. The technologies

can be divided between those in which the electrical power production is available upon utility

demand (dispatchable) and those where it is not.

In the table, dispatchable applications are further

broken down according to base, intermediate,

and peak load applications. Among applications

where the utility cannot summon electrical power

on command are intermittent technologies (e.g.,

wind turbines and direct solar equipment), when

1 These include nuclear power, convent io na I technologies used

In cogeneratlon,and conventional equ Ipment which uses biomass;

see p. IV of this report.

Table 4-1 .—Developing Technologies Considered in

OTA’s Analysisa

Photovoltaics:

Flat plate systems (tracking and nontracking)

Concentrators

Solar thermal electric:

Solar ponds

Central receivers

Parabolic troughs

Parabolic dishes

Wind turbines

Geothermal:

Dual flash

Binary (large and small)

Atmospheric fluid ized-bed combustors

Integrated gasification combined-cycle

Batteries

Lead acid

Zinc chloride

Compressed-air energy storage (large and small)

Phosphoric-acid fuel cells (large and small)

75
76 . New Electric Power Technologies: Problems and Prospects for the 1990s

Table 4-2.—Selected Alternative Generating and Storage Technologies: Typical Sizes and Applications

Typical configurations in the 1990s

GENERATING TECHNOLOGIES

Solar Technologies

Introduction

In seeking ways to directly exploit the Sun’s

energy to produce electric power, two alternatives are being pursued. Solar thermal-electric

technologies rely on the initial conversion of light

energy to thermal energy; the heat typically is

converted to mechanical energy and then to electric power. Alternatively, photovoltaic cells may

be used to directly convert the light energy into

electrical energy. Between the two technologies,

many variations are being developed, each with

its own combination of cost, performance, and

risk, and each with its own developmental

hurdles.

Most solar electric technologies promise noteworthy advantages over conventional technologies. 2 These include:

1. Free, secure, and renewable energy source:

These are especially important attributes

when contrasted with price and availability uncertainties of oil and natural gas.

2. Widely available energy source: Figure 7-

11 in chapter 7 illustrates the distribution

of the solar resource in the United States.

~Note that some solar technologies may use a su pplernental fuel

such as oil, gas, or biomass. In such instances, the hybrid system

will not have some of the advantages and disadvantages listed; and

the system will possess some advantages and disadvantages not

listed.
Ch. 4—New Technologies for Generating and Storing Electric Power . 77

3.

4.

5.

6.

7.

8.

9.

10,

No off-site, fuel-related impacts: The delivery of solar energy imposes no environmental impacts off-site, unlike the delivery

of conventional fuels which frequently require a series of steps (exploration, extraction, refining, transportation, etc.) which

each impose environmental impacts quite

distinct from those at the power plant site

itself.

No fuel supply infrastructure required: T he

delivery of solar energy does not require

the development of an ancillary fuel-supply

infrastructure as is the case with conventional fuels. A solar plant can operate remotely at any site; a coal plant could not

do so without the prior development of an

infrastructure which extracts, refines, and

transports the coal to the plant.

Short lead-times.

Wide range of installation sizes.

Dec/ining costs: Many of t he solar thermal

systems are experiencing declining costs,

a fact which reduces risk in any plans to

invest in the technologies.

Relative/y small water needs: Some of the

solar technologies require little water beyond that used for cleaning.

Litt/e or no routine emissions: Other than

thermal discharges and other than run-off

from washing operations, most solar technologies do not routinely emit large quantities of wastes into the air, water, or soil. j

Siting flexibility.

Though graced by many advantages, solar electric systems–like any other generating technologies—also have disadvantages. Among them are:

1. /intermittent supp/y of energy: Solar energy

is subject to uncontrollable and sometimes

unforeseeable variations. It is not always

there when needed. Most obviously, it completely ceases to be available every day for

extended periods (night) or its power is considerably diminished anytime clouds pass

between the Sun and the surface of the

Earth. in addition, seasonal and annual fluctuations in average solar radiation can be sig-

‘Dl~posa I of the tec h nology at the end of Its usefu I I Ifet I me may,

however, create serious ~~aste problems.

2.

3

4.

5.

6.

nificant. 4 And these fluctuations put stress

on hardware and can cause control problems.

Capita/ intensive: Current solar electric technologies are characterized by very high capital costs per kWe.

Land extensive: Solar systems use a lot of

land per unit of power. where land is expensive, land acquisition can greatly increase installation costs. where solar concentrators are spread over a large surface

area, soils and microclimates and local ecosystems can be affected.

Water usage: Some solar thermal systems

routinely require large quantities of water;

and all likely will require periodic cleaning.

Where units are used in arid areas, this may

be a problem.

Exposure to the elements and to malevolence: Many of the system components are

fully exposed. They therefore suffer from

erosion, corrosion, and other damage from

the wind, from moisture (including hail) and

contaminants in the air, and from temperature extremes. The systems also may be easy

targets for vandals or saboteurs. For these

reasons most solar electric installations are

enclosed by fences, often with some kind

of barrier for wind protection. And where

reflective mirrors are used, they frequently

are designed not to shatter and to withstand

the elements. A permanent security force

also may be required where the systems are

deployed, but their land extensiveness

makes security difficult.

Cost and difficuky of access: The likelihood

that the systems will be built in remote locations raises problems relating to site access

during construction and for maintenance.

Transmission access may also be difficult or

expensive to obtain.

Photovoltaics

introduction.–A photovoltaic (PV) cc// is a

thin wafer of semiconductors material which conqlt \vas reported, for example, that the solar flux at Solar One

a solar-thermal central receiver plant in California, has been 25 percent lower than in the base year (1 976) used for planning purposes

for the plant, This may be due to the increased atmospheric particulate load imposed by recent volcanic eruptions.

‘A semiconductor IS a material characterized by a conducti~lty

lying between that of an Insulator and that of a metal.
78 • New Electric Power Technologies: Problems and Prospects for the 1990s

verts sunlight directly into direct current (DC)

electricity by way of the photoelectric effect, Cells

are grouped into modules, which are encapsulated in a protective coating. Modules may be

connected to each other into panels, which then

are affixed to a support structure, forming an array (see figures 4-1 and 4-2). The array may be

fixed or movable, and is oriented towards the

Sun. Any number of arrays may be installed to

produce electric power which, after conversion

to alternating current (AC), may be fed into the

electric grid. I n a PV installation, all the components other than the modules themselves are collectively termed the balance-of-system.

At present, PV systems are being pursued in

many different forms. Each seeks some particular combination of cost and performance for the

module and for the balance-of-system. In a concentrator moduIe, lenses are used to focus sunIight received at the module’s surface onto a

much smaller surface area of cells (see figure 4-

2); all available concentrator systems follow the

Sun with two-axis tracking systems. A flat-plate

module is one in which the total area of the cells

used is close to the total area of sunlight hitting

the exposed surface of the module. Various

mechanisms such as mirrors can be used to divert light from adjacent spaces onto the exposed

surface of the modules. Flat-plate systems may

be fixed in position or may track the Sun with

either single or two-axis tracking systems.

The parallel development of these two types

of PV modules and systems reflects a basic technological problem: it is difficult to produce PV

cells which are both cheap and highly efficient.

Cheap cells tend to be inefficient; and highly efficient cells tend to be expensive. Some PV systems which are being developed for deployment

in the 1990s are emphasizing cells which are relatively cheap and inefficient; such cells are used

in flat-plate modules. Others are using a smaller

number of high-cost, high-efficiency cells in concentrator systems.

In either case, if PV systems are to compete

with other grid-connected generating technologies in the 1990s, their cost and overall risks will

have to come down and their performance will

Figure 4.1 .—Features of a Flat-Plate Photovoltaic System
Ch. 4—New Technologies for Generating and Storing Electric Power • 79

Figure 4-2.—Schematic of a Conceptual Design for a High Concentration Photovoltaic Array

Institute, 1984) EPRI AP-3263

have to improve. There is considerable disagreement over which particuIar PV system is the

strongest contender for this market. Market

penetration will depend on the current state of

the particular variety of PV system; the potential

for cost reductions and performance improvements; and on the reduction in risk perception

among prospective investors in grid-connected

instalIations.

At present, two types of modules appear to be

the leading contenders. One is the flat-plate module based on tandem cells made from amorphous

silicon; the other is the concentrator module,

probably using crystalline silicon.

There are a number of reasons why the concentrator module could be the photovoltaic technology of choice in central station applications

in the near term. The crystalline silicon cell is relatively well understood, as are the techniques for

making such cells. The cells have been manufactured for many years, and information on cell performance after extended exposure to the elements is rapidly accumulating. Concentrator

modules may offer a favorable combination of

cost and performance in the Southwest, where

early central station deployment probably will be

greatest. And the prospects are good that cost and

performance improvements can be made during

the balance of the century. Many of the improvements do not appear to require basic technical

advances but rather incremental improvements

and mass production.

Flat-plate modules using amorphous silicon

meanwhile are expected to continue to develop.

But basic technical improvements must be made
80 . New E/ectric Power Technologies: Problems and Prospects for the 1990s

before extensive grid-connected deployment will

occur. The current technology is too inefficient.

Efficiencies must be improved, and the performance of the improved modules must be established over time and under actual conditions. This

combination of technical improvements and the

need to establish a clear, long-term performance

record will take a substantial period of time. Because of this, amorphous-silicon flat-plates may

not offer a superior choice for central station applications until the latter part of the 1990s or later.

There is a small possibility, however, that rapid

improvement in the cost and performance of

amorphous modules is likely and that they will

compete successfully with concentrators during

most of the 1990s.

Regardless of technology, the commercial prospects for PV systems will depend heavily on continued technical development and the volume

of production. Factors influencing either technical development or production levels therefore

will strongly affect cost and performance in the

1990s.

The Typical Grid-Connected Photovoltaic

Plant in the 1990s.—ln the 1990s, central station

applications probably will be favored over dispersed applications. Indeed, by May 1985, approximately 19 MWe of PV power in multimegawatt central station installations were connected

to the grid in the United States—this was most

of the grid-connected PV capacity in the country. This capacity was divided roughly equally between concentrator and flat-plate modules. By

1995, as much as 4,730 MWe could be located

in such installations nationwide.b Capacity probably will be concentrated in California, Florida,

Hawaii, Arizona, and New Mexico.7

In this analysis, it is assumed that the typical

grid-connected photovoltaic system in the 1990s

is a centralized photovoltaic system (see figure

4-3). Unless otherwise stated, the numbers rebThis IS the range pro~’lded by Pieter Bos (Polydyne Inc.), as estimated in a submission at the OTA Workshop on Solar Photovoltalc Power (Washington, DC, June 12, 1984) and discussed by Maycock and Sherlekar (Paul D. Maycock and Vic S. Sherlekar,

Photo\ wltaic Technology, Performance, Cost and Market Forecast

to 1995. A Strategic Technology& Market Analysis (Alexandria, VA:

Photovoltaic Energy Systems, Inc., 1984), pp. 130-1 36.),

‘Ibid.
Ch. 4—New Technologies for Generating and Storing Electric Power • 81

Figure 4-3.—A View of a Recently Installed Photovoltaic Central Station

SOURCE ARCO Solar, Inc

such as dust abatement measures, vegetation

control efforts, and periodic cleaning of the

moduIes.

The lead-time required to deploy a PV plant

is potentially quite short, perhaps 2 years—including planning, licensing, permitting, construction, and other elements. Construction itself

should be quick and simple. Licensing and permitting should proceed very rapidly because

many of the environmental impacts are low relative to those associated with conventional technologies. However, large PV plants will be new

to most areas in the 1990s; and the land-extensive

character of the technology raises problems

which could engender controversy, leading to

regulatory delays.

System Cost and Performance.–Operating

availabilities of 90 to 100 percent are anticipated

for the multimegawatt PV installation of the

1990S.

10 This will be affected primarily by the

number of PCSS required and their quality. Most

operating large PV systems today are characterized by operating availabilities below this—

between 80 and 90 percent–usually as a result

of problems with the PCSS. I n order to reach the

expected range of operating availabilities, PCSS

must be developed which can operate reliably.

I (Ioperat I ng ay a I la bl [ Ity of I nd Ivld ua I arrays k~ I I I be between q 5

and 100 percent, depending mostly on the performance of trw ker~,

if they are used. Recent experwrwe with tra( kers su~ges[~ that their

operatl ng availahl I Itles shou Id not ta I I below that ra nm.

Ch. 4—New Technologies for Generating and Storing Electric Power • 83

Such systems now are being developed and may

be available during the 1990s.

Equipment lifetimes of up to 30 years are anticipated, but they will depend mostly on the lifetime of the modules, the trackers (if they are used)

and the PCS, and the lifetimes for all three types

of equipment are still uncertain. By far the most

important component in this regard is the module; degradation and failures may seriously

shorten its life.

Capacity factors will differ noticeably from system to system, depending on the general design

features as well as on the location of the system

and atmospheric conditions. In this analysis, capacity factorsll for fixed flat-plate systems vary

little–they range from 20 to 25 percent in Boston to 25 to 30 percent in Albuquerque. The capacity factors for tracking flat-plate systems are

assumed to range from 30 to 40 percent, ’ 2

though, this has yet to be verified nationwide.

The capacity factor for concentrator systems

varies by a larger margin by location—from 20

to 25 percent in Boston and Miami, to 30 to 35

percent in Albuquerque.

The modules and the balance of system (BOS)

jointly determine capital costs and efficiency.

Module cost and efficiency, as discussed above,

depends on whether the system utilizes flat-plate

modules or concentrator modules. Regardless of

moduIe or whether the array is fixed or tracking,

BOS efficiencies are likely to fall within the same

rough range. The costs of the BOS, however, will

vary greatly, depending on whether or not a

tracking system is used.

The typical multimegawatt flat-plate module PV

station in the 1990s probably will produce electric power with an efficiency between 8 to 14 percent. Capital costs are expected to range between

$1,000/kWe and $8,000/kWe in Albuquerque,

and higher elsewhere in the country. Instal lations

using concentrator modules should be more

efficient-with a 12 to 20 percent efficiency. Capital costs for concentrator moduIes i n Albuquerque should be between $1,000/kWe and $5,000/

I I Capacity factor 15 the ratio of the annual energy output ( kwe

(AC)) of a plant to the energy output (kWe (AC)) It would have had

if it operated continuously at Its nominal peak operating cond It ions.

I ZOTA ~tatt’ I ntervlew with D,G. Schueler, Manager, Solar Energy

Department, Sanc~ia Laboratories, Albuquerque, NM, Aug. 7, 1984.

kWe; costs will be higher in areas with lower

levels of direct sunlight.

Cost reductions and performance improvements in PV systems will require the deployment

of highly automated processes capable of mass

producing cells as well as efficiently producing

other components, such as tracking equipment

and lenses for concentrators.

Another important element of cell costs will be

the cost of silicon. If cell costs are to be driven

down, either the quantity of silicon consumed

per kilowatt-electrical of cell produced must be

reduced; or silicon costs must be lowered either

through new production techniques or by an expansion of silicon production capacity. More

material-efficient cells are being developed which

require less silicon per kilowatt-electrical produced. 13 Efforts are also underway to develop silicon production processes which can produce

low-cost silicon. There is a fair chance that these

silicon production processes will be successfully

developed and available in the 1990s.14 And evidence indicates that the additional silicon production capacity will be built when needed .15

PV plants should have low operating and maintenance costs—probably ranging from 4 to 28

mills/kWh in the 1990s. These estimates are

highly uncertain, though, and will only become

more definite as more systems are placed in the

field. Questions about module lifetimes, tracker

problems, and difficulties with the PCS make

operating and maintenance (O&M) cost projections uncertain.

Two other areas of uncertainty may increase

O&M costs. The first is that dirt accumulating on

the modules may reduce their efficiency. ’b Rain

13A god discussion of silicon and its importance as a driving force

behind the development of alternative PV technologies can be

found in: Paul D. Maycock and VIC S. Sherlekar, H-rotovo/faIc Technology, Performance, Cost and Market Forecast to 199.5. A Strategic Technology & Market Analysis, op. cit., 1984.

IALeonard J. Reiter, A probabj/istjc Ana/ysls o?’ .$ I/ICOn C05t ( Pasadena, CA: Jet Propulsion Laboratory, 1983), DOE/JPL/1012.

I SRObert V. Steele, ‘ ‘strategies on Poly, Photo ~’o/taics ]ntern.?-

tiona/, vol. 11, No. 4, August/September 1984, pp. 6-8.

lbFor example, in a module performance Wah JatiOn program conducted by the MIT Lincoln Laboratory and the Jet Propulsion Laboratory, “the greatest single cause of power loss has been soil accumu Iation. ’ (Edward C. Kern, Jr., and Marvin D. Pope,

Development and Evaluation o(Solar Photoi oltaic System~: Final

Report (Lexington, MA: ,MIT, 1983), DOE/ET/20279-240.
84 . New Electric Power Technologies: Problems and Prospects for the 1990s

has been found to be an effective cleaner, but

often the best areas for photovoltaics have little

rain. With flat-plate systems, dirt does not seem

to be as much of a problem as with concentrators. The second problem is wind damage. Most

existing photovoltaics and solar thermal plants

have suffered damage from wind blown sand,

though methods to prevent this are being developed.

Solar Thermal= Electric Powerplants

Technology Descriptions. -Solar thermal-electric plants convert radiant energy from the Sun

into thermal energy, a portion of which subsequently is transformed into electrical energy.

Among the systems, there are four which, with

some feasible combination of reduced costs and

risks and improved performance, could be deployed within the 1990s in competition with

other technologies and without special and exclusive Government subsidies. They are central

receivers, parabolic troughs, parabolic dishes,

and solar ponds. Brief descriptions of these technologies are provided below.

Centra/ Rece;ver.–A central receiver is characterized by a fixed receiver mounted on a tower

(see figure 4-6). Solar energy is reflected from a

large array of mirrors, known as heliostats, onto

the receiver. Each heliostat tracks the Sun on two

axes. The receiver absorbs the reflected sunlight,

and is heated to a high temperature. Within the

receiver is a medium (typically water, air, liquid

metal, or molten salt) which absorbs the receiver’s thermal energy and transports it away

from the receiver, where it is used to drive a turbine and generator, though it first may be stored.

Parabo/ic Dishes. –parabolic dishes consist of

many dish-shaped concentrators, each with a re-
Ch. 4—New Technologies for Generating and Storing Electric Power ● 8 5

ceiver mounted at the focal point. The concentrated heat may be utilized directly by a heat engine placed at the focal point (mounted-engine

parabolic dish); or a fluid may be heated at the

focal point and transmitted for remote use (remote-engine parabolic dish). Each dish/receiver

apparatus includes a two-axis tracking device,

support structures, and other equipment (see

figures 4-7, 4-8, and 4-9).

Solar Troughs.–With a parabolic trough, the

concentrators are curved in only one dimension,

forming long troughs. The trough tracks the Sun

on one axis, causing the trough to shift from east

to west as the Sun moves across the sky. A heat

transfer medium, usually an oil at high temperature (typically 200 to 400° C), is enclosed in a

tube located at the focal line. The typical installation consists of many troughs (see figure 4-1 O).

The oil-carrying tubes located at their focal lines

are connected on each end to a network of larger

pipes. The oil is circulated through the tubes

along the focal lines, flows into the larger pipes,

and is pumped to a central area where it can be

stored in tanks or used immediately. In either

case, it ultimately passes through a heat exchanger where it transfers energy to a working

fluid such as water or steam which in turn is

routed to a turbine generator. At the Solar Energy

Generating units in southern California, the only

large trough installations in the United States, the

oil’s heat is supplemented with a natural gas-fired

combustion system to obtain adequate steam

temperatures to drive the turbine. After passing

through the steam generator. The oil is used to

preheat water destined for the steam generator;

the oil may be returned to the trough field.

So/ar Pond.–In an ordinary body of open

water, an important mechanism which influences

the thermal characteristics of the reservoir is natural convection. Warmer water tends to rise to
the surface; and if the water is warmer than the

ambient air, it tends to lose its heat to the atmosphere. A solar pond (see figure 4-11) is designed

to inhibit this natural process. The creation of

three layers of water, with an extremely dense

layer at the bottom and the least dense layer at

the top, interferes with the movement of warmer

bottom waters toward the surface. Salt is used

to increase the density of the bottom layer, forming a brine, to the point where its temperature

can go as high as 227° F. The heat in this bottom layer can then be drawn off through a heat

exchanger, where the brine transfers its heat to

an organic working fluid which in turn can drive

an engine to produce electric power.

General Overview. –Within most of the above

mentioned technologies, many variations now

exist or could exist. The discussion here is confined to those variations which appear to affect

prospects for solar thermal-electric systems in the

1990s. The discussion is intended to be a brief

survey rather than exhaustive examination of the

technologies.

Each technology is characterized by a particular set of advantages and disadvantages (see table 4-3) which together define its prospects this

century. All of the technologies share a principal

disadvantage in that costs and performance are

currently uncertain. The level of uncertainty can

only be reduced sufficiently as commercial-sized

units are deployed and operated. In some cases,

research and development hurdles must still be

solved before commitments are likely to be made

to early commercial units, Until this occurs, the

chances for widespread commercial application

for any one technology during the 1990s are quite

small, regardless of the technology’s ultimate

promise. At least one operating system is required

to reduce cost and performance uncertainty to

a level where it no longer is a primary impediment to extensive investment; and perhaps several units—including early commercial units—

would be necessary. The time and expense associated with these early demonstration and commercial units are critical elements in determining the commercial prospects of the solar thermal

technologies in the 1990s.
While the need to reduce uncertainty is of

prime importance, efforts to improve cost and

performance through continued research and development also couId enhance the prospects for

the technologies in the 1990s. The primary R&D

needs are different for each technology though

generally efforts directed towards the development of low-cost, durable, and efficient concentrators, receivers, and heat engines are most important. ’ 7 Also very important will be the need

‘7More cktdtted Intormatmn on R&D needs for solar thermal technologies can be tou nd In Sandla Natlondl Laboratories, U.S. Department of Energy, ~li e Year Research and Dmdoprnent P/.?n

1985-1989, draft (Lltermore, CA: Sandia Natmnal Laboratories, Decem her 1984); and Edw a rci 1, t+. LI n, A Re\ Iew of the Sa/t Gradient

So/ar Pond Techno/og} (Pasadena, CA Jet Propulsion Laboratory,

1982I, DOE/SF-2 J52-l

for adequate data on the solar resource across

the country.18

Solar Ponds and Centra/ Receivers.– Neither

solar ponds nor central receivers appear to require major technical breakthroughs before they

can be commercially applied. But because no

commercial-scale solar ponds or central receivers

are now operating in the United States, because

none are now under construction in this country, and because of the long lead-times expected

for the installations, it will be very difficult to deploy enough demonstration and early commer18 B p .,G u ~>tcl, Soi.jr Thernl,]l Research Program, Ann ua I Resea r[ h

Plan, Fiscal Yedr 1985 (Golden, C() Solar Energy Rew~arch I nstl -

tute, 1984).

38-743 0 - 85 - 4
88 • New Electric power Technologies: Problems and Prospects for the 1990s

Figure 4-il.—Solar Pond Powerplant Concept

Condenser

1 4

Y

Generator

Pump

ry

1982).

Table 4-3.—Advantages and Disadvantages of Solar Thermal Electric Systems

Technology

Parabolic dishes Parabolic dishes Central

Characteristic Solar ponds Solar troughs (mounted-engine) (remote engine) receiver

Yes (+)

Yes (+)

Yes (+)

low ( – )

low (+)

low (–)

no (–)

yes (+)

yes (–)

med (0)

Yes (+)

No (–)

No (–)

high (+)

high (–)

high (+)

no (–)

no (–)

no (+)

low (+)

Total, all categories:

+ (major advantages) 5 5 5

– (major disadvantages) 5 4 5

● (moderate advan/disadvan) o 1 0

Total, categories 3-10:

+ (major advantages) 5 3 4

– (major disadvantages)

● (moderate advan/disadvan)

3 4 4

0 1 0

Yes (+)

Yes (+)

Yes (+)

low ( – )

low (+)

low (–)

no (–)

yes (–)

no (+)

— med (0)

5

4

1

3

4

1

No (–)

No (–)

Yes (+)

med (0)

low (+)

low (–)

no (–)

yes (+)

no (+)

med (Ž)

5

4

2

4

2

2

SOURCE: Office of Technology Assessment
Ch. 4—New Technologies for Generating and Storing Electric Power ● 8 9

cial units quickly enough to sufficiently reduce

uncertainty about cost and performance. Furthermore, the expense of such early units is high

enough that it is very unlikely that any entity or

group of entities outside of government presently

would invest in such units without special government incentives. In short, the time and expense associated just with reducing risks for these

two technologies strongly mitigate against the

provision of sizable amounts of electric power

by the technologies within the 1990s. It is likely

that only a sizable and immediate government

intervention to encourage rapid deployment of

demonstration units and subsequent units could

reduce uncertainty to the point where it no longer

is a major impediment to commercial investment

in the 1990s.

Should such intervention occur and if the potential advantages of the solar ponds and central

receivers are realized, both technologies offer

favorable balances of advantages and disadvantages which could stimulate considerable private

investment in the 1990s. Between the two technologies, the central receiver probably would be

most widely deployed. Solar ponds must be located in areas where land, water, and salt are

plentiful. Such sites are far less common than the

sites available to central receivers, which require

considerably less land, less water, and do not require such large quantities of salt. Siting options

therefore are greater with the central receiver. 19

Furthermore, the central receiver is a more mature technology. A 10 MWe (net) pilot facility,

Solar One, has operated successfully in southern

California since 1982; and a small experimental

facility, rated at 0.75 MWe (gross) has been operated in New Mexico .*” Small central receivers

also have been built and operated overseas, but

no solar pond has ever produced electric power

in the United States. However, a 5 MWe unit is

in operation in Israel and several ponds have

——

lgFOr a ~lscussion Of the so[ar pond’s prospects in California, and

of the II m Itat Ions regard I ng sites, see Marshal F. Merriam, E/ectriclty Generation from Ncm-Corrvectlve Solar Ponds in Ca/lt’ornia (Berkeley, CA: Universitywlde Energy Research Group, December

1983), UER-109,

20john T. Holmes, “The Solar Molten Salt Electric Experiment, ”

Advanced Energy Systems–Their Role in Our Future: Proceedings

of the 19th /ntersociety Energy Conversion Engineenng Conference,

Aug. 19-24, 1984, (San Francisco, CA: American Nuclear Society,

1984), Paper 849521,

been built and operated in the United States and

elsewhere for applications other than the production of electricity. The solar pond concept however is considered to be well established and the

successful commercial deployment of the technology is not expected to require any major technical breakthroughs. *1

Parabolic Troughs and Dishes.– Unlike the

ponds and central receivers, parabolic dishes and

parabolic troughs already have been deployed

in commercial-scale units. Indeed, commercial

installations financed by private investors assisted

by the Renewable Energy Tax Credits now are

operating. Further demonstration and early commercial units are being planned over the next 5

years, though the extent to which the plans are

realized depends heavily on Government tax policies or funding, As current units continue to

operate, and as new units are added, the level

of uncertainty and risk associated with the technologies will continue to drop.

At present, the parabolic trough is the most

mature of the solar thermal electric technologies,

with commercial units operating, under construction, and planned. Nearly 14 MWe (net) of privately financed capacity already is operating in

southern California at the Solar Electric Generating System-1 (S EGS-I); an additional 30 MWe

(net), the Solar Electric Generating System-n

(SEGS-11), now is being built. Additional capacity— 150 MWe or more—may be added by early

1989. if the energy tax credits are extended in

some form. Whatever the case, by 1990 more

commercial experience will have been logged

with this technology than any other solar thermalelectric alternative. The resultant low level of risk

will constitute an important advantage for this

technology. Other important advantages will be

the technology’s inherent storage capacity and

the relatively wide variety of markets to which

it could be applied—including industrial processheat applications.

21 See: I ) N4assach usetts I nstltute of Technology, A state-o~-fheArt Study of Noncon\wcti\e So/ar Ponds for Power Generation (Palo

Alto, CA: Electric Power Research Institute, January 198S), EPRI AP3842. 2) Edward I.H. Lln, A Retlew ot’the Sa/t Gradient SoL~r Pond

Technology, op. cit., 1982,
90 Ž New Electric Power Technologies: Problems and Prospects for the 1990s

But the troughs are saddled with several serious disadvantages which to some extent will constrain deployment. The technology’s low efficiency is its most serious disadvantage. Another

is the need by the SEGS units for a supplementary fuel such as oil or gas, and for considerable

volumes of water. Finally, the system of conduits

through which the heat-absorbing oil flows may

develop problems or the oil itself may degrade

at an excessive rate; these potential problems

have not yet materialized at the SEGS-I installation, but further operating experience is required

before long-term performance can be proven.

Two types of parabolic dishes may be deployed in the 1990s: the mounted-engine parabolic dish and the remote-engine parabolic dish.

Each offers many design options. The primary advantages of the mounted-engine units are their

high efficiencies, low water consumption, and

ability to operate without supplemental fuel. The

small size of the basic electricity-producing module also carries with it advantages. The system

may be installed in many sizes, and multi module

installations may produce electric power long before the full installation is completed; individual

moduIes or groups of moduIes may begin operating while others are being installed. Together

these advantages provide the technology with

considerable siting flexibility and potentially very

short lead-times.

The largest disadvantage of the mounted-engine

unit is the relatively high level of uncertainty

about its performance, and the possibility that the

engines may require an excessive amount of

maintenance. Only three commercial-scale demonstration units—at about 25 kWe (net) each—

had been deployed by May 1985, and few are

scheduled to be deployed by 199o; no commercial installation yet exists, or is under construction. Other disadvantages include the lack of storage capacity and the inability to readily adapt the

technology to cogeneration or nonelectric applications.

The remote-engine dishes, like the troughs, enjoy the advantage of being used at present in a

commercial installation. A 3.6 MWe system, built

by LaJet, Inc., now is operating in southern California. Also, like the troughs, the remote-engine

technology may use as few as one or two engines;

engine-related O&M costs therefore could be

much lower than those of the mounted-engine

parabolic dishes. The remote-engine technology

in addition may be easily used for nonelectric applications. The LaJet design at present does not

require a supplemental fuel.

But the remote engine technology is inefficient;

much heat is lost as the heat transfer fluid is

pumped from the collector field to the turbines.

Also, the system has little storage capacity; electricity production therefore cannot be deferred

for very long. And unlike the mounted-engine

units, the remote-engine technology consumes

sizable volumes of water.

Both dishes and troughs suffer from the same

serious problem—they lack the cost and performance certainty which can only be gained through

more commercial-size operations. This mitigates

against private sector investment which is not in

some manner accompanied by government support. At the current pace, it is uncertain whether

the situation will change over the next 5 to 10

years.

Generally, capital costs will have to be reduced

and performance improved if the technologies

are to be deployed. To some extent this can be

fostered by research oriented towards incremental improvements of the commercial-scale

systems now operating. The most useful research

would concentrate on low-cost, durable, and

highly reflective reflector materials and inexpensive, long-lasting receivers and engines. But if the

technologies are to be extensively deployed in

the 199os, the greatest overall need is to reduce

uncertainty and thereby increase demand to the

point where economies of scale can drive costs

down.

By virtue of the fact that commercial-scale systems now are operating for troughs and dishes,

the level of cost and performance uncertainty

among the troughs and dishes will be considerably lower than the uncertainty associated with

the central receiver and ponds in the 1990s. Between troughs and dishes, uncertainty will be

lowest for troughs, highest for the mountedengine dishes, and somewhere in between for

remote-engine dish systems.
Ch. 4—New Technologies for Generating and Storing Electric Power ● 9 1

The mounted-engine dishes, in particular could

benefit from greater deployment of commercialscale units. A considerable reduction in uncertainty and greatly improved commercial prospects might result. Under such conditions, the

mounted-engine parabolic dishes could eliminate

the current lead enjoyed by parabolic troughs

among the solar thermal technologies. If the engines perform well, the parabolic dish technology could well become the prevalent choice for

solar thermal electricity production in the 1990s.

Typical Solar Thermal-Electric Installation for

the 1990s.—The precise cost and performance

of the solar thermal-electric systems in the 1990s

will vary widely according to system design, location, overall market size, risk, and many other

factors. No attempt here is made to fully discuss

the cost, performance, and uncertainty of all the

many solar thermal technologies. Rather, a single technology–the mounted-engine parabolic

dish–is examined in fuller detail and used for

reference purposes. The cost and performance

numbers shown i n appendix A, table A-2 for the

mounted-engine parabolic dish installation in the

1990s represent reasonable estimates, but obviously should be viewed with caution.

By 1995, mounted-engine parabolic-dish plants

might account for up to 200 MWe of installed capacity, The deployment level depends mostly on

the extent of Government support over the next

5 to 10 years–primarily the Renewable Energy

Tax Credit—and avoided cost rates.

The reference plant used in this analysis consists of 400 electricity producing modules, each

independently tracking the Sun and producing

electric power. The plant would have a gross capacity of 10.8 MWe and a net capacity of 10.2

MWe–the 0.6 MWe difference goes primarily to

driving the tracking motors which keep the dish

properly oriented toward the Sun during the day,

and to cooling the engine. Other equipment required on the site include a central control unit,

electric power subsystems, buildings, maintenance facilities, and other equip ment.22

z~whc re Stlrllng Pnglnes are used, the other equipment Includes

system~ which pressu rlze hydrogen for use i n the Stirling engines,

The amount of time required to build the plant

should be very short, perhaps 2 years. The greatest uncertainty in this estimate lies with permitting and licensing. A large area of land—approximately 67 acres—would be required for the

installation; the impacts of the development

would be extensive. The most obvious impact

would be visual, arising from the modules, roads,

and transmission lines (see figure 4-7). Serious impacts on the soil and vegetation of the area could

also occur. Installations in the 1990s probably

would be concentrated in arid areas which have

fragile soil and plant communities. Regulatory delays could result from concerns over all these impacts. Indeed, such problems reportedly have delayed the planned expansion of LaJet’s Solarplant

1 facility in southern California (see box 7B in

chapter 7).

The overall operating availability23 of the installation could be quite high for several reasons.

Routine maintenance could be conducted at

night. Should a module not be working during

the day, its incapacity would not impede the

operation of other modules. As long as large numbers of unpredictable failures do not occur (as

for example might happen after a severe and

damaging storm), then high operating availabilities for the system as a whole can be maintained.

The reference system used in this analysis is

characterized by operating availabilities of 95

percent.

The expected plant lifetime is 30 years. Many

of the components are relatively simple and durable. The power conversion unit (PCU) located at

the focal point, which uses relatively unproven

technology, is the component which creates the

greatest uncertainty about plant lifetime, It is anticipated, however, that with a regular and perhaps expensive maintenance pregram, this uncertainty can be greatly reduced, although further

development is needed to assure this.

z }Operatlng ava(labl Ilty here refers to the average percentage Of

modules capable of operating between sunrise and sunset. A 95

percent availability indicates that during the average day, s percent of the modules are not operating.
92 . New Electric Power Technologies: Problems and Prospects for the 1990s

Wind Turbines

Introduction

A wind turbine converts wind into useful mechanical or electrical energy. Wind turbines may

be classified according to the amount of electricity they generate under specified wind conditions. A small turbine generates up to 200 kWe,

an intermediate-sized turbine can deliver from

100 to 1,000 kWe, and a large system may produce more than 1 MWe.

Since the early 197os, the development of wind

technologies for electric power production has

followed two relatively distinct paths–one directed towards small turbines and the other

towards the large machines. As the efforts relating to the large turbines bogged down with technical and economic problems, the small turbines

—aided by State and Federal tax incentives—

progressed very rapidly. In the early 1980s, wind

turbines were extensively deployed, mostly in

California, where 8,469 turbines were operating

by the end of 1984. The total capacity of these

units was approximately 550 MWe. Almost all

were erected at windy locations, in clusters called

“wind farms. ” By the end of 1984, many thousands of wind machines, with a total installed capacity of over 650 MWe, were producing electric power in the United States, and almost all

were small turbines (see figure 4-I 2).

As operating experience accumulated with the

small machines, both manufacturers and investors began to gravitate towards intermediate-sized

machines. By the end of 1984, intermediate-sized

machines were being deployed in small numbers.

It is widely believed that if large numbers of wind

turbines are to be manufactured and deployed

in the 1990s, in free competition with other

generating technologies, intermediate-sized machines probably will be favored over both small

and large machines. Only the intermediate-sized

machines promise sufficiently cheap power without imposing unacceptable risks (figure 4-13 illustrates a intermediate-sized vertical-axis wind

turbine).

While it appears that the total installed capacity of wind turbines in the United States may exceed 1,000 MWe by 1985, the rate of subsequent

Figure 4-12.—Maintenance Crews Performing

a Routine Inspection of a Small Wind Turbine

SOURCE: U.S. Windpower, Ed Linton, Photographer

deployment is a matter of speculation. Given the

short time within which a wind farm can be deployed and operated–from 1 to 2 years, excluding wind data gathering—growth u rider favorable circumstances could be extremely rapid. it

is possible that the market potential for wind turbines could be as high as 21,000 MWe for the

1990-2000 period. 24

The areas most favored for wind farms are those

with good wind resources, heavy reliance on oil

or gas, and with an expected need for additional

generating capacity. They are located mostly in

California, the Northeast, Texas, and Oklahoma.

There are, however, less extensive but nevertheless promising opportunities elsewhere in the

country, especially in parts of the Northwest,

Michigan, and Kansas.25 Most–though not all–

Zqscience Applications International Corp., Ear/y Market Potef?-

tial for Utility Applications of Wind Turbines, Preliminary Dratl (Palo

Alto, CA: Electric Power Research Institute, December 1984), EPRI

Research Project 1976-1.

ZSlbld,
Ch. 4—New Technologies for Generating and Storing Eleclric Power ● 9 3

Figure 4-13. —A 500 kW Vertical”Axis Wind Turbine

SOURCE Southern California Edison Co.

turbines probably will continue to be installed in

relatively large wind farms rather than individually or in small clusters. Figure 7-10 in chapter

7 indicates the distribution of the wind resource

and the areas of the United States where wind

development is most favored.

A Typical Wind Farm in the 1990s

The reference wind farm used in this analysis

is summarized in appendix A, table A-4. A typical wind farm in the 1990s may consist of up to

several hundred, 200 to 600 kWe wind turbines;

the reference wind farm consists of 50 turbines

with ratings of 400 kWe each. Installations could

vary widely in the number of turbines deployed

or in their exact ratings. But based on current projections, the important cost and performance

characteristics would be common to the average

facility considered by investors during that

decade.

In addition to the turbines themselves, related

equipment will be necessary at the site, including power conditioning equipment, system protection devices, security fencing, metering devices

for measuring turbine output, wind measuring

equipment for monitoring site conditions and

equipment performance, control buildings, and

a fabrication yard where equipment is stored and

assembled .26

The turbines of the reference wind farm would

be distributed over an area of anywhere from 300

to 2,OOO acres, depending on the topography,

prevailing wind direction, the shape and orientation of the property on which the farm is located, and the size of turbines being used. The

turbines are spaced to avoid excessive interference with each other. Because installation and

maintenance of the turbines requires vehicular

access, at least one road leads to a wind farm and

to each individual wind turbine (see figure 4-14)

unless topography, surface characteristics, and

regulations allow access without roads. Since the

performance of the turbines and the cost of their

power depends directly on wind exposure, all

major obstructions such as trees would be removed. 27

It is evident that the major environmental impacts of wind farms will result from their initial

construction as well as from their high visibility,

their extensive road networks, and from the activities of maintenance crews on the roads and

around the turbines.28 Among the other impacts,

the severity of which may be assessed less readily but which nevertheless are considered potentially serious, are those associated with the noise

created by turbine operation.

Concern over environmental impacts could

seriously delay the deployment of wind turbines.

zbsanl sa~l~r, @ al,, t~fl~~} Lanci O\~mer\ ~uldf? [%km, OR: ~~Kgon Department of Energy, 1984), p. 17,

ZTlt shou Id be noted that many prl me MI nd sites, bel ng expoied

to frequent h Igh velocity winds, are I n hospitable en~)ronrnents for

:rees and therefore treq uently are devoid of large, upright trees

wh Ich COU Id be con fdered serious obstructions.

“’’Wind Farms, Timber Logging May Have Similar En\ ironmental

Impacts, Har\ard’s Turner Says, ” So/,?r /nte//igence Report, Not.

26, 1984, p. 375,
94 ● New E/ectric Power Technologies: Problems and Prospects for the 1990s

Figure 4-14.—Aerial View of a Wind Farm in the Altamont Pass in California
Ch. 4—New Technologies for Generating and Storing Electric Power ● 9 5

sited in windy areas. Under these favorable conditions, typical capacity factors between 20 and

35 percent are expected in the 1990s as the

intermediate-sized turbine technology matures.

As the performance of wind turbines improves

and is better understood, one especially large uncertainty still remains in estimating the annual

outputs of turbines in the 199os: the quality of

the wind resource to which the turbines will be

applied. Today’s turbines are exploiting some of

the best wind resources available. But new sites

will be required, and the average quality of new

sites probably will decline. High capacity factors

wiII be progressively more difficuIt to maintain.

At present, it is difficult to predict what wind regimes will characterize new sites exploited in the

1990s, because sufficiently detailed, site-specific

wind data are not yet available in most instances.

Information is accumulating, however, and it suggests that there remain considerable areas of land

available with high-quality wind resources.

The lifetime of a wind farm is somewhat difficult to determine because individual turbines and

even components of turbines can be replaced as

needed; in a sense, the wind farm itself can outlive any of its individual components. Generally,

the components of a wind farm in the 1990s will

be designed to last 20 to 30 years, though some

key components–such as the rotor–may fail and

be replaced before that time.

Wind Farm Costs.–The average capital cost

for wind turbines installed on California wind

farms in 1984 was $1,860/kWe.2g This capital cost

however is heavily inflated as a result of the

financing arrangements associated with current

projects; one observer has estimated that in fact

actual costs would be closer to $1,330/kWe if the

financing mechanisms typical of utilities were

used .30

The capital costs of the typical wind farm in the

1990s may range from $900 to $1,200/kWe. The

reduced capital cost will resuIt both from design

zgconver5ation between MI ke Bat ham, Californ id Energy COrnmlsston, and OTA staff, Feb. 5, 1985. See also ‘ ‘California Adds 366

MWe of Wind Capacity; Size, Capacity Factor Up, ” Solar Energy

Intelligence Report, Jan. 28, 1985, p. 30.

JODonalcf A. Baln, wind Energy Specialist, Renewable Resources,

Oregon Department of Energy, conversation with OTA staff, June

11, 1985.

improvements and from the more competitive

market expected when the current favorable tax

treatment is phased out. Termination or phaseout of the Federal and California State tax credits,

for example, would very likely contribute to decreases in the capital costs.

Operating and maintenance costs for the wind

farms of the 1990s could range between 6 and

14 mills/kWh. Available evidence indicates that

costs for small turbines i n 1984 ranged between

15 and 25 mills/kWh.sl The high O&M costs

which thus far have been incurred can be attributed to the fact that the first generations of

machines, those deployed in the early 1980s,

were plagued with mechanical problems. Changes

in two areas will stimulate the reduced O&M

costs: smaller numbers of turbines per kilowatthour generated and improved turbine design, Of

central importance will be the maintenance of

high operating availability.

An important cost associated with wind-generated electric power is the cost of access to the

wind itself—if indeed access can be gained at any

cost. The fee charged by the landowner typically

is either in the form of a minimum rent, royalty

payments, or some combination of the two.32

Costs of access have increased substantially; landowners have already begun to appreciate the

value of prime sites, particuIarly i n California .33

There, in 1984, annual land charges commonly

amounted to 6 to 13 percent of gross revenues

from the sale of the electricity over the lifetime

of the contract negotiated between the developer

and the landowner. 34

The prospects for wind turbines in the 1990s

would be enhanced by research and development. Among the most important R&D items are

the need to better understand turbulence and

predict its effects; to more readily and accurately

g’ “Wind Turbine Operating Experience and Trends, ” EPRI Journa/, November 1984, pp. 44-46.

32 For a discussion of the determ i nat ton ot’ w I nd resource va I ue

and contractual arrangements see: Sam Sadler, et al., Windy Land

Owners’ Guide, op. cit., 1984.

gJTeknekron Research, cost Estimates and Cost-Forecasting Methodologies for Selected Non-Conventional Electrical Generation

Techrro/ogies (Sacramento, CA: California Energy Commission, May

1982).

gdconversationbetween Mike Batham (California Energy Commission) and OTA staff, Nov. 30, 1984.
96 • New Electric Power Technologies: Problems and Prospects for the 1990s

model structural dynamics; to better predict noise

problems; to accurately model wind farm cost

and performance; and to develop, test, and

characterize materials and components. The development of cheap, reliable, and accurate wind

measurement instruments as well as better understanding and prediction of the wind’s characteristics also are needed. Detailed and accurate

assessments of the wind resource nationwide are

necessary too.35

Geothermal Power

moderate temperature range (1 50 to 250o F). 37

Geothermal development has in the past focused

on the high-quality, vapor-dominated reservoirs,

which are confined to limited areas of the United

States,

The equipment required to exploit these highquality resources is commercially available, and

no major changes in the basic characteristic of

the technology is likely during this century. There

are available improved technologies, however,

which not only could more economically exploit

the high-quality resource, but also may economically tap the much more plentiful resources of

lesser quality. Among these are single-flash, dualflash, binary, and total flow systems.

The single-flash technology has been commercially deployed in the United States. Because this

analysis focuses on technologies which are not

already technologically mature, the single-flash

technology will not be examined here. The total

flow systems also will not be discussed, since they

either require considerable further technical development, or will be applied only to a small

number of high-quality sites i n the United States.

The total flow systems therefore are unlikely to

constitute more than a small fraction of geothermal capacity additions in the 1990s. The dualflash and binary systems will constitute the most

important new technologies applied to the liquiddominated geothermal resource in the 1990s,

and, therefore, are the subject of this analysis.

Geothermal Power Technology

Before the resource is exploited to produced

electric power, it must be located and assessed.

This itself is a time-consuming, expensive process involving its own particu tar set of technologies

and problems. Ultimately, resource assessment

requires building roads, transporting drilling

equipment to the site, constructing the rigs and

drilling. Once the resource has been satisfactorily

measured, the thermal energy next must be

brought to the surface where it can be used. This

too involves particular technologies and difficul-

~7M. Nathenson, “High-Temperature Geothermal Resources in

Hydrothermal Convection Systems In the United States, ” Proceedings otthe Se~enth Annu,il Geotherm,jl Conference and workshop,

Altas Corp. (cd. ) (Palo Alto, CA: Electrlc Power Research Institute,

1983), EPRI AP-3271 , pp. 7-1 to 7-2.
Ch. 4—New Technologies for Generating and Storing Electric Power ● 9 7

ties. An especially important technological hurdle which remains to be satisfactorily overcome

is the development of cheap, reliable "downhole” pumps capable of moving the brine from

the underground reservoir, and subsequently

reinfecting it. While the brine is at the surface,

a portion of its thermal energy is drawn off and

used to produce electric power.

Dual-Flash Systems.–Figure 4-15 illustrates the

typical dual-flash unit. When liquid-dominated,

high temperature brine–300 to several thousand

pounds per square inch (psia) and 410 to 6000 F

—reaches the surface, a portion of the brine

“flashes” into steam. First, a high pressure flashtank processes the geothermal brine into saturated steam and spent brine, The steam enters

one inlet of a dual-inlet turbine, while the unflashed brine goes on to a second, lower pressure flash-tank. The second-stage flash-tank

produces further steam which is routed to the

other inlets of the turbine. The remaining unflashed brine then is reinfected underground.

After exiting the turbines, the steam passes

through a condenser, where it transfers its heat

to a stream of cooling water. The cooling water

is then routed to a cooling apparatus. Current designs use “wet cooling” devices in which the hot

water is sprayed into the air and discharges its

heat mostly through evaporation, The remaining

water is recirculated to the condenser to repeat

the cycle, along with “make-up” water required

to compensate for evaporative losses. The condensed steam from the turbine is reinfected into

the geothermal reservoir to help maintain reservoir pressure.

The make-up water requirements may be extremely large. The 50 MWe reference plant used

in this analysis would require about 3 million gallons of make-up water daily, roughly six times the

amount of water required by an atmospheric

fluid ized-bed combustor of comparable net generating capacity. The water requirements could

be reduced with “dry-cooling” systems; but these

are very expensive and reduce the plant’s overall efficiency.

Figure 4-15.—Schematic of Dual-Flash Geothermal Powerplant

Turbine-generator

First stage

I

o2

flash vessel

(high pressure)

Concentrated

1

I

07
98 ● New Electric Power Technologies: Problems and Prospects for the 1990s

Alternatively, the water requirement could be

greatly reduced by meeting it in part with the condensed steam from the condenser (instead of reinfecting it into the reservoir). This can only be

done, however, to the degree allowed by contractual agreements and regulations. The field developer may require that all or part of the condensed steam be reinfected into the geothermal

reservoir to maintain the quality of the resource.

Or regulators may require some degree of reinfection in order to reduce subsidence problems.

The basic turbine, condenser, and cooling

tower subsystem are similar to traditional steam

powerplant designs, although there are significant

differences. An important factor in the use of flash

technology is the existence of noncondensable

gases and/or entrained solids in the brine. These

contaminants can cause scaling, corrosion, and

erosion within the flash equipment, surface piping, and reinfection well casing. Development of

highly saline resources has been slowed by these

problems. Considerable research has been conducted to develop and demonstrate reliable

removal technologies for these resources.

Although, operational dual-flash units abroad

total 396 MW,38 there is little commercial experience with these systems in the United States.

None is now operating, and only one 47 MWe

(net) dual-flash unit is under construction (see figure 4-1 6). Nevertl~eless, the dual-flash system will

be used increasingly to exploit moderate to high

temperature hydrothermal resources because it

is more efficient than the single-flash system .39

Appendix A, table A-5 contains cost and performance estimates for dual-flash units in the

1990s. By the reference year 1995, dual-flash geothermal units will most likely range in size from

40 to 50 MWe. The expense of smaller units

‘8R. Dipippo, “Worldwide Geothermal Power Development:

1984 Overview and Update,” Altas Corp. (cd.), Proceedings of the

Eighth Annual Geothermal Conference and Workshop (Palo Alto,

CA: Electric Power Research Institute, 1984), EPRI AP-3686, pp. 6-

1 through 6-15.

jgThe Electric power Research Institute (persona! communication

between E. Hughes (EPRI) and OTA staff, Oct. 4, 1984) predicts

that most of the planned flash plants at the Salton Sea and Brawley

resources will use dual-flash technology.

Figure 4-17.–Simplified Process Flow Diagram of Binary Cycle Technology

I

surface condensers (instead of direct contact condensers).

The major advantages of binary cycles relate

to efficiency, modularity, and environmental considerations. First, working fluids in binary cycles

can have thermodynamic characteristics superior

to steam, resulting in a more efficient cycle over

the same temperature difference. QB Second, binary cycles operate efficiently at a wide range of

plant sizes. Especially attractive are small plants

which, in addition to encouraging short leadtimes, have many other important advantages as

well. Third, since the brine is kept under pressure and reinfected after leaving the heat exchanger, air pollution, e.g., hydrogen sulfide,

from binary plants can be tightly controlled.

There are also several other cost and efficiency

advantages of binary technology over the clualflash systems. Nevertheless, the dual-loop design

of binary cycles is more complex and costly than

a flash design.

~Ep B[ai r, et al,, Geothermal Energy. Investment Decisions and

Comrnercl~/ Development (New York: John Wiley & Sons, 1982).

Binary cycle technology is in developmental

stages with few large operational generating units.

By the end of 1985, one large 45 MWe (net) binary plant will have been installed near Heber,

California (see figure 4-1 8); in addition, small binary plants, with a total capacity of about 30

MWe, will be operating. 49 This will account for

most of the binary capacity installed worldwide.

Development is expected to proceed, and extensive commercial deployment is feasible in the

1990s.

The expected cost and performance of binary

geothermal plants in the 1990s are summarized

in appendix A, table A-5. Data is provided for two

reference plants, a large plant of about 50 MWe

(net) and a small plant of about 7 MWe (net). The

large plant could require up to 20 acres of land

for the powerplant and for the maze of piping

required for both the brine and the working fluid.

The small unit might occupy 3 acres or Iess.so As

with the the dual-flash technology, very large

‘

9 Ronald DiPippo, “Worldwide Geothermal Power Development:

1984 Overview and Update, ” op. cit., 1984.

~Opersonal communication between H. Ram (Ormat, Inc. ) and

OTA staff, Oct. 6, 1984.
Ch. 4—New Technologies for Generating and Storing E/ectric Power ● 101

Figure 4-18.—Artist’s Conception of the Heber, CA, Binary Geothermal Installation

SOURCE San Diego Gas & Electrlc Co

volumes of cooling water are required; indeed,

the water requirements are even larger than the

dual-flash units. The large plant would require

over 4 million gallons each day. The smaller plant

would need about 0.6 million gallons per day.

Small plants of about 5 to 10 MWe (net) can

be erected and operating on a site in only 100

days. But prior licensing, permitting, and other

preconstruction activities could extend the leadtime to 1 year.5

’ Construction of larger binary

units shouId take only 1 1⁄2 to 2 years.52 But here

too, overall lead-times will be longer because of

preconstruction activities, including licensing and

“Wood & Associates, a geothermal energy developer, has had

permitting problems at the county, State, and Federal level at Its

site near Mammoth Lakes, CA.

‘zSan Diego Gas & Ele[ trlc also had problems getting their large

binary plant through the permitting process, Its problems, howeier,

were encountered during the California Publ K Uti Iities Comml+

slon’s plant dpprok al process.

permitting. About 5 years total might be required

for the first plant at a resource, and 3 years might

be necessary for subsequent additions. With both

small and large plants, problems about water requirements and environmental impacts could

seriously extend the licensing and permitting

process.

Binary cycle plants are designed to operate

continually in base load operation. Availability

is expected to be between 85 and 90 percent,

and capacity factors are likely to be in the 75 to

80 percent range. Binary pIants should last at least

30 years.

The net brine effectiveness of binary cycle

plants may vary between 7 and 12 Wh/lb of steam

at a 4000 F resource. Advanced binary technology in the larger sizes should increase present effectiveness values at Heber from 9.5 to 12 Wh/
102 ● New Electric Power Technologies: Problems and Prospects for the 1990s

●

●

●

●

●

●

responsiveness to changes in desired output,

short lead-times,

easily recovered waste heat,

fuel flexibility,

off-site manufacturing, and

ability to operate unattended.

Most of the commercial demonstration plants

crucial to the future of the fuel cell will not begin operations until the late 1980s, though by May

1985, a 4.5 MWe demonstration plant was operating successfully in Japan and thirty-eight 40-

kWe demonstration units were operating in the

United States.ss Should the performance of the

demonstration units be very good, limited quantities of commercial fuel cells may be produced

at the earliest at the end of this decade or the

beginning of the next.5G 57

The level of deployment depends heavily on

the success of the demonstration units; the period

of time deemed necessary to generate investor

confidence; and the willingness of the vendors

to share the risk and cost of the early units, The

perceptions and decisions of investors, vendors

and buyers cannot be accurately and confidently

predicted, but current evidence suggests that the

early 1990s may see the beginnings of fuel-cell

mass production and the first commercial applications. As much as 1,200 MWe of fuel cell powerplant capacity may be operating by 1995.

The low production levels will drive installed

capital costs down somewhat, but they will remain far above possible costs in a mature market. High-volume mass production is unlikely to

occur until a sizable market is anticipated—in the

mid-l990s at the earliest. Such a market may develop as investors observe the continued operation of the demonstration units and the initial

operation of the early commercial installations.

Most important to the prospective investors will

be operating and maintenance costs, economic

ssjw staniunas, et al,, United Technologies Corp., Eo//ow’-On

40-kWtn Field Test Support, Annual Report (July 1983 -Jurre 1984)

(Chicago, IL: Gas Research Institute, 1984), FCR-6494, GR1-84/0131.

JGpeter H Unt, Ana/ysjs of Equipment Manufacturers and Vendors

in the Electric Power Industry for the 1990s as Related to Fuel Cells

(Alexandria, VA: Peter Hunt Associates, 1984), OTA contractor repOrt OTA US-84-1 1.

SzBattelle, Columbus Division, Fina/ Report on Alternative Generation Technologies (Columbus, OH: Battelle, 1983), VOIS. I and

11, pp. 13-11.
Ch. 4—New Technologies for Generating and Storing E/ectric Power ● 103

life, and reliability. In particular, investors are

likely to be sensitive to the rate at which fuel cell

performance degrades over time under various

operating conditions as well as the cost and difficulty of replacing cells when their performance

becomes unacceptable. There is uncertainty

among investors over these two points, both of

which are crucial to the fuel cell’s uItimate commercial prospects. ShouId problems be encountered in either area in early commercial prototypes, commercial deployment will be delayed.

If powerplant operation is favorable, subsequent

market growth in the latter half of the I990S could

be very rapid.

Basic Description

The typical fuel cell powerplant will consist of

three highly integrated major components: the

fuel processor, the fuel cell power section, and

the power conditioner. The fuel processor extracts hydrogen from the fuel which can be any

hydrogen-bearing fuel, though most installations

in the 1990s are expected to employ natural gas.

The hydrogen is then fed into the fuel-cell

power section, the heart of which are “stacks”

of individual fuel cells. The operation of a single

fuel cell is schematically illustrated in figure 4-

19, The cells are joined in series (the stacks),

which, in turn, are combined to form a powerplant. There are several types of fuel cells being

developed. These are categorized according to

the type of electrolyte-the medium in which the

electrochemical reaction occurs—they use. The

first-generation fuel cells use phosphoric-acid as

the electrolyte. These cells are the most developed and are likely to account for most of the

fuel cells deployed in the 199os.

Other less mature, fuel cell designs which employ alternative electrolytes promise superior performance; molten carbonate cells are the closest

to commercial application, but are not expected

to be commercially deployed until the late 1990s

at the earliest. They therefore are not likely to account for an important share of fuel cell powerplants installed in the 1990s. M w

S8Peter H u nt, AflJ/YSIS Ot Equipment Manufacturers and Vendors

In the Electrlc Power Industry for the 1990s as Related to Fuel Cells,

OP. Cit., 1984.

5gu ,s, Congress, office of Technology Assessment Workshop on

Fuel Cells, Washington, DC, June 5, 1984.

The electrical power which flows from the fuel

cell stacks is direct current (DC). With some voltage regulation, this DC power can be used if the

load is capable of operating with direct current.

Otherwise, a power conditioner is required to

transform the direct current into alternating current. This allows it to be fed into the electrical

grid and to be used by alternating-current electrical motors.

The components of the fuel cell plant are tightly

integrated to reduce energy losses through the

proper management of fuel, water, and heat (see

figure 4-20). Various parts of the plant benefit

from the byproducts of other parts of the installation. Further efficiency gains result when byproduct heat from different parts of the plant are

tapped for external use. The fullest exploitation

of the fuel cell’s heat may yield total energy efficiencies of up to 85 percent for the entire plant.

The heat can be used for domestic hot water, for

space heating, or to provide low-level process

heat for industrial uses.

Typical Fuel Cell Powerplants

for the 1990s

The expected cost and performance of typical

fuel-cell powerplants for the reference year 1995

are summarized in appendix A, table A-7. Because no complete powerplants identical to those

which might be deployed at that time exist today,

these values remain estimates.

The units deployed in the 1990s probably will

be built around two sizes of fuel cell stacks. The

larger stacks are likely to be capable of generating approximately 250 to 700 kWe (gross, DC)

each and the smaller stacks about 200 to 250

kWe (gross, DC) each. The plants built around

the small stacks will be installed mostly in large

multifamily dwellings, commercial buildings, and

in light industries; most will probably be used to

cogenerate both electricity and useful heat. The

typical system would consist of at least two complete self-contained modules (see figure 4-21 ),

each of which might produce about 200 kWe

(net, AC).

Plants using the larger fuel cell stacks most likely

will be deployed primarily by electric utilities, and

by industries which would use them in cogeneration applications. Installation capacities probably
104 ● New Electric Power Technologies: Problems and Prospects for the 1990s

Figure 4-19.—Schematic Representation of How a Fuel Cell Works

1. Hydrogen gas flows over negative

electrode (anode).

11

1

Electrons

11

Ieotrone, and o

will range from several megawatts on up. The

reference installation used in this analysis is 11

MWe (net). Many of the major components

wouId be fabricated in factories and shipped to

the site on pallets.

The lead-time of a small fuel cell powerplants

should be about 2 years. These units are relatively

small, unobtrusive, and quickly and easily erected.

Modules subsequently added at the same site

could require as little as a few months. Regulatory delays are unlikely because of relatively minor siting and environmental considerations.

Installations utilizing the larger stacks, however,

may encounter more serious regulatory problems, Unlike the approximately 480 to 600 square

feet required by an installation of two, 200 kWe

units, an 11 MWe installation would occupy

about 0.5 to 1.2 acres of land (see figure 4-22).

Because the plants frequently may be located in

the midst of populated areas, the opportunity for

regulatory conflicts with these larger plants is considerably greater. Partly offsetting these factors,

though, are the environmental advantages associated with fuel cell powerplants. Hence, a leadtime of 3 to 5 years is anticipated with the larger

units, considerably longer than the small plant’s

lead-time, but also much shorter than that of most

conventional powerplants. As with the smaller

fuel cell installations, capacity subsequently added to an already existing fuel cell plant should

require considerably shorter lead-times.
L

Mechanical systems

Water

—— ——— — -

Water

treatment

1

Powerplant

controller
106 ● New E/ectric Power Technologies: Problems and Prospects for the 1990s

Figure 40-21.— Design for a 200 kWe Fuel Cell Module

While basically similar to units which might be deployed In the 1990s, this design differs in several important details,

The operating availability of large fuel cell powerplants may range between 80 and 90 percent.

Availability is heavily dependent on the quality

of design—its simplicity, the extent to which it

has redundant components, the number of parts,

and their reliability—and on the availability of

spare parts and repair people when they are

needed.

The fuel cell can be applied to any duty cycle.

The fuel cell has excellent load following capabilities and high efficiency over a wide variety of

operating levels.

The fuel cell powerplant’s lifetime is assumed

to be approximately 20 to 30 years with periodic

overhaul of the fuel cell stacks and other components. over time, the powerplant’s efficiency

drops. The timing of overhauls will vary; schedu Ies will be a function of the performance reduction over time and of other factors such as the

cost of fuel .60 I n some cases the stacks must periodically be removed and replaced with new

ones. The old unit then is shipped back to a manufacturing plant where its catalyst (in the fuel

processing section) and perhaps other components are removed, processed, and recycled.

While the overhaul schedule and costs are uncertain, it is assumed here that all stacks are

replaced after the equivalent of 40,000 hours of

operation at full capacity.

60J. R, Lance, et al., Westinghouse Electric Corp., “Economics and

Performance of Utility Fuel Cell Power Plants, ” Acf~anced Energy

Systems– The/r Role In Our Future: Proceedings of the 19th /rrtersoclety Energy Conversion Engineering Conference, August 19-24,

/984 (San Francisco, CA: American Nuclear Society, 1984), paper

849133.
Ch. 4—New Technologies for Generating and Storing Electric Power Ž 107

co

Figure 4-22.—Typical Arrangement of 11 MWe Fuel Cell Powerplant

Auxiliary

power system \

Power

nditioner \ 1

Liquid

fuel system

\

Natural

gas system

supply

—

/-.

Efficienciesbl for large fuel cell plants are expected to be between 40 and 44 percent. Small

plants may have efficiencies of approximately 36

to 40 percent. The estimated efficiencies are those

which might characterize a plant over its lifetime;

efficiencies of new stacks could be higher while

those of older stacks might be below that level.

The installed capital costs of fuel cell power

plants are expected to range from $700 to $3,000/

kWe for large units to $950 to $3,000/kWe for

small plants; expected values for 1995 are $1 ,430/

kWe and $2,240/kWe respectively. The low numbers can be expected where units are commercially produced in large numbers; the high numbers are representative of prototype units and

include nonrecurring costs. By far the largest expense is the fuel-cell power section itself; it is expected to account for about 40 percent of the

‘]’ Based on higher heatln~-~ alue

costs of a mature 11 MWe plant .62 The largest

decrease in capital costs over the next decade

will come from increases in the levels of fuel-cell

production. However, technical improvements

in the fuel-cell plant itself may substantially reduce costs as well. Already, over the past several years, design changes have reduced costs by

an appreciable amount.

Operating and maintenance costs may range

between 4.3 and 13.9 mills/kWh. The biggest element in O&M costs is the cost of periodically

replacing cells stacks. For specific applications,

the actual O&M costs will depend on the overhaul period for the cell stacks and the material

and labor costs for each overhau 1.

b~u nlted TeCh rlol~~les Power Systems, sfu~y OfJ ~~05@Or/C ACI~

Fuel Cells Using Coal-Deri~ed Fuels (South Windsor, CT: United

Technologies Power Systems, Apr. 27, 1981 ), prepared for Tennessee Valley Authority, contract No. TV-52900A, FCR-2948.
108 ● New Electric Power Technologies: Problems and Prospects for the 1990s

Fuel costs are expected to be approximately

27 to 33 mills/kWh, accounting for the major portion of electricity costs from fuel cells. Fuel costs

also constitute the fuel cell’s greatest advantage

over some of its competitors such as the gas turbine, due to the fuel cell’s high efficiency which

yields substantially lower per kilowatt-hour fuel

costs. Major variations in fuel costs per kilowatthour will result primarily from fluctuations in fuel

prices. Fuel cell efficiency variations, due to technical improvements or maintenance practices

(especially stack reloading schedules), also would

be reflected in different fuel costs. In the longer

term, post-2000, it is expected that natural gas

will have to be replaced with more abundant

fuels. Primary candidates are synthetic fuels–

especially methanol—from coal and biomass.

Stacks are of central importance in determining capital, O&M, and fuel costs. The development and extended demonstration of cheap (per

kWe) and reliable stacks which can operate at

high efficiencies for extended periods are critical to the success of the technology. Technological improvements which could be especially important in this regard are the development of

inexpensive, corrosion-resistant cell structural

materials and less expensive and more effective

catalysts to operate at higher pressures and temperatures, and improved automated fabrication

and handling processes for large area cells. Also

important is the development of cheap, reliable

and efficient small-scale reformers (fuel processing units) and the improvement of various other

standard components.

Combustion Technologies

Integrated Gasification/Combined-Cycle

Powerplants

introduction.-A coal gasification/combinedcycle powerplant centers around two elements.

First is a gasification pIant which converts a fuel

into a combustible gas; other equipment purifies

the gas, Second is a combined-cycle powerplant

in which the gas fuels a combustion turbine

whose hot exhaust gases are used to generate

steam which drives a steam turbine. While the

gasification system can be quite separate and distinct from the combined-cycle system, they can

be integrated so that some of the heat discharged

in the gasification sequence is exploited in the

combined-cycle system, and a portion of the heat

discharged by the combined-cycle unit may be

routed back for use in the gasification plant (see

figure 4-23). This section focuses on such integrated units, commonly referred to as IGCCS.

The primary attractions of the IGCC are its fuel

efficiency and its low sulfur dioxide, carbon

monoxide, nitrogen oxide, and particulate emissions. The high efficiency allows for fuel savings

and hence reduced operating costs. The potential for very low emissions makes the technology

particularly attractive for using coal to generate

electric power. Another advantage allowed by

the IGCC is “phased construction. ” Some parts

of the plant may be installed and operated before the rest of the plant is completed;63 this can

be financially advantageous and is considered a

major selling point for the technology. The IGCC

also may be very reliable. In addition, the technology requires less land and water than a conventional scrubber-equipped, pulverized coal

boiler powerplant. Furthermore, its solid wastes

are less voluminous and less difficuIt to handle

than those of its scrubber-equipped competitor

and of the atmospheric fluidized-bed combustor

(AFBC). Current estimates are that solid wastes

from an IGCC will be 40 percent of a pulverized

coal boiler and 25 percent of an AFBC of comparable size.

The evidence suggests that the IGCC offers a

favorable combination of cost and performance

when compared to its competitors (see also chapter 7). Nevertheless, a combination of two factors—lead-times and risk—may mitigate against

its extensive deployment within the 1990s. Because of its modular nature and positive environmental features, potentially the IGCC has leadtimes of no more than 5 to 6 years. It is likely,

however, that the first plants, at least, will require

longer times–up to 10 years–because of regulatory delays, construction problems and operational difficulties associated with any new,

complex technology. It may take a number of

GJFOr example, the gas-turbine/generator sets may be installed

before the gaslfiers and operated off of natural gas. When the gasl -

fiers are completed, the synthetic gas then may be used instead.
Coal

Nitrogen

to atmosphere

I

Process I

. Flash I i

Claus Incinerated

steam Effluent gas sulfur tall gas

treatment - recovery an

incineration 1

I

4

Saturated steam

Po-we/ Generation (Argonne, IL Argonne National Laboratory 1983)

I

Plant

auxiliary

– J

power
110 . New Electric Power Technologies: Problems and Prospects for the 1990s

commercial plants before the short lead-time potential of the IGCC is met, unless strong steps are

taken to work closely with regulators and to assure quality construction for these initial plants.

Such steps may be facilitated if the early plants

are in the 200 to 300 MWe range rather than the

current design target of 500 MWe. Should the

longer lead-times be the case, projects must be

initiated no later than the end of 1991 and perhaps as early as the end of 1989 if they are to

be completed within the 1990s.

In addition to these possible longer lead-times,

limited experience with IGCC demonstration

plants may also constrain extensive deployment

in the 1990s. Although there has been extensive

experience with the gasification phase, currently,

there is only one IGCC plant in operation, the

100 MWe Cool Water plant in California (see figure 4-24). In addition, there is another demonstration plant using a different gasifier, under construction in a large petrochemical plant (discussed

more in chapter 9). The Cool Water plant has

been very successful in meeting its construction

scheduled and budget, and in its early operation.

As a result it has given confidence to utilities in

their consideration of whether to commit to an

b~An interesting discussion of the plannlng and construction of

an IGCC can be iound in: Cool Water Coal Gasification Program

& Bechtel Power Corp., Cool Water Coal Gasification Program–

Second ,4nnua/ Progress Report, interim report (Palo Alto, CA: Electric Power Research Institute, October 1983), EPRI AP-3232.

IGCC. Despite this success, however, more operating experience is likely to be required before

there will be major commitment to the IGCC by

a very cautious electric utility industry. The Electric Power Research Institute, a major sponsor of

the IGCC Cool Water project, anticipates three

to four commitments by the end of 1986. If these

projects go forward and the shorter lead-time potential of the IGCC is proven, then significant

deployment in the mid to late 1990s is quite

possible.

Description of a Typical IGCC in the 1990s.–

Plausible cost and performance features of a representative IGCC are described in appendix A,

table A-6. The reference year considered in the

report is 1990, at which time two plants, generating altogether approximately 200 MWe probably will be operating in the United States. The

reference plant capacity is 500 MWe, consisting

perhaps of five gasifiers,65 though installations as

small as 250 MWe might be preferred. While capable of being built with capacities even smaller

than 250 MWe, such smaller installations would

be more costly per unit of capacity.66 The plant

would consist of three types of equipment: the

gas production, cooling and purification facilities;

the combined-cycle system (including gas turbines and steam turbines); and the balance of the

plant. Included in the constituents of the latter

are fuel receiving and preparation facilities, water

treatment systems, ash and process-waste disposal equipment, and in most cases an oxygen

plant.

Gszaininger Engi r-reefing CO., capacity factors and costs of Electricity for Conventional Coal and Gasification-Combined Cycle

Power Plants (Palo Alto, CA: Electric Power Research Institute, 1984),

EPRI AP-3551 .

66According t. one source (Electric bA@’ Research Institute, Economic Assessment of the Impact of Plant Size on Coal Gasification—

Combined-Cyc/e P/ants (Palo Alto, CA: Electrlc Power Research institute, 1983), AP-3084), the Ievellzed cost of electricity for a variety of IGCCS using Texaco gasifiers increased as plant size decreased. The economies of scale were relatively small among plants

of capacities greater than 250 MWe. But as plant size diminishes

below 250 MWe, Ievellzed costs increase very significantly. Selection of a 500 MWe module also was favored by participants in a

June 1984 OTA-sponsored workshop on IGCCS, though it was suggested that installations as small as 250 MWe might seriously be

considered.
Ch. 4—New Technologies for Generating and Storing Electric Power ● 111

The IGCC can be built in phases. The design

permits the operation of portions of the pIant before other segments are completed. The gas turbines could be installed first and operated with

natural gas. The steam turbines then could be

added, allowing the production of still more electric power. Finally, the gas facilities could be

added to complete the plant and to allow its operation based on synthetic gas. Hence, some electrical power could be produced before the entire plant is completed.

The typical plant would require a rather large

area of land and considerable quantities of water

during its lifetime of approximately 30 years. An

estimated 300 to 600 acres would be needed for

the facilities, and for disposal of solid wastes. And

3 to 5 million gallons of water, on average, would

be required to run the plant daily. These quantities are large, but as noted above, they are smaller

than those which characterize conventional pulverized coal plants equipped with scrubbers.

The operating availability of the reference IGCC

plant is 85 percent. There is uncertainty associated with availability estimates, as these plants

would be the first commercial units and could

experience problems which would result in lower

availability rates. Of particuIar concern is the

reliability of the combined-cycle system; combined-cycle system design as well as operating

and maintenance practices will largely determine

combined-cycle reliability.

The IGCC facility commonly would be used to

provide base load power at efficiencies ranging

from 3S to 40 percent. This corresponds to a heat

rate of between 8,533 and 9,751 Btu/kWe-hour.67

It is worth noting that the Cool Water demonstration plant, which had a design heat rate of

11,400 Btu/kWh, has consistently met that target in operation to date. While the gasifier design certainly has an important effect on efficiency, the most important factor in efficiency

within the anticipated range probably would be

FIT I t I ~ I m ~)() rtcl nt tO note that I Gcc heat rates are part IC u IJ rlv wn -

~ltl~ e to J mblent temperatures, Heat rates go down it Ith a mblent

temperatu rej. See, (or example, table 3-1 In: Zaln Inger Engl neerInfi Co , Cap,]t It) F<]( tor~ .;nd Ccxti oi E/ectrKlt\ for Con\ entlon,]/

Coa/ ,]nd G,]sltlc,]rlon-C~~n?blned C\c/e Po\~ w P/.]nt\, op [ it,, 1984,

It IS a~surned here that amhlent temperatu rej are held constant

throughout the year at 88 F,

the gas turbines. To reach the high efficiencies

projected for the IGCC will require high-temperature, advanced combustion turbines. The

projected efficiency range is somewhat higher

than the 35 to 36 percent efficiency expected for

conventional plants with scrub bers. 68

Conventional turbines would yield efficiencies

at the low end of the efficiency range, while advanced turbines might yield higher efficiencies. 69

The choice of turbine type could significantly affect O&M costs in addition to efficiency. ’o For example, an advanced turbine design, while promising higher efficiencies couId also entaiI greater

technical problems and therefore higher O&M

costs. The choice of turbine also would affect capital costs. Higher efficiency turbines wouId resuIt

in a higher electrical output for a given gasitier

and feed system; and the steam plant would be

relatively smaller. Both changes would reduce

capital costs per kilowatt- hour.71

Capital costs probably will range from $1,200

to $1,350/kWe (net). For units in the 250 MWe

range, costs are expected to be somewhat higher,

about $1,600/kWe, By far the largest expense

would be the gas production and purification facilities. These might account for approximately

40 percent of total costs. The cost would vary

especially with gasifier design; there are indications that substantial capital cost differences may

exist among leading gasifier designs,72 though the

magnitude of these differences not clearly established. Costs also will vary significantly according to the degree to which redundancy is designed into the system. Another 40 percent of the

cost would include buildings, coal receiving and

preparation equipment, an oxygen plant, waste

handling equipment, water equipment, and the

68B. M, Banda, et al,, ‘‘Comparlw)n of I ntegrat~d Coat Ga\ltl~.v

tlon Combined Cycle Power Plants L\’ith Current and ,f+di an( ed

Gas Turbines, ” Aci~,?nceci Energy SjS$ten?\- Their Rolt’ In Our F(Iture’ Prm eedlng$ of the 19th Interwx let~ [nerg} Con~ er~lon Eng/-

rwering Conrerem e, ,Auguht 19-24, 1 %94 (San Franc IV o, CA: 4merIcan Nuclear %clety, 1984), paper 849507.

b91 bld

‘°For a dlscuislon ot relei ~nt turbine de~ elopmenri, w’e Erl( jett~

“Tokyo Congress Highlights Ettlclenc\ and N[)I Control, ” Ga5 Turbine \l’or/d, J,~nu,]r\-Ft>bru,ir) 1 WA, pp. 26-N).

“‘Genera I E Iw t rl[ Co, , Re~ Ie\t ,I17d Corrtment,]r\ on Design or

Ad\ arrceci Fo~\I/ Fue/ S}\tem< ( Falrtleld CT: General Elec trlc Co.,

1982).

‘IOTA stati telephone c on~ erwtlon it Ith Bert Lou L\, El(>ctric

Pou er Research I n~tltute, June 6 1984
112 • New Electric Power Technologies: Problems and Prospects for the 1990s

combined-cycle system .73 Finally there are access

roads, site preparation, and various civil engineering tasks; together these might represent roughly

20 percent of capital costs.

Operating and maintenance costs could range

from 6 to 12 mills/kWh, a figure roughly equivalent to the costs characteristic of a conventional

pulverized coal plant. The greatest source of uncertainty in the estimate concerns the performance of the gasifiers, of the syngas coolers (if they

are used) and of the gas turbines.

Fuel costs for the reference plant are projected

to range from 15 to 17 mills/kWh based on 1990

coal costs of $1 .78/MMBtu (see “Definitions” in

appendix A for discussion of fuel costs). It is here

where the possible cost advantage of the IGCC

over the conventional scrubber equipped plant

is greatest. Because of its higher efficiency, the

IGCC’s fuel costs would be less than those of its

conventional counterparts. As discussed above,

an important determinant of overall efficiency is

the gas turbine’s efficiency. Advanced turbines

which are expected to be available by the early

199os would be much more efficient than present

turbines. Their use could allow fuel costs to fall

to the low end of the estimated range. Since fuel

costs account for a large portion of the cost of

generating electricity from the IGCC, the anticipated improvement in turbine efficiency will affect the competitive position IGCC significantly .74

Atmospheric Fluidized=Bed Combustion

Introduction.–The AFBC is a combustion

technology which will provide an economic alternative to conventional pulverized coal plants in

the 1990s. Its relatively low volumes of sulfur dioxide and nitrogen oxide emissions, great fuel

flexibility, small commercially available size ( <

100 MWe), easily handled solid wastes, responsiveness to demand changes, and other features

TIH G Hernphill and M, B, jennings (Raymond Kaiser Engineers,

Inc.), “Offsites, Utilitles, and General Facilities for Coal Conversion Plants, o‘ Advanced Energy Systems— Their Role in Our Future:

Proceedings of the 19th Intersociety Energy Conversion Engineering conference, August 19-24, 1984 (San Francisco, CA: American

Nuclear Society, 1984), paper 849195.

7qB. M. Bancia, et al., “Comparison of Integrated Coal Gasification Combined Cycle Power Plants With Current and Advanced

Gas Turbines, ” op. cit., 1984.

offer advantages which may allow it to compete

successfully with conventional plants, particularly

in areas where high sulfur coals are used. Investment outside the utility industry in AFBC cogeneration units already is growing rapidly, Greater

investment by utilities is likely in the 1990s,

though various factors may keep the number of

large utility-owned AFBCs operating by the end

of the century below that which cost alone would

set (see chapter 9).

There are two basic types of fluid ized-bed combustors: the atmospheric fluid ized-bed combustor (AFBC) and the pressurized fluidized-bed

combustor (PFBC). The PFBC operates at high

pressures, and therefore can be much more compact than the AFBC. The PFBC also may produce

more electricity for a given amount of fuel. Despite these potential advantages, the PFBC has

more serious technical obstacles to overcome

and is less well developed than the AFBC. It has

not yet been successfuIly demonstrated on a

commercial scale, nor are any commercial-scale

demonstrations now under construction in the

United States. It is unlikely that more than a few

commercial units could be completed and operating before the end of the century, though the

PFBCs longer term potential is quite promising.

The AFBC, the focus of this analysis, operates

at atmospheric pressures. Small-scale AFBCs already are used commercially around the world

for process heat, space heat, and in various other

industrial applications; and are producing electrical power abroad as well as in very small

amounts in the United States. Three types of

AFBC installations may be important over the

next 15 years: large electric-only plants (100 to

200 MWe), cogeneration installations, and nonelectric systems. The electric-only units are likely

to be deployed by utilities, whereas the cogeneration and nonelectric units probably would be

built and operated by others.

The cogeneration unit is an installation operated to provide both electricity and usable thermal energy, while the nonelectric systems are

used to supply usable heat only. Electric-only

AFBCs may be new “grass-roots” plants built

from the ground up; or they may be “retrofits”

to existing plants which have been modified to
Ch. 4—New Technologies for Generating and Storing Electric Power • 113

77A Cyc lone ,s a mechan Ica I device wh IC h sepa rateS Particles from

gases by using centrifugal force.

78A ~y~tem of fabric fl[ters (bags) for dust removal from stack gases.
114 ● New Electric Power Technologies: Problems and Prospects for the 1990s

Fluidized-bed combustors are commonly categorized by the degree to which solids are entrained in the gas-flow through the bed and to

which solids are recycled to the bed after passing through the cyclone. The primary types of

fluidized-beds are illustrated in figure 4-25;

among these, bubbling beds and the circulating

beds are the most important.79

The bubb/ing bed AFBC is characterized by low

gas velocities through the bed. The result is a bed

from which only the smaller particles are entrained with the gas; after being entrained, the

solids on the average are recycled through the

bed less than once. Conversely, the gas flow velocities through the circulating bed are rapid. The

bed itself becomes less distinct with greater en79 These I n turn can be further subdivided. Among the bubbling

beds are the conventional bubbling bed, multibed and in-bed circulating models. Circulating systems include conventional and multisolids bed (or hybrid} systems. (Bruce St. John, NUS Corp., ArM/y -

sis and Comparison ot FiL’e Generic FBC Systems, paper presented

at Fluldized Bed Combustion Conference, sponsored by the Government Institutes, May 1984. )
Ch. 4—New Technologies for Generating and Storing Electric Power • 115

trainment levels, as larger portions of the fuel and

sorbent repeatedly are cycled through the combuster. The fuel and limestone are thoroughly

mixed as combustion of the fuel takes place.

Each of the two types of AFBC possesses certain operating characteristics and peculiarities. An

important shortcoming shared by both technologies is the fact that neither have been built to

produce electric power on a scale–100 to 200

MWe—attractive to utilities. And both face serious technical challenges in moving from the very

small nonelectric industrial boilers which have

typified AFBC applications so far to these larger

sizes.

The bubbling bed has an important advantage

in that it is the older of the two types and there

is greater operating experience in the United

States (in small, nonelectric, industrial applications). The bubbling-bed combustor can more

readily be retrofitted to some preexisting conventional boilers, But the design also has its drawbacks. perhaps the most serious are the fuel-feed

problems encountered as the unit is scaled-up.

it is difficult to design a reliable feed mechanism

that adequately distributes fuel to the bed; the

problem becomes progressively more difficult as

the bed is enlarged. An elaborate feed design is

required; and the size and moisture content of

the fuel must be carefully controlled.

By the end of this decade several large bubbling-bed AFBCS will be operating in the United

States. One is a grass-roots, 160 MWe demonstration plant in Paducah, Kentucky (see figure

4-26). Two others are retrofit units. Among the

units, two different feed systems will be used.

Should serious problems be encountered in the

feed systems of the units, the deployment of the

bubbling beds with capacities between 100 and

200 MWe in the 199os may be seriously delayed.

Favorable operation would encourage commercial orders of large units. Other problems associated with some bubbling bed designs, which

may impede commercial deployment, are erosion and corrosion of materials which are in contact with the bed itself or particulate laden gases.

These difficulties, should they persist, could result in unacceptably high O&M costs.

With the circulating bed, by virtue of its greater

gas’ velocities and higher levels of particulate recycling, the fuel-feed problem may be far less of

a problem, at least with smaller units. A simpler

feed mechanism can be used, and larger variations in fuel size and moisture are tolerated. Efficient combustion and sorbent utilization is more

readily achieved. Nitrogen oxide and carbon

monoxide emissions also tend to be lower.

Being a newer “second-generation’ technology, there is less experience operating even small

circulating-bed AFBCs. But this disadvantage is

rapidly disappearing. Many vendors now are

offering circu Iating beds; and almost all the major cogeneration units and many of the nonelectric AFBC projects now being built employ circulating beds.

While it is not clear whether plants using bubbling beds, circulating beds, or some hybrid of

the two will be favored for large grass-root plants

in the 1990s, the recent commercial trends indicates that the circulating beds are becoming the

technology of preference for small cogeneration

uses and a sizable share of nonelectric applications. Favorable experience with these units, as

well as the single large retrofit unit using the circulating bed, couId decisively favor the competitive position of large circulating bed AFBCs in the

199os. As with the large bubbling bed demonstration units, however, difficulties with the demonstration retrofit unit could seriously retard the

commercial deployment of large units.

Typical AFBC Plant for the 1990s.–A large

AFBC plant typical of the kind which might might

be deployed for electricity production in the

1990s is described in appendix A, table A-5. The

table and the following discussion focus on allelectric, grass-roots plants. By the early 1990s,

U.S. utilities will have only one such plant on

which to base evaluations of the technology. This

is the 160 MWe demonstration unit which currently is being constructed at TVA’s Shawnee

Steam Plant in Kentucky; startup is scheduled for

1989. Investors, however, also by the early 1990s

will benefit from the technical progress and information resulting from two large demonstration

retrofit units, one of 100 MWe and the other of
116 Ž New Electric Power Technologies: Problems and Prospects for the 1990s

Figure 4-26.– 160 MW AFBC Demonstration Plant in Paducah, KY

Authority

125 MWe, which also will have operated for several year-s by the early 1990s. Also important will

be experience gained from the operation of a fully

com mercia1, 125 MWe cogeneration u nit—also

a~ retrotit—being installed by a private firm in

Florida. And many hundreds of megawatts of

\mall AFBs will have been installed by 1990.

The reference AFBC plant considered in the

analysis has a generating capacity of approximately 150 MWe (net). The gross electrical power

production of the plant actually would exceed

net capacity, because power is required to oper-

.~te the equipment which circulates the solids and

forces air into the bed. Any commercial units considered in the early 1990s are not likely to exceed by very much the size of the demonstration units; AFBCs are subject to scale-up problems

which probably will inhibit during the 1990s deployment of any commercial units much larger

than the demonstration plants.

Many features of the AFBC installations deployed in the 1990s, regardless of type, are likely

to be much the same. They will require access

to coal and limestone supplies; this usually means

railroad access. A rather sizable piece of land will

be required, not only for the AFBC itself but for

coal and limestone handling and processing facilities, storage areas for the limestone and coal,

disposal areas for the solid waste generated by

the plant, and ponds of various sorts. Disposal

of spent limestone may be one of the most serious problems for the AFBC. Current estimates are

that about 1,200 tons per MWe year need to be

disposed of for 3.5 percent sulfur, Illinois coal.
Ch. 4—New Technologies for Generating and Storing Electric Power ● 117

For a 150 MWe plant, about 90 to 218 acres

could be required; the exact amount depends on

several conditions. Access to water also will be

required; the 150 MWe reference plant is expected to require about 1.5 million gallons each

day.

Like any large powerplant, the AFBC is expected to require a considerable amount of time

to deploy. An AFBC in the 100 to 200 MWe range

potentially has a lead-time of no more than 5

years because of its smaller size and environmental benefits. As with the IGCC, however,

lead-times of the first plants are likely to be

greater, and could be as long as 10 years. This

includes up to 5 years for design, preconstruction, and licensing activities; and 2 to 5 years for

construction. Favorable regulatory treatment, and

rapid and quality construction could result in

lead-times close to the potential.

If in fact large, grass-root AFBC plants take up

to 10 years to build from initial commitment,

orders for them must be made by 1990 for the

AFBCs to contribute appreciably to generating capacity before the close of the century. Given the

fact that the three large demonstration plants and

numerous small cogeneration units will be operating by then, there is a possibility that considerable numbers of large plants indeed will be i nitiated by that time.

The operating availability of an AFBC powerplant may be around 85 to 87 percent. But considerable uncertainty surrounds this figure. Difficulties with the fuel feed system in bubbling-bed

AFBCs could severely reduce operating availability. Or erosion or corrosion associated with both

bubbling-bed and circulating-bed AFBCS could

have similar effects.

AFBCs are expected to be used primarily as

base load plants, though their demand-following

capabilities will allow their use in intermediate

applications. An AFBC plant is expected to last

for approximately 30 years, and to operate with

an efficiency of approximately 35 percent—somewhat higher than a conventional pu Iverizecl coal

plant equipped with scrubbers.

The capital cost of a large AFBC probably will

be pegged at a level roughly comparable to that

of its main competitors, the conventional scrubberequipped plants and the IGCC. The estimate in

this analysis is $1,260 to $1,580/kWe. Fuel costs

are expected to be approximately 17 mills/kWh

assuming coal costs of $1.78/MMBtu. O&M costs

are expected to fall between 7 and 8 mills/kWh,

but high uncertainty is associated with this estimate. Should technical problems be experienced

with the fuel feed system, or shouId serious erosion or corrosion problems arise, power production could suffer and expensive repairs and modifications could be required. Consequently, O&M

costs could escalate.

The major opportunities for research which

cou Id yield technical improvements in the AFBC

or reduce uncertainty about performance lie i n

the three large demonstration projects which currently are underway. These projects offer the

chance to experiment with basically different designs and to compare technologies. Of particular importance will be research relating to the fuel

feed systems and to designs and materials which

can reduce erosion and corrosion of system components.

ENERGY STORAGE TECHNOLOGIES

Introduction

ing periods when the marginal cost of electricity

There are several tasks that electric energy stor- is high. I n addition, storage equipment can be

age equipment, employed by utilities, can per- used as spinning reserve, the backup for generform. The most common is load-/eve/ing, i n ating systems which fai1, or as system regulation,

which inexpensive base load electricity is stored the moment-by-moment balancing of the utility’s

during periods of low demand and released dur- generation and load.
118 ● New Electric Power Technologies: Problems and Prospects for the 1990s

Energy storage technologies also may be used

by utilities’ customers in either remote or gridconnected applications. The latter typically involve the use of storage devices by utility customers wishing to avoid the high price of electricity

during peak periods. Cheaper power is purchased during base periods and stored for use

during higher cost, peak periods.

Modular storage technologies, such as batteries

and flywheels, can be deployed in either a utilityowned or in a nonutility-owned dispersed fashion. However, economic considerations currently

seem to favor large utility- or third-party-owned

installations. While storage technologies may at

some point be installed in conjunction with large

deployments of intermittent generating plants,

such as photovoltaics or wind, storage facilities

in the 1990s will most likely be used to store

the inexpensive output of large, conventional

plants .80

There are two storage technologies which

could, under some circumstances, see significant

deployment in the 199os: advanced batteries and

compressed air energy storage (CAES). Batteries

are a well-established technology, familiar mostly

in mobile applications, but only recently have advances in chemistry and materials made it possible to construct large-scale systems with sufficiently long lifetimes and low capital costs to

attract utility interest.

A CAES plant is a central station storage technology i n which off-peak power is used to pressu rize an underground storage cavern with air,

which is later released to drive a gas turbine. The

technology has been demonstrated in Europe,

but not in the United States.

Compared to batteries, CAES plants have several advantages. They are in a more advanced

stage of technical development and are likely to

be less expensive than batteries on a dollar per

kilowatt-hour basis when long discharge times

(roughly 5 hours or more) are required. However,

compared to batteries, CAES plants are less modular, and thus carry more financial risk per

project.

~{~As Cu rr~nt IY IS the c ~rnrn~rl practice with pu roped hyciroelectrlc tacl Iltles; there may be some exceptions, howei er, in certain

isolated areas with large potential tor renewable, such as Hawal i,

Among the storage technologies not likely to

make a significant additional contribution in the

1990s are pumped hydro, flywheels, and superconducting magnet energy storage. While there

are numerous pumped hydro plants in existence

in the United States, it has become difficult to site

these plants if they involve a large, above-ground

reservoir. If all the water is stored underground,

the plants are economic only in very large units. Bl

Flywheels, while possibly competitive in small installations, e.g., cars or homes, cannot compete

economically with batteries or CAES in larger installations. B2 Finally, superconducting magnetic

energy storage is not likely to be commercial before the next century.

Compressed Air Energy Storage

Introduction

A CAES plant uses a modified gas turbine cycle in which off-peak electricity—stored in the

form of compressed air–substitutes for roughly

two-thirds of the natural gas or oil fuel necessary

to run an equivalent conventional plant (see figure 4-27). in a conventional plant, the turbine

must power its own compressor to supply the

compressed air necessary for operation. This

makes only a third of the turbine’s power available to produce electricity. I n a CAES plant, however, off-peak electricity is used to drive the compressor (through the generator running in reverse

as a motor) which charges an underground storage cavern with compressed air. Later the air is

released and passes through a burner where a

hydrocarbon fuel such as natural gas is burned.Bs

The resulting hot gases then pass through a turbine which, freed from its compressor, can drive

the electric generator with up to three times its

normal fuel efficiency. The gases discharged from

8 I peter E, ‘jc ha u b, Potomac E Iect ric Power CO

.

, comments o n

OTA electric power technologies November 1984 draft report, Jan.

29, 1985.

8~ja me5 H. Sw15her and Robert R. Reeves, ‘‘Energy Storage Technology, ’’Energy Systems Handbook (New York: John Wiley & Sons,

February 1983).

B3 I n ,Icjd it ion to the CA ES tech no logy descrl bed here, there J re

severa 1, more advanced CAES systems which reduce or ellm I nate

the need for natural gas or hydrocarbon fuel. These systems would

be more expensive than the more conventional CAES systems, .]nd

Whi Ie none hake yet been demonstrated, they c ou Id k)e developed

for the 1990s with sufficient utility Interest.
Ch. 4—New Technologies for Generating and Storing Electric Power ● 119

Figure 4-27.– First Generation CAES Plant

Exhaust

Afte r

cooler I

(Cools alr

before It

enters cavern

~—.

t

I I Turbines I I

L

I

H

— I

air

the turbine pass through a “recuperator” where

they discharge some of their heat to the incoming air from the cavern; this, too, increases the

overall efficiency of the plant.

Three types of caverns may be used to store

the air: salt reservoirs, hard rock reservoirs, or

aquifers (see figure 4-28). Each has its advantages

and disadvantages. About three-fourths of the

United States rests on geology more or less suitable for such reservoirs (see figure 7- I 2 in chapter 7). The salt domes are concentrated mostly

in Louisiana and eastern Texas. Salt caverns are

“solution-mined” by pumping water into the deposit and having it “dissolve” a cavern. The resuIting reservoir is virtually air-tight. These salt

caverns are pressurized to up to 80 atmospheres,

have a depth of 200 to 1,000 meters, and a volume of 1,000 cubic meters/MWe.

Rock caverns are located throughout the

United States. They must be excavated with underground mining equipment. A typical CAES

plant using a rock cavern would be coupled to

38-743 0 - 85 - 5
120 ● New Electric Power Technologies: Problems and Prospects for the 1990s

Figure 4-28.—Geological Formations for CAES Caverns

Wells

Impervious

cap rock Air shaft

Solutlonmined

cavity I

Salt dome

Compensation

Salt caverns are mined by a technique

called solution-mining. A narrow well is

drilled into a salt dome and fresh water is

continuously pumped in to dissolve the

salt while the resultant brine is pumped

out. The process is continued until the

desired storage volume is reached, The

Hard rock caverns are mined with standard

excavation techniques. A compensation

reservoir on the surface maintains a constant pressure in the cavern as the compressed air is injected and withdrawn. This

minimizes the volume of rock it is necessary

to excavate.

necessary volume is larger than that needed in a hard rock or aquifer system

because without water present, the

pressure of the compressed alr drops as it

is withdrawn from the cavern,

SOURCE “Eighty Atmospheres In Reserve” .E/W Journa/, April 1979

an above-ground compensating reservoir which

would maintain a constant pressure in the cavern as it discharges. The maintenance of constant

pressure offers several important operational advantages. In addition to maintaining the desired

pressure, the reservoir also allows for a much

smaller cavern than is the case with salt reservoirs.

Thus, only about 600 cubic meters/MWe are

needed underground, though a pool of about 700

cubic meters/MWe of water is required on the

surface. 84

M u~e of ,1 c Onl pen 5at I ng reservoir I 5 less 5u Ita hle for sa It re5ervoi r~ because the salt dissolves i n the water. This can on Iy be prevented by the u5e ot’ water saturated Wtth salt, an approa( h whlc h

cou Id resu It i n major en~ Iron mental ~]roblems,
Ch. 4—New Technologies for Generating and Storjng Electrjc Power . 121

The aquifer reservoirs are naturally occurring

geological formations found in much of the Midwest, the Four Corners region, eastern Pennsylvania and New York. An advantage of this kind

of reservoir is that it does not require any excavation. It consists of a porous, permeable rock

with a dome-shaped, nonporous, impermeable

cap rock overlying it. Compressed air is pumped

into the reservoir, forcing the water downward

from the top of the dome. Later, as air is drawn

from the reservoir, the water returns to its original place beneath the dome. An important advantage of this kind of reservoir lies in the fact that

the volume of the reservoir is quite flexible, allowing for a variety of plant capacities and operating schedules.

With the exception of the recuperator, the

technologies required for CAES plants—the turbomachinery and the reservoir-related technologies such as mining equipment—are well-established technologies. The turbomachinery is only

a slight modification of currently used equipment

and there are several manufacturers, American

and foreign, that offer CAES machinery with fuII

commercial guarantees, While there are some

questions as to the dynamic properties of the air

as it enters and leaves a cavern, there is little

doubt that the technology exists to build and

maintain underground storage facilities. These

caverns have been used for years to store natural gas and other hydrocarbons, and the same

firms that supply the oil and gas industry have

offered to provide utilities with CAES caverns that

can be warranted and insured. 85

Despite the relative maturity most of the components which make up the CAES plant, there

has been no experience in the United States with

CAES itself–though a CAES plant using a salt cavern has been in operation since 1978 at Huntorf,

West Germany (see figure 4-29) and has performed well. This lack of domestic experience

with the technology constitutes the largest hurdle facing CAES. There is a general reluctance

among utilities in this country to be the first to

make a commitment to build a plant. While several utilities have made preliminary planning

— .

‘

r

’ Perw~n<]l c (JrrtJ\\)fjn(j(’n[ c het~~ ~~[~n Arnold FIC k(>tt f EltI[ t rl(

Pow t>r R(+e,]rc h Initltut[’) ,lnd OTA \t,ltt, July 2, 1984

Figure 4-29.—The Huntorf Compressed Air Energy

Storage Plant in West Germany

[n the foreground is the wellhead, where compressed air IS Injected

and released The rest of the plant is in the background

SOURCE BBC Brown Boven, Inc

studies, the Soyland Electric Cooperative in 11-

Iinois is the only American utility that has ordered

a plant. This plant, however, was for various reasons canceled and no project has been initiated

since then.

Typical CAES Plant for the 1990s

CAES plants in the 1990s are likely to be available in two modular unit sizes, 220 MWe, commonly called maxi-CAES, and 50 MWe, miniCAES. These sizes are determined by the sizes

of existing models of turbomachinery—the turbines, compressors, generator/motor, and a gearbox which connects them.

A CAES plant must be sited in an area with access to water and fuel. The turbomachinery requires about 2,000 ga[lons/MWe of water per

day, and a plant with a rock cavern needs additional water for the compensation reservoir. Both

mini- and maxi-CAES plants burn about 4,000

Btu/kWh of fuel and emit the standard combustion byproducts, such as nitrogen oxide, but at

only a third of the level of a similar size conventional gas turbine. CAES plants also have noise

levels similar to those of more conventional

plants. There are several waste disposal problems

involved with building the caverns. If a rock cavern is used, it is necessary to dispose of a large
122 ● New Electric Power Technologies: Problems and Prospects for the 1990s

volume of waste rock,8b and when a salt cavern

is used, the brine pumped out of the cavern must

be disposed of. Land requirements would range

from around 15 acres for a maxi-CAES plant to

3 acres for a mini-CAES plant.

The lead-times expected for CAES plants will

probably range from 4 to 8 years. The large plants

would occupy the higher end of the range, while

the smaller units would fall at the lower end. The

primary source of uncertainty in lead-time estimates concerns licensing and permitting, which

is expected to take 2 to 4 years. Regulatory hurdles will vary depending on the type of reservoir

used. Among the regulatory impediments are

those relating to the disposal of the hard rock or

brine from the mining operation, and relating to

water usage and impacts. Also problematic may

be the requirements of the Powerplant and industrial Fuel Use Act of 1978. Even though a CAES

plant is an oil and gas saving device, the fact that

it uses these fuels means a utility must receive

an exemption from the act to operate one. A

precedent was established when such an exemption was granted to the Soyland Electric Cooperative, but under the current regulations, exemptions would be required for every CAES plant .87

The properties of the two sizes are similar (see

table A-8, appendix A); the mini-CAES turbomachinery costs somewhat less—$392/kWe vs.

$51 5/kWe for the maxi-CAES. The storage caverns can be formed out of three types of geological formations: aquifers, salt deposits, and hard

rock. In general, aquifers are the least expensive,

followed closely by salt. Rock caverns, which

must be excavated, are by far the most expensive. on a total dollars per kilowatt basis, caverns

for maxi-CAES plants are less expensive than

those for mini-CAES.

BGThiS problem is greatly alleviated by the fact that the excavated

material can be used in constructing the compensating reservoir

or other facilities (Peter E. Schaub, comments on OTA electric power

technologies November 1984 draft report, op. cit., 1985).

HTp, L, Hendrickson, Lega/ and Regulatory Issues ~ffWf/ng COnlpressed Air Energy .Storage (Rlchland, WA: Pacific Northwest Lal]-

oratory, July 1981 ), PNL-3862, UC-94b.

Advanced Batteries

Introduction

Batteries are more efficient than mechanical

energy storage systems, but their principal advantage is flexibility. Batteries are modular so that

plant construction lead-times can be very short

and capacity can be added as needed. Batteries

have almost no emissions, produce little noise

(though because of pumps and ventilation systems, they are not silent), and they can be sited

near an intended load, even in urban areas. A

battery’s ability to rapidly begin charging or discharging (reaching full power in a matter of

seconds, as opposed to minutes for a CAES system) makes it valuable for optimizing utility operations. However, battery-storage installations do

not benefit very much from economies of scale

either in capital costs or in maintenance costs,

so that if large blocks of storage are required,

CAES may be less expensive. Also, though cost

effective and reliable in numerous remote applications, battery technology has not yet achieved

the combination of low cost, good performance,

and low risk necessary to stimulate investment

in grid-connected applications.

There are two types of utility-scale batteries

which under some circumstances could be particularly important in the 1990s: advanced leadacid batteries, and zinc-chloride batteries. Leadacid batteries are in wide use today mostly in

automobiles and other mobile applications; advanced lead batteries constitute an incremental

improvement over the existing technology. Zincchloride batteries are a newer technology, and

constitute a fundamental departure from the conventional lead-acid battery. I n both cases, individual modules similar to commercial modules

which might be deployed in the 1990s, have been

tested at the Battery Energy Test Facility in New

Jersey. 88 Though neither type of battery has been

deployed yet in a multi megawatt commercial installation, plans to do so during the late 1980s

are being developed and implemented.

Other battery technologies meanwhile are being pursued. Among these, the most promising

appear to be zinc-bromide batteries and sodium-

~Bsee ch, g for further detai Is on this f~c i Iity.
Ch. 4—New Technologies for Generating and Storing Electric Power . 123

Typical Battery Installation for the 1990s

If battery technology is deployed in the 1990s

by utilities, the general requirements of a typical

plant, regardless of the battery technology employed, are expected to be a peak power output of 20 MWe and a storage capacity of about

100 MWh. Such a plant could consist of about

10 to 50 factory built modules, along with control and power conditioning equipment, housed

in a protective building (see figures 4-30 and q31). Battery installations outside the utilityindustry might be considerably smaller.

The total land necessary will depend on both

the so-called “energy footprint” (energy density

i n kilowatt-hour per square meter) of the particular battery technology as well as the amount of

space necessary for easy maintenance. Each of

the reference battery installations discussed here

will require about 0.02 to 0.03 acres. There are

no fuel and only minimal water requirements.

The lead-time required to deploy battery installations is expected to be very short. Because of

the comparatively low environmental impacts of

the installation, licensing could proceed quite

rapidly. And since the battery moduIes are factory built, construction can be very rapid too. The

lead-time of the plant should be less than 2 years.

There is, however, uncertainty regarding the time

required for Iicensing and permitting. Concern

over possible accidents and disposal of hazardous materials, discussed in greater detail below,

couId be a source of reguIatory delays particu -
124 ● New Electric Power Technologies: Problems and Prospects for the 1990s

Figure 4-30.—Generic Battery System

Enclosure

Enclosure
Ch. 4—New Technologies for Generating and Storing E/ectric Power • 125

Figure 4-31 .—A Commercial Load-Leveling Zinc-Chloride Battery System

Englneerlng Conference San Francisco CA, Aug 19-24, 1984
126 . New Electric Power Technologies: Problems and Prospects for the 1990s

Figure 4-32.— Lead-Acid Batteries

The illustrations below show how a lead-acid battery stores electrlc energy. Advanced lead-acid batteries differ (n the construction of the electrodes, etc., but the basic operation is the same as the more traditional designs.

In its fully charged state, the negative electrode consists of spongy

lead with a small mixture of antimony (around 10 percent), while the

positive electrode is lead dioxide. The electrolyte is sulfuric acid.

Electron flow

.

Fully charged

When fully discharged, the battery’s electrodes are almost entirely

lead sulfate and the electrolyte IS largely water.

electrode electrode

PbS04 PbS04

Negative Positive

electrode electrode

\ A

Discharging

To charge the battery, electrons are driven back into the negative

– Discharged

4 4 .2

Electron flow

l . -

electrode electrode

Charging

4
Ch. 4—New Technologies for Generating and Storing Electric Power ● 127

The safety hazards of advanced lead-acid batteries occur primarily if the battery is overcharged. In this instance, it will generate potentially explosive mixtures of hydrogen and oxygen

which must be ventilated. Stibine and arsine can

also be formed from the materials used i n the

electrodes. Finally, there are also dangers from

acid spills and fire. When the battery is decommissioned, the lead must be recycled, and the

acid disposed of. However, there is much experience with lead-acid batteries, and few safety

problems are anticipated if well-established maintenance and safety procedures are followed.

Zinc-Chloride Batteries.–The zinc-chloride

battery has been under development since the

early 1970s. It is a flowing electrolyte battery (see

figure 4-33). During charging, zinc is removed

from the zinc-chloride electrolyte and deposited

onto the negative graphite electrode in the battery stack, while chlorine gas is formed at the

positive electrode. The gas is pumped into the

battery sump, where it reacts with water at 10°

C to form chlorine hydrate, an easily managable

slush. During discharge, the chlorine hydrate is

heated to extract the chlorine gas, which is

pumped back into the stack, where it absorbs the

zinc and releases the stored electrical energy.

A principal advantage of the zinc-chloride battery is that it promises to be ultimately less expensive than the lead-acid battery, due primarily to the inexpensive materials that go into its

construction. However, the technology, which

requires pumps and refrigeration equipment, is

more complex—it is sometimes described as being more like a chemical plant than a battery. 94

Since no commercial design zinc-chloride battery has yet been operated, any cost projections

must be taken with some caution. (See appendix A, table A-9.)

Estimates indicate that at a production level of

about 700 MWe/year, zinc-chloride batteries

could be sold at a price less that-t $500/kWe, Because zinc-chloride batteries will most likely

make their first appearance in grid-connected use

(unlike lead-acid batteries which are already sold

in other markets), this price is likely to depend

‘W)TA statt;nter~ Iew~ with ( 1 ) Arnold Fickett, op. cit., 1984 and

i2) J.J, KelleY, EXIDE Corp., Aug. 29, 1984,

strongly on the volume produced. If only 50

MWe/year were made, the price could be about

$860/kWe; and early commercial units could cost

as much as $3,000 /kWe.

The zinc-chlorine battery may have a longer

lifetime than the lead-acid battery. The best cells

have run for 2,500 cycles, and while there have

been numerous problems with pumps and plumbing, no basic mechanisms have been identified

which would limit the lifetime to less than 5,000

cycles. 95 However, the 500 kWh test module at

the BEST facility has only run for less than 60 cycles, and several tough engineering problems

have yet to be overcome before the battery can

have a guaranteed lifetime long enough for commercialization. In addition, the AC to AC roundtrip efficiency, which is currently in the low 60

to 65 percent range for the large battery systems,

must be increased to 67 to 70 percent; values in

this range have been attained by smaller prototypes.

The O&M requirements of zinc-chloride systems are even more uncertain than for lead-acid

systems. However, the expected longer lifetimes,

and the less expensive replacement costs for the

stacks and sumps (estimated to be about onethird the initial capital cost of the battery) should

lead to Ievelized replacement O&M costs in the

3 to 9 mills/kWh range. For lack of better data

on operating experience, the annual O&M costs

are estimated to be the same as for lead-acid, I

to 4 mills/kWh, though because of the increased

complexity of the system, they probably will be

higher.

Another major advantage of the zinc-chloride

battery over the lead-acid battery is that their reaction rates are controllable. This is due to the

fact that, in a charged zinc-chloride battery, the

zinc and the chlorine are separated in the stacks

and sumps. The rate at which the battery discharges is controlled by the speed at which the

pumps allow the reactants to recombine. This not

only makes the battery more flexible in its operation, but provides a major safety advantage in

that if a zinc-chloride cell malfunctions, its discharge can be stopped by shutting off the chlorine pumps. In contrast, the reactants in a

~JOTA stdf~ I nter~lew with Arnold Fickett, op. cit. ~ J 984.
128 ● New Electric Power Technologies: Problems and Prospects for the 1990s

Figure 4-33.—Zinc-Chloride Flowing Electrolyte Batteries

H

H

Fully charged

When the battery IS fully charged, the negative electrode IS plated

with zinc and the electrolyte has only a weak concentration of zinc

chloride. The battery sump IS filled with chilled chlorine hydrate.

Ele

fl

Zinc [ /

ZnCll(aq) C I

1 = H 20’ H20

Charging

Heat

As the battery is charged, chlorine ions from the electrolyte combine

at the positive electrode to form chlorine gas and release two

electrons. These electrons are driven to the negative electrode by

the charging generator There they combine with zinc being plated

onto the negative electrode, The chlorine gas is pumped to the sump

which has been chilled to below 10 “C, The gas reacts with the cold

water and forms an easily storable solid, chlorine hydrate.

flow

Discharge

The battery IS discharged by heating

sump, which then releases the chlorine gas. This gas is pumped to

the stack, where it combines with electrons from the positive

electrodes and breaks into chlorine ions. At the negative electrode

the zinc atoms release electrons and enter the electrolyte as zinc

Ions.

Negative electrode: Zn - Zn + + e -
Ch. 4—New Technologies for Generating and Storing Electric Power Ž 129

charged lead-acid battery cell remain in the same

battery case, so that short-circuited terminals

could lead to a sudden release of the stored

energy.

A major concern of regulatory ofticials considering zinc-chloride plants is likely to be the safety

problems associated with the accidental release

of chlorine. Since the chlorine is stored in a solid

form, there is no danger of a sudden release of

large quantities of the gas. However, the same

procedures used in industrial plants manufacturing or using this gas must be followed. In addition, the sum ps must be sufficiently insulated so

that in the event of a malfunction of the refrigeration system, the chlorine will stay frozen in the

chIoride hydrate phase long enough for repairs

to be made.

SUMMARY OF CURRENT ACTIVITY

The tables in appendix A at the end of this re- i n the U n ited States. The extent to which capacport summarize the cost and performance char- ity already has been deployed or is being conacteristics discussed in this chapter. Table 4-2 structed provides an additional indication of the

summarizes the information detailed in the ap- cost, performance and risk associated with the

pendix. Table 4-4 provides an overview of the technologies.

plants which currently are installed or operating

Table 4.4.—Developing Technologies: Major Electric Plants Installed or Under Construction by May 1, 1985

Technology Capacity Location Primary sources of funds Status

Wind turbinesa . . . . . . . . . 550+ MWe (gross)b

Solar thermal electric:

Centrai receiver . . . . . . . .

Paraboiic trough . . . . . . . .

Parabolic dish . .

Solar pond. . . . . . . . . . . . .

Photovoltaics:

Fiat piate ... . . . . . . . .

Concentrator. . . . . . .

Geothermal:

Dual flash ., . . . . . . . . . . .

Binary:

Smail ., . . . . . . . . . . . . .

Large . . . . . . . . . . . . . . .

100+ MWe (gross)c

? MWed

10 MWe (net)e

0.75 MWe

14 MWe (net)

30 MWe (net)

0.025 MWe (net)f

2 x 0,025 MWe (net)f

2 x 0.025 MWe (net)f

3.6 MWe

None

1 MWe (de, gross)

1 MWe (de, gross)

1 MWe (de, gross)

6.5 MWe (de, gross)

0.75 MWe (de, gross)

4.5 MWe (de, gross)

1.5 MWe (de, gross)

3.5 MWe (de, gross)

10 M’We

10 MWe

47 MWe (net)

32 MWe (net)

2 x 3.5 MWe

3 x 0.3 MWe

3 x 0.4 MWe

10 MWe

1 x 0.75 MWe (gross)

3 x 0.35 MWe (gross)

3 x 0.45 MWe (gross)

4 x 1.25 MWe (gross)

3 x 0.85 MWe (gross)

45 MWe (net)

California wind farms

U.S. wind farms outside

of California

All U.S. wind farms

Daggett, CA

Albuquerque, NM

Daggett, CA

Daggett, CA

Palm Springs, CA

Various iocations

Various locations,

Warner Springs, CA

Sacramento

Sacramento, CA

Hesperia, CA

Carrisa Plains, CA

Carrisa Plains, CA

Borrego Springs, CA

Davis, CA

Barstow, CA

Brawley, CA

Salton Sea, CA

Heber, CA

Salton Sea, CA

Mammoth, CA

Hammersly Canyon, OR

Hammersly Canyon, OR

East Mesa, CA

Wabuska, NV

Lakeview, OR

Lakeview, OR

Suifurviiie, UT

Sulfurville, UT

Heber, CA

Nonutility

Nonutility

Nonutility

Utility, nonutility, and

Government

Utility, nonutiiity, and

Government

Nonutility

Nonutiiity

Government

Nonutility

Non utility

Nonutility

Utility and Government

Utility and Government

Nonutility

Nonutility

Nonutility

Nonutility

Nonutility

Nonutiiity

Utility lnonutiiity

Utilitylnonutility

Nonutility

Nonutility

Nonutility

Nonutility

Nonutility

Nonutility

Nonutiiity

Nonutiiity

Nonutiiity

Nonutiiity

Nonutility

Utility, nonutility, and

Government

Instailed

Installed

Under construction (1986)

installed

Installed

Installed

Under construction (1986)

Installed

Instailed

Under construction

Installed

Installed

Under construction (1985)

instailed

Installed

Under construction

Instaiiedg

Installed

Instaiiedg

Installed

Installed

Under construction (1985)

Under construction (1985)

Installed

Installed

Instaliedh

installed

Instalied

Instaiiedh

Instailedh

Under construction (1985)!

Under construction (1985)1

Installed
130 • New Electric Power Technologies: Problems and Prospects for the 1990s

Table 4-4.—Developing Technologies: Major Electric Plants Installed or Under Construction

by May 1, 1985-Continued

Technology Capacity — Location —

Primary sources of funds Status

Fuel cells:

Large, . . . . . . . . . . . . . . . . .

Small J 

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

Small cogeneration . . . . .

IGCCn . . . . . . . . . . . . . . . . . . .

Batteries:

Lead acid”. . . . . . . . . . . . .

Zinc chloride. . . . . . . . . .

CAES:

Mini . . . . . . . . . . . . . . . . . .

Maxi . . . . . . . . . . . . . . . . . .

28 MWe

2.8 MWe

24 MWe

20 MWe

100 MWe

Pontiac, Ml

Washington, DC

Enfield, ME

Chinese Station, CA

Daggett, CA

0.5 MWe Newark, NJ Utility and Government

NoneP

None

None

Installed

Under construction

Under construction (1989)

Under construction (1987)

Under construction (1986)

Under construction (1986)

Under construction (1985)

Under construction (1986)

Under construction (1987)

Under construction (1986)

Under construction (1986)

Under construction (1987)

Installed

Under construction (1986)

Installed

Under construction (1986)

Under construction (1986)

Installed

Installed

alncludes small. and medium-sized wind turbines.

bApproximately 550 Mwe were operating in California at the end of 1984, It is not known how much additional capacity was Installed by May 1985

cApproximately100 Mwe were operating outside of California at the end of 1984, It is not known how much additional capacity had been installed outside Cal if Ornla

by May 1985,

dlt is not known how much capacity was under construction on May 1, 1985.

eThis facility, the ~lar One pilot plant, is not a Commerc ial. scale plant and differs in other impo~ant ways from the type of system which might be deployed commercially in the 1990s.

fThis installation consists of only one electricity producing module; a commercial installation probably would COnSiSt of hundreds of modules.

90nly 10 percent of the modules were operating at the time because of problems with the Power conversion sYStems.

hlnstatled but not operating, pending contractual negotiations with utilitiOS.

iThe equipment ~dules have been delivered to the site; site preparation, however, has not started.

iThGs.e un~ts are not cornrnerc~a~.sc~e units.

klncluding the Electric Power Research lnStitUtO.

IThis ,s the total capacity which may be generated from the four AFBC boilers which Will be installed,

mThis is the tot~ capacity which may be generated from the two AF8C boilers which will be installed.

nwhile this inst~lation, the Cool Water unit, uses commercial. scale components, the installationitself IS nOt a Commercial-SCa!.S installation,

owhile this installation at the Batte~ Energy stora~e Test Facility uses a commercia~.scale batte~ module, the installation itseif iS not a COITrrl)OrCial-SCa[O inStaiiatiOn

PA 0.5.Mwe zinc chloride commercial-scale battery module was, however, operating at the Battery Energy storage Test facility until early 1985.

SOURCE Office of Technology Assessment.
Chapter 5

Conventional Technologies for

Electric Utilities in the 1990s
CONTENTS

Page

introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..., . . . . . . . . . . . . . . . . . . 133

Plant Improvement and Life Extension . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 133

Introcluction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 133

objectives of Plant Betterment Options. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 135

Relative Cost and Performance. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 137

Regulatory and Insurance Considerations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 139

Summary and Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 140

Conventional Generating Options . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 141

Load Management. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 142

Introduction . . . . . . . . . . . . . . . . . . . . ., . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 142

Major Supply/Demand Variables Relating to Load Management . . . . . . . . . . . . . . . . . . 143

Other Variables . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 146

Current Status of Load Management Efforts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 147

Innovative Rates. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 147

Load Control . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 148

Potential Peak Load Reductions From Load Management . . . . . . . . . . . . . . . . . . . . . . . 149

Technologies for Load Management. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 151

Ancillary Technologies Owned or Controlled by the Customer. . . . . . . . . . . . . . . . . . . 157

Major Impediments to Load Management ., . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 157

List of Tables

Table No. Page

5-1!

5 - 2

5-3,

5 - 4

5-5.

5 - 6

5-7,

5-8,

Average and Weighted Average Age of U.S. Electric Power

Generating Facilities, 1984 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .............134

Environmental Requirements for Existing and New Plants . ....................135

Turbine Generator Uprating Checklist . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. ...137

Powerplant Life Extension Projects: Regulatory Summary. . ....................139

Cost and Performance Summaries . . . . . . . . . . . . . . . . . . . . . ...................142

Use of Major Electricity-Using Appliances in U.S. Residences, 1982.............145

Major Uses of Purchased Electricity in the United States, 1983.................147

Load Control Appliances and Sectors Controlled in 1983

Under Utility-Sponsored Load Control Programs. . . . . . . . . . . . . . . . . . . . . . .......149

l.ist of Figures

Figure No. Page

5-1. Age of U.S. Electric Power Generating Facilities, 1980-95 . .................,.134

5-2. Heat Rate v. Generator Output for Uprated and Restored Turbine-Generator Set .137

5-3. Trend of Powerplant Heat Rate With Age . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ...138

5-4. Trends of Forced Outage Rates With Age . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ...138

5-5

5-6

5-7

5-8

5-9

5-1o

5-11

5-12

5-13

5-14

Trend of Plant Forced Outage Rate Duration With Age . .....................138

Life Extension Cost v. Powerplant Reliability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .138

Conventional Technology Costs, Utility Ownership-West . ...................141

Load Shape Objectives. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ...................144

Illustration of Customer Class Load Profiles-North Central Census Region

in the 1970s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . , . . . . . .146

An Example of Time-of-Day Rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .........148

Time-of-Day Rates Shift Patterns of Ekctricity Use . .........................148

A Direct-Control Load Management Technology:

Domestic Water Heater Cycling Control . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ...,153

A Local-Control Load Management Technology: Temperature-Activated Switches .154

A Distributed Control Load Management Technology:

Load Management Thermostats. . . . . . . . . . . . . . . . . . . . . . . . ..................155
Chapter 5

Conventional Technologies for

Electric Utilities in the 1990s

INTRODUCTION

The financial difficulties faced by utilities in the

1970s and early 1980s have prompted many to

investigate extending the lives of existing facilites

or even rehabilitating old plants to yield additional capacity. Control of electricity end use has

also surfaced as another promising alternative to

meeting all or part of future load growth. For most

of these utilities, however, conventional central

station powerplants still provide the base against

which all other supply-enhancing or demandcontrolling investments are compared.

This chapter presents a benchmark set of cost

and performance estimates for conventional options of traditional central station powerplants

and for a variety of options which extend the lives

or otherwise improve the performance of existing generating facilities. Since these strategic options are not the principal focus of this assessment, these estimates are presented primarily to

enable comparisons with the new generating options discussed in chapter 4. These comparisons

are reported in chapter 8. I n addition, load management, one of the strategic options being pursued aggressively by utilities in many regions of

the United States for controlling end use of electricity, is discussed in this chapter.

PLANT IMPROVEMENT AND LIFE EXTENSION

Introduction

In the wake of declining demand growth and

soaring costs of new generating capacity, many

utilities have begun to examine the so-called

plant betterment option for improving the performance of or extending the lives of existing capacity .

1 This option is likely to become

increasingly important through the end of this decade and into the 1990s—a period when the U.S.

powerplant inventory will undergo dramatic

changes. For example, since 1975, new plant order cancellations nationwide by utilities have exceeded new plant orders. By the year 1995, if

present new plant ordering patterns continue

about a third of the existing fossil steam generating capacity in the United States will be more

‘R. C. Rittenhouse, “Maintenance and Upgrading Inject New Life

Into Power Plants, ” Power Engineering, March 1984, pp. 41 -50;

T. Yezerskl, Pennsylvania Electric Association Power Generation

Committee, “Power Plant Life Extension Practice at Pennsylvania

Power & Light Co., ” unpublished paper, Sept. 18, 1984; R. CareIock, Potomac Electric Power Co., “Plant Life Extension: Potomac

River Generating Station, ” unpublished paper, September 1984.

than 30 years old (see figure 5-1 and table 5-1).

The age distribution varies considerably by

region, however, as discussed in chapter 7.

Moreover, the plants “coming of age” during this

period will be considerably more valuable than

those of early vintages. In the 1950s, unit sizes

grew to over 100 MW and heat rates fell to below 10,000 Btu/kWh while older units(1920s and

1930s vintage) were much smaller with heat rates

of as high as 20,000 Btu/kWh. z While in the past,

the benefits of new technology far outweighed

pIant betterment options, because of the relative

quality of currently existing plants, this situation

is rapidly changing.

Traditionally, investments in aging fossil plants

began to decline after about 25 years causing reliability to deteriorate accordingly. The plants

were relegated to periodic operation, reserve

duty, and, finally, demolition. For the remainder

2

R. Smock, “Can the Utillty Industry Find a Fountain of Youth

for Its Aging Generating Capacity?” E/ectric Light and Power, March

1984, pp. 14ff.

133
134 ● New Electric Power Technologies: Problems and Prospects for the 1990s

.

1980 1995 1980 1995 1980 1995 1980 1995 1980 1995 1980 1995

Coal Oil and gas Total Nuclear Other Total

Table 5-1 .—Average and Weighted Average Age of U.S. Electric Power Generating Facilities, 1984
Ch. 5—Conventional Technologies for Electric Utilities in the 1990s . 135

of this decade, as new nuclear base load plants

come on-line, existing base load fossil units will

increasingly be relegated to cycling duty which

can significantly shorten plant life. Recent studies,

however, show that in many cases, such plants,

at least those built in the 1950s and 1960s, can

be refurbished cost effectively for $200 to $400/

kW, even in cycling duty applications.3

These

studies also indicate that some refurbishment

projects can include efficiency improvements,

and capacity upgrades of 5 to 10 percent. a

Finally, many siting and environmental requirements facing new capacity can be avoided by

rebuilding existing capacity. Table 5-2 shows the

marked contrast in these requirements for new

versus existing coal-fired units. Current Federal

regulations (New Source Performance Standards—

NSPS) require that any unit that is more than 50

percent rebuilt (defined as 50 percent of the cost

of a new boiler) must reduce sulfur dioxide emissions by 90 percent of the uncontrolled level. It

turns out that a great deal of plant betterment can

be accomplished under this 50 percent requirement. Moreover, an important consideration with

this requirement is that the emissions reduction

—. —

3Glbbs & HIII, Inc., “Considerations for Power Plant Life Extension: Prospects for the 1990s, ” contractor report to OTA, October

1984.

4

R. Smock, “Operating Unit Heat Rates Can Be Cut, Says EPRI;

New Units Can Be 10 Percent More Efficient, ” E/ectric Lighf and

Power, March 1984, p. 24.

Objectives of Plant Betterment Options

It is important to note that plant betterment is

only a substitute for new capacity to the extent

plant retirement can be deferred past the time

originally scheduled, and the plant’s capacity can

be increased as a result of betterment. When

these conditions prevail, plant betterment options

offer considerable promise7 relative to other strategic options. However, they present a complicated planning problem for utilities. Indeed, a

considerable investment is often required to develop the details of a prospective project and its

expected cost. For example, in 1984 Wisconsin

Electric Power Co. commissioned detailed plant

——

SThe regu Iation reads that an existing facility fal Is u rider theses

guidelines provided “it is technologically and economically feasible to meet the applicable standards set forth in this part.”

b“Power Plant Life Extension Economics, Plans Explored at American Power Conference,” E/ectric Light and Power, June 1984, pp.

27-30.

7

0ne indication that this promise is already being realized is that

average plant availability of existing units in the United States has

increased from 67 percent in 1977 to 76 percent in 1984, partially

as a result of plant betterment activities.

Table 5-2.—Environmental Requirements for Existing and New Plants

Particulate Air emissions SO, NOX

Existing plants (1980 typical plants):

Varies from 0.12 3.2 lb/M MBtu. Com- 1.3 lb/M MBtu.

to 0.25 lb/ pliance based on No monitoring

MMBtu coal analysis required

New p/ants >73 MW:

0.03 lb/MMBtu 1.2 lb/M MBtu and 0.6 lb/MMBtu

20°\0 opacity Re- 90°\0 reduction ex- and 65°\0

quires baghouse cept 700/0 if emission reduction.

or very efficient <0.06 lb/M MBtu. Compliance

elect rostat ic Compliance based on based on con

precipitator continuous monitors. tinuous moRequires coal clean- nitors

ing or wet scrubber

(total capital =

$2481kW)

Condenser

cooling water Ash disposal Wastewater treatment

Thermal limits Sluicing and Combining waste

based on eco- ponding of streams (coal pile,

logical studies combined fly broiler cleaning, etc.)

and bottom ash for cotreatment in

ash pond

Cooling towers Dry collection Dedicated possible

and reuse or separate treatment

Iandfilling of pond(s) may require

flyash. Sluicing artificial liner(s) and

and pending of chemical addition

reuse of bottom

ash

SOURCE W Parker, “Plant Life Extension—An Economic Recycle, ” Power Errg(neerlrrg, July 1984, and Judl Greenwald, U S Environmental Protection Agency, personal correspondence with OTA staff, June 18, 1985
136 ● New Electric Power Technologies: Problems and Prospects for the 1990s

betterment studies on a number of existing fossil units, at a cost of more than $1 million per

study.

In considering plant betterment or life extension programs, utilities need to account for both

system level objectives, such as coordination with

existing capacity expansion and scheduled maintenance plans, and unit level objectives, such as

extending the life for a target number of years

at a specified level of capacity, efficiency, and

availability. Indeed, the overall characteristics of

a utility’s system dictate the timing and level of

investment justified in a particular betterment/life

extension project. For example, a utility with a

high reserve margin may consider the relatively

simple step of derating an aging unit to lengthen

its life, while a utility with a low reserve margin

may consider upgrading the unit to both extend

its life and increase its capacity. Although the age

of the unit and the production lost during rebuilding may make the latter strategy more costly than

life extension alone, usually it is still much less

expensive than building new capacity.

Ultimately, all individual improvements relate

to either increased productivity or longevity.

Productivity improvements involve increased

efficiency; increases (restoration or upgrading) in

rated capacity; reduced fuel costs (e.g., through

fuel switching); reduced labor requirements; increased capacity factors; and reduced emissions.

Longevity improvements include mechanisms for

increasing plant life at specified levels of rated

capacity. This may mean extending the life of a

unit at full rated capacity or, by contrast, “mothballing” the unit for use at a later time when all

or part of the rated capacity is needed; mothballing is sometimes referred to as an extended cold

shutdown.

Virtually all life extension/plant improvement

programs begin with a detailed performance test

of any candidate plant to determine the current

status of the equipment, i.e., how far the current

plant operating parameters are from the original

design specifications. Equipment evaluated in the

performance test includes the turbine generator,

boiler, condenser, feedwater heaters, auxiliary

equipment systems, flue gas cleaning equipment,

and plant instrumentation. Comparison of the

most recent performance test with historical performance identifies areas to be investigated in

more detail. A detailed examination of the boiler

usually precedes other studies since its results are

likely to control the length of the overall plant

betterment project being considered. Also, other

areas of the overaIl study may be affected if, for

example, the boiler analysis reveals that it must

be operated at lower pressure to lengthen its life.8

Recommendations resulting from a detailed

performance test and analysis, sometimes termed

a design change package (DCP),9 generally fall

into two categories: 1 ) new procedures for startup, operations and maintenance, training of personnel, update of performance records, and

spare parts support; and 2) equipment or component modifications. The category (1) improvements are usually relatively low cost and very cost

effective. The nature of the category (2) improvements depends on the age of the equipment and

the facility.

Likely plant betterment candidates are middleage generating units (1 O to 20 years old) which,

at some point in their lives, are usually relegated

to intermediate duty cycling where they experience greater load changes, and more frequent

starting and stopping, As noted earlier, this

change in operation can significantly reduce the

operating life of the unit and, as a result, upgrading of middle age units often means adapting

them for cycling duty. Typical enhancements include full flow lubricating oil systems, automatic

turbine controls, and thermal and generator performance monitors (newer units will also benefit from these improvements). In addition, the

middle-aged units will benefit from turbine modification and temperature control equipment.

Upgrading or life extension of older units (20

years or more) usually requires evaluating the

replacement of major components such as turbine rotors, shells, and generator coils. While uprating of components, such as the turbine, may

be possible for older units, it is usually a highly

8S. j. Schebler and R. B. Dean, Stanley Consultants, “Fossil Power

Plant Betterment,” paper presented at Edison Electric Institute Prime

Movers Committee Meeting, New Orleans, LA, Feb. 1, 1984.

9W. O’Keefe, “Planning Helps Make Plant Improvements More

Effective,” Power, February 1984, pp. 89-90.
Ch. 5—Conventional Technologies for Electric Utilities in the 1990s ● 137

customized job. Table 5-3 shows a typical turbine generator uprating checklist which gives the

possible limitations on a candidate upgrading program. Figure 5-2 shows the possible improvements in heat rate of an upgraded (uprated and

restored) turbine-generator unit.

The complexity of performance testing and

analysis has prompted the major equipment

manufacturers to offer comprehensive plant modernization programs. 10 Both manufacturers and

architect-engineering firms see plant betterment

projects as a promising market for their goods and

services.

Finally, some plant improvement projects may

be aimed at reducing emission levels or the use

of specific fuels. For example, many projects in

recent years have been carried out to convert oilfired capacity to coal. Such conversions often involve unit derating, but recent studies show that

recovering as much as two-thirds of the capacity lost after coal conversion can be achieved at

40 to 50 percent of the dollars per kilowatt coal

conversion cost. 11

IO For example, Westinghouse has been marketing turbinegenerator upgrades for several years.

‘ 1 P, Mlliaras, et al., “Reclaiming Lost Capablllty in Power Plant

Coal Conversions: An Irrnovatwe Low-Cost Approach, ” Proceedings ot’ the joint Power Conference, American Society of Mechanical Engineers, 1983, 83-J PGC-Pwr.

Figure 5-2.—Heat Rate v. Generator Output for

Uprated and Restored Turbine-Generator Set

9.000 L

“o 10 20 30 40

Output – 1,000 kW

Relative Cost and Performance

The principal effects of fossil powerplant aging

are: 1 ) decreased efficiency, i.e., the amount of

electricity generated per Btu declines as plant

heat rate increases, and 2) more and longer

forced outages. Figure 5-3 shows the rate of increase in heat rate as a function of age for a typical fossil plant; the average is about 0.3 percent

per year with average maintenance practices. ’2

After about 20 years, the reliability of typical

plants declines dramatically; figures 5-4 and 5-5

show typical increases in rate and duration of

forced outages as a function of age.

Utility concern about reliability, in particular,

prompts the decision to invest in plant betterment

projects because the cost of lost production during an outage may be very high. For example,

if a utility’s replacement power cost $0.04/kWh,

a 1 percent improvement in the capacity factor

of a 500 MW fossil unit will save the utility about

$1.75 million a year. That savings must, of course,

be balanced against the cost of achieving the capacity factor improvement; this trade-off is the

central focus of plant betterment studies. The

trade-off is illustrated in figure 5-6; the total “reliability cost” of operating a generating facility is the

sum of the cost of lost production when outages

occur and the plant betterment investment (or
Age

w

I

20 I

40
Ch. 5–Conventiona/ Technologies for Electric Utilities in the 1990s . 139

preventative maintenance allowance) charged to

the plant to establish a given level of reliability.

The cost of outage decreases as reliability increases and the plant betterment investment increases. The target of a plant betterment program

is to minimize the total cost as shown in the

figure.

The life extension and/or upgrading decision

is complicated by the fact that, while a powerplant’s forced outage rate increases with age, the

aging characteristics of individual plant components as well as the cost of improving component reliability may vary widely.

Regulatory and Insurance

Considerations

Regulation of Plant Betterment Projects

In addition to engineering feasibility, compliance with over 50 Federal and State regulations

may be required in the course of considering a

plant betterment program13 These include Federal and State air quality programs, water quality and solid waste programs, environmental impact studies, Corps of Engineer rules, exemptions

from the Powerplant and Industrial Fuel Use Act,

and utility commission approval—see table 5-4.

Perhaps the most important regulatory considerations are the major Federal air quality regulations of NSPS, mentioned earlier, and the Prevention of Significant Deterioration (PSD) rules.

Generally, Federal regulations apply to a plant

betterment program that increases emissions by

any amount or costs more than 50 percent of a

new boiler. State Implementation Plans and other

State air quality statutes will generally apply to

all projects,

Of particular concern maybe the NSPS requirements which require that, if a fossil plant ( >250

MMBtu/hr and constructed prior to 1971) is either “modified” or “reconstructed” as defined

in table 5-4, the plant is subject to the 1978 NSPS

provisions of stringent emissions limitations and

percent sulfur removal. This would in most in-

—.———

I ~D, ward and A, MekO, ‘‘Regulatory Aspects of power plant Betterment, ’ H’orkshop Notebook: Fossil P/ant Life Extension (Palo

Alto, CA: Electric Power Research Institute, June 1984), EPRI

RP- 1862-3.

Table 5-4.—Powerplant Life Extension Projects:

Regulatory Summary

Federal requirements:

NSPS (air):

● Standards apply if facility is:

1. new:

—replacement of boiler

2. modified:

—physical or operational change that results in

increased emissions.

3. reconstructed:

—fixed capital costs exceed 50°/0 of the cost of a

new steam generator.

PSD (air):

● Permit requirements apply to “major

modification ’’—modification for which net emissions

increase exceeds de minimis limits (permit may be

issued by State).

NPDES (water):

● Permit required for point source discharges to

navigable waterways. Modified sources require new

or modified permit (permit may be issued by State).

State requirements:

Air:

● New or modified construction and operating permits

required.

● Bubble policy may apply,

Water:

● New or modified construction and operating permits

required.

Solid waste:

c New or modified construction and operating permits

required.

Other requirements:

EIS:

. Not required unless major renovation subject to

Federal licensing occurs.

Corps of Engineers:

. Nationwide permits for construction activity in

navigable waters are available.

State PUC:

● Approval requried for modification of powerplant and

recovery of costs through rate base.

SOURCE T Evans, “Regulatory Considerations of Life Extension Projects, ’ Vlr.

glnla Electrlc Power Co , unpublished report, 1984

stances require pollution controls on a facility

where few, if any, existed prior to the modification. The requirements are even more stringent

for plants constructed between 1971 and 1978.

It is important to note, however, that under the

current regulations a great deal of plant betterment can be and is already being accomplished

without these provisions being invoked.

A PSD permit is also required for any major

modification to an existing plant; a special set of

provisions defines and is applied to such modifications. Finally, if an upgraded existing facility increases emissions in a nonattainment area, pollution offsets would be required.
140 ● New Electric Power Technologies: Problems and Prospects for the 1990s
Ch. 5—Conventiona/ Technologies for Electric Uti/ities in the 1990s ● 141

CONVENTIONAL GENERATING OPTIONS

in order to be deployed in significant numbers,

the developing technologies addressed in this report must compete successfully with existing electric utility generating options. The five major conventional power generation technology types that

will most likely be available to electric utilities in

the 1990s are: pulverized coal-fired plants, combined-cycle plants, combustion turbines, slowspeed diesels, and light water nuclear powerplants.

This section briefly presents the benchmark

cost and performance estimates for these five

technologies as well as for life extension of existing coal-fired plants. Cross-technology comparison of these technologies with the developing

technologies is contained in chapter 8.

Table 5-5 contains the benchmark set of cost

and performance estimates for the five conventional technologies. All of the listed technologies,

except one—combustion turbines—are capable

of base load operation. Three of these technologies, pulverized coal-fired, combined-cycle, and

slow-speed diesel, are also capable of intermediate-load operation. One major difference

among the conventional alternatives is plant size.

Although there is increasing interest in small,

modular plants (see chapter 3), the technologies

listed in table 5-5 are generally large, central station powerplants. Slow-speed diesels and combustion turbines represent the smaller sized central station technologies.

The Ievelized cost model used in chapter 8 was

used with the cost and performance estimates

shown in table 5-5 to derive most likely electric

utility costs. These Ievelized costs are presented

in figure 5-7. This figure also includes a Ievelized

cost estimate for existing coal powerplant betterment. The plant costs and the capacity and effiFigure 5-7.—Conventional Technology Costs,

Utility Ownership—West

Technology

ciency upgrades discussed earlier were applied

to the generic coal plant listed in table 5-5 to derive an expected cost for coal plant betterment.

According to this figure, the lowest cost conventional alternative is life extension and plant betterment of existing coal units. The next lowest

cost conventional alternative is pulverized coal

plants, followed by light water nuclear plants.

The cost and performance estimates for the

conventional technologies discussed in this section represent the present technologies expected

to be available in the 1990s. Additional enhancements to these technologies or different design

configurations may occur prior to 1990 which

could dramatically change these expected costs.
142 ● New Electric Power Technologies: Problems and Prospects for the 1990s

Table 5.5.—Cost and Performance Summaries

Technologies

. —

Pulverized Combined- Combustion Slow-speed Municipal

Reference swstem coal-fired cycle turbine diesel solid waste Nuclear

General:

Reference year . . . . . . . .

Reference-plant size . . .

Lead-time . . . . . . . . . . . .

Land required . . . . . . . . .

Water required . . . . . . . .

Performance parameters:

Operating availability . .

Duty cycle . . . . . . . . . . . .

Capacity factor. . . . . . . .

Plant lifetime . . . . . . . . .

Plant efficiency . . . . . . .

costs:

Capital costs . . . . . . . . .

O&M costs . . . . . . . . . . .

Fuel costs . . . . . . . . . . . .

1990

500 MWe

6-8 years

640 acres

5.94 million

galiday

9.5 mills/

k Wh

17 mills/

kWh

1990 1990

600 MWe 150 MWe

3-4 years 2-3 years

5-10 acres 2-5 acres

2.9 million Negligible

gal/day

1990

40 MWe

2 years

10-15 acres

Negligible

850/o 680/0

Base Base

Introduction

The term load management refers to manipulation of customer demand by economic and/or

technical means. It involves a combination of

economic arrangements and technology typically

directed towards one of the following objectives:

1.

2.

Encouraging demand during off-peak periods: During the valleys of a load curve, a

large portion of generating equipment is idle.

Utilities benefit when that capacity is more

heavily used. This typically is achieved by

either shifting use to those periods from

peak-demand periods (load shifting) or by

encouraging additional use during off-peak

periods (valley filling).

Inhibiting demand during peak periods: It

may also be desirable to reduce peak-period

demand. When electricity is purchased from

other utilities, costs per kilowatt-hour during these periods are high. Or, to meet peakperiod demand, a utility may have to use

generators which are more costly to operate because they are older and less efficient

or they burn more expensive fuel. In addition, if growth in peak-period demand requires the utility to invest in new capacity,

load management may reduce the rate at

which such expenditures must be made.

In the context of this study, the most important benefit “of load management lies in the second objective which if realized allows utilities to

defer additional peak-load generating capacity.

In addition, by reducing the share of the load

served during the peak period, load management

permits a higher proportion of demand to be

served by lower cost electricity. other advantages

are also becoming evident as utilities gain more

experience with load management, and as sophisticated models are developed which permit

better assessment of load management.18 For exIeFor example, See: I ) John L. Levett & Dorothy A. COnant, “Load

Management for Transmission and Distribution Deferral, ” Public

Utilities For?nighr/y, vol. 115, No. 8, Apr. 18, 1985, pp. 34-39; 2)

Associated Power Analysts, Inc., Study of Effect of Load Management on Generating-System Re/iabi/ity (Palo Alto, CA: Electric Power

Research Institute, 1984), EPRI EA-3575.
Ch. 5—Conventional Technologies for Electric Utilities in the 1990s ● 143

ample, load management may reduce future demand uncertainty. And some utilities have found

it to be an effective means of improving the efficiency of power system operation by allowing increased flexibility in the hour-by-hour allocation

of system resources.19

Load management is only one of many closely

related options available to utilities in managing

demand. Other demand management alternatives include encouraging conversions to electric

power through new applications, and more efficient use such as home insu Iation and electronic

motor controls. I n addition, demand management is also carried out indirectly to the degree

that customers are encouraged to generate their

own power. These other demand management

options may be pursued independently of load

management, or may be implemented as part of

an integrated program with load management.

Depending on the nature of the demand management strategy, the utility’s daily load curve can

be modified as shown in figure 5-8.

Within load management falls a very wide

range of strategies, technologies, and economic

arrangements. These typically center around

some combination of: 1 ) load management incentives, 2) advanced meters, and 3) load control equipment, While many other elements may

be present in a load management program, these

appear to be of pivotal importance. Although incentives will be touched upon below, the emphasis will be placed on the technologies themselves: specifically advanced meters and load

control equipment.

With respect to the number of customers, the

residential sector is by far the most important i n

load management. But the fact that the sector

consists of a large number of relatively small consumers makes load management quite difficult

to assess and implement. In part, because of this,

only a small fraction of the major electric appliances in this sector have load management controls (see table 5-6). Nevertheless, utilities are

increasingly interested in residential load management, both because the sector uses a large

———

“B. F. Hastings, “Cost and Performance of Load Management

Tech nologies, ” comments presented at OTA Load Management

Workshop, Washington, DC, Aug. 15, 1984.

quantity of electricity (in 1984 it accounted for

34 percent of all electricity used) and because it

is the largest contributor to the daily fluctuations

in demand (see figure 5-9).

In the industrial and commercial sectors, while

only a relatively small number of loads have been

managed, the contribution has been significant.

These sectors contain major loads amenable to

load management, and, compared to the residential sector, fewer customers with larger demands

per customer. Hence, load management is already practiced more widely in these sectors.

Considerable opportunities remain, however,

and industrial and commercial customers likely

will continue to account for a major portion of

load management during this century.

Current evidence suggests that load management will provide, in many cases, an economic

alternative to new generating capacity in the

1990s, It may be a particularly attractive utility

investment when it is part of an integrated system designed not only to manage loads but also

to serve other utility or customer needs.

Some of the potential for load management can

be met by using existing technologies at current

costs and performance levels; but considerably

greater application will require the introduction

of technologies which offer a combination of

cost, performance, and risk superior to current

technology. Furthermore, institutional arrangements must be developed within which load

management can be more easily deployed. Finally, the costs, benefits, and uncertainties of load

management options must be better understood

and integrated into the thinking of utilities and

of others upon whose decisions affect load management deployment.

Major Supply/Demand Variables

Relating to Load Management

Key End-Use Sectors and Applications

Central to load management in the 1990s will

be the electricity demand patterns which develop

in the united States. What sectors will be most

important and how will they use electricity? These

patterns determine the magnitude of the load at

any time, and the shape of the load curve, They
144 ● New Electric Power Technologies: Problems and Prospects for the 1990s

Figure 5.8.— Load Shape Objectives

“Adapted from Clark W, Gellings, Highlights of a speech presented to the 1982 Executive Symposium of EEI Customer Service and Marketing Personnel.

SOURCE Battelle-Columbus Divis!on & Synergic Resources Corp., Derrrand-Side Management, Vo/urne 3: Techrro/ogy A/tematives and Market /mp/ernentatiori Methods

(Palo Alto, CA: Electric Power Research Institute, 1964), EPRI EA/EM-3597
Ch. 5—Conventional Technologies for Electric Utilities in the 1990s ● 145

Electric Power Research Ins;ltute May l’9&l), EPRI EM.3529

also strongly influence the selection of load management strategies. For example, managing industrial use of electricity for process heat will be

quite different than that of managing residential

electricity demand for air-conditioning.

Usage patterns will depend on many interrelated variables; precise predictions of future

consumption are impossible.20 Nevertheless,

many useful generalizations can be made by

looking at the conditions which have characterized the past.

In the residential sector, the single most important application of electric power is air-conditioning, which in 1984 accounted for about 14

percent of delivered residential electricity .21

Somewhat less important but still sizable quantities of electricity were used for water heating

and space heating. These three applications accounted for over a third of residential electricity

consumption in 1983. These appliances are particularly important in load management efforts

~~F~r example, see: Rene H. Males, “Load Management—The

Strategic Opportunity, ” Workshop Proceedings: Planning and

Assessment of’ Load Management (Palo Alto, CA: Electric Power

Research Institute, 1984), EPRI EA-3464, pp. 3-1 through 3-8.

j I End-use energy consumption excludes the energy used to generate and transmit electricity to the end-use sectors, and accounts

for only the energy used by the consumer.

because they typically are major contributors to

fluctuations in overall demand for electric power

(see figure 5-9).

In the commercial sector, lighting and airconditioning are the most important applications

for electric power, each accounting for roughly

40 percent of electricity use. Much of the rest is

used in used in water and space heating. The use

of electric power for air-conditioning and space

heating in the commercial sector is especially important. They accounted for 12 percent of national electricity use (1 984) and contribute significantly to daily fluctuations in demand.

In industry, the largest fraction of electric

power—over 50 percent in 1984—is used in machine drives. Electrolysis accounted for about 13

percent industrial electricity use; slightly less was

used in generating process heat. Most of the balance went for for space heating and lighting.

While industry uses a large amount of the electrical energy, its cyclical variations tend to be less

extreme than those in the commercial and residential sectors.

As table 5-7 suggests, the individual applications which account for the largest portion of

electricity use is found in the industrial sector,

followed by the commercial sector and then the
146 ● New Electric Power Technologies: Problems and Prospects for the 1990s

Figure 5-9.—illustration of Customer Class Load Profiles—North Central Census Region in the 1970s

Peak summer day Peak winter day

5 10 15 20

Hou r
Ch. 5—Conventional Technologies for Electric Utilities in the 1990s ● 147

electric power rather than generating it themselves. These characteristics, alone or in combination, may encourage load management.

Though these features vary from one utility to the

next, some regional generalizations can be made.

(See the section on load management in chapter 7.)

Current Status of

Load Management Efforts

Because of the large variety of forms which load

management may take, it is very difficu k to accurately determine the extent to which it is being exercised by utilities. There are, however, two

key indicators of load management activity which

have been examined in detail in surveys by the

Electric Power Research Institute (EPRI). First is

the implementation by utilities of innovative rates

designed to modify customer electricity demand

patterns. Second are activities by the electric utilities relating to direct load control.

Innovative Rates

The Electric Power Research Institute in 1983

sponsored a survey of electric utilities to gather

information on innovative rates in the utility industry. EPRI found that at least half of the investorowned utilities in the United States had implemented or proposed innovative rates; and about

6 percent of publicly owned utilities had done

so. 23 The most commonly applied rates were

time-of-use rates, rates which are linked to the

specific time at which the power is needed.

Figures 5-10 and 5-11 illustrate how a time-of-use

rate can affect electricity demand.

About 20 million electricity customers served

by utilities which responded to the EPRI survey

are affected by innovative rates. That is about 21

percent of all the utility customers in the United

States. 24 Most of the customers under the innovative rates were in the residential sector, though

IJThe estimates are based on information provided by the Electric Power Research Institute (Ebasco Business Consulting Co., /nnovative Rate Design Survey (Palo Alto, CA: Electric Power Research

Institute, 1985), EPRI EA-3830).

In the responses to a checklist sent to the members of the American Public Power Association and the National Rural Electric Cooperative Association, approximately 175 members reported innovative-rate design activity. Since there is a total of about 3,069

publicly owned utilities in the United States, this amounts to about

6 percent of all publicly owned utilities. This 175-member estimate

should be treated as a low figure, as it does not include utilities

which were not members of the two associations; nor does it include utilities who did not respond to the checklist.

In the case of the investor-owned utilities, EPRI found that 106

utilities have either proposed and/or implemented innovative rates.

Since there are about 204 investor-owned utilities in the United

States, this amounts to about 52 percent of those utilities. As with

the publicly owned utilities, this should be treated as a low figure.

The number is based on only 123 survey responses–about 60 percent of investor-owned utilities,

lqThis is based on an estimate made by the Ecilson Elecrric lnstltute that there was a total of 97 million ultimate customers of the

entire electric utility industry as of Dec. 31, 1983 (Edison Electric

Institute, Statistic/ Yearbook of the f/ectric Uti/ity /ndustry (Washington, DC: EEI, 1984), p, 58),
148 ● New Electric Power Technologies: Problems and Prospects for the 1990s

Figure 5-10.—An Example of Time. of-Day Rate

7

2

v 9 a m Noon 3 pm 6 pm 9 pm Midnight

Figure 5-11 .—Time-of -Day Rates Shift Patterns of

Electricity Use

V 9 am Noon 3 pm 6 pm 9 pm Midnight

Hour

there were a substantial number of industrial and

commercial customers as well.25

Unfortunately, very little is known about the

precise impact of these rates on electricity supply and demand nationwide. To the extent that

assessments have been made, they typically have

been utility-specific and limited in scope. The

available evidence indicates that utilities have.

in many instances, effectively and economically

managed loads by implementing carefully structured rate programs.26 But this has not always

Z5According to a study by the Rand Corp. (Jan Paul Acton, et al.,

Time-of-Day Electricity Rates for the United States (Santa Monica,

CA: The Rand Corp., November 1983), more than 12,000 commercial and industrial enterprises fell under time-of-day rates (the

major form of time-of-use rates) by the early 1980s.

ZGlbid.

been the case. Rates in some cases have been

developed and implemented which have had little or no impact on demand patterns. This is an

indication of the difficuIty in understanding customer demand patterns and in designing and implementing rates for load management.

Load Control

Utilities have controlled loads in the United

States for about half a century. The earliest efforts in the United States, in the 1930s, involved

the installation by utilities of timers on appliances27 to inhibit appliance operation during preselected periods. But only within the last decade

have utilities seriously considered load control

as a potentially attractive investment.

The 1983 EPRI survey also sought to assess utility activities in load control. *a While, as mentioned earlier, numerous objectives could be

served by load control, the survey found that it

has been viewed primarily as a means of reducing wholesale power costs and has been most

vigorously pursued by utilities which purchase

much of their power from other utilities. By far

the most active in load control are rural distribution cooperatives and municipal utilities. Together they accounted for one-third of the loads

controlled in 1983.

As is the case with innovative rates, the largest

number of customers subject to load control falls

within the residential sector (see table 5-8). Table

5-6 summarizes the load management activity

which was underway among U.S. residences, *g

and provides a rough idea of the number of

points which are available for control. The table

suggests that only a very small portion-perhaps

only a few percent—of the residential appliances

are subject to load control.

Given the large potential in the South (see table 5-6), it is not surprising that in 1983, roughly

Z7Synerglc Resources corp., 1983 Survey of Utiiity End-use

Projects (Palo Alto, CA: Electric Power Research Institute, May 1984),

EPRI EM-3529.

z81 bid.

zgThe table includes only space heating, water heating, and airconditioning. It does not include pool pumps and other controlled

points.
Ch. 5—Conventional Technologies for Electric Utilities in the 1990s ● 149

Table 5-8.— Load Control: Appliances and Sectors

Controlled in 1983 Under Utility ”Sponsored

Load Control Programs

58 percent of the load control points30 nationwide were located there; 37 percent were i n the

North Central region, followed by the West, with

11 percent. The Northeast, though it appears to

have somewhat more controllable points than the

West, accounts for less than 2 percent of the

points currently controlled.

The nationwide impact of the load control

measures in place in 1983 has not been precisely

determined. It can be very roughly estimated,

however. The average peak load reductional reported in the 1983 EPRI survey of 298 utilities was

1 kW for each controlled residential air-conditioner and 0.6 (summer) to 0.9 (winter) kW for

each controlled residential water heater. These

averages should be interpreted with caution; the

results vary widely from one utility to the next,

Since there were 643,910 residential water heaters

and 491,695 residential air-conditioners controlled in 1983, the peak load reduction might

have been roughly 880 MWe in the summer (if

all the water heaters were controlled during the

summer) and 580 MWe (if all the water heaters

were controlled during the winter).

While positive results were observed for many

load control projects, utilities often were not

wholly satisfied with the performance of the load

management technologies they used. In particular, equipment has been relatively unreliable. The

problems resulted from a combination of factors.

To some extent these resulted from inferior products, or other supplier problems; but many also

resulted from the manner in which the technology was used. Most of these problems have been

alleviated over time and appear to be the kind

of passing difficulties which are to be expected

with the application of new configurations of technologies to relatively complex circumstances .32

Potential Peak Load Reductions

From Load Management

The potential peak load reduction from load

management in the 1990s depends on many factors. At the most basic level, the peak load reduction from any load management program depends on: 1 ) the total numbers of customers and

electricity using appliances, 2) the nature of the

appliances and the manner in which they are

—— ...—

JIThe peak load reduction is the magnitude of the additional

power which would have been required to meet demand had the

appliance not been controlled.

JzAnalysis and Control of Energy Systems, Inc., Residential Load

Management Technology Review (Palo Alto, CA: Electric Power

Research Institute, 1985), EPRI EM-3861.
150 . New Electric Power Technologies: Problems and Prospects for the 1990s

used, 3) the extent to which customers participate in the load management effort, and 4) the

peak load reduction achieved for each appliance.

These variables in turn depend on many other

conditions, some of which vary greatly from utility

to utility, and even within the territory of a utility. Only now are methods being developed and

refined for predicting the results of load management programs.33

An accurate, reliable, and detailed estimate of

the nationwide potential of load management requires an effort beyond the scope of this report.

However, strong evidence suggests that there are

many opportunities for increasing the number of

customers and points under load management

programs, It is apparent that though innovative

electricity rates are becoming more common in

the United States, most utility customers do not

yet fall under such rates. Likewise, as table 5-6

suggests, only a tiny fraction of customer loads

are controlled through load control programs,

Evidence suggests that customers in many–

though not a//–instances would be favorably disposed towards both special rates and load control. 34 The precise customer response depends

not only on the character of the customers but

also the nature of the load management effort. 35

Where rates and load control are implemented,

significant peak load reductions may occur. Considerable variation in customer attitudes toward

load management and in the impacts of load

JJsee the following: 1 ) Robert T. Howard, “Estimating Customer

Response to Time-of-Use Rates, ” Workshop Proceedings: Planning

and Assessment of Load Management (Palo Alto, CA: Electric Power

Research Institute, 1984), EPRI EA-3464, pp. 16-3 through 16-4. 2)

T.D. Boyce, “Estimating Customer Response to Direct Load Management and Thermal Energy Storage Programs, ” Workshop

Proceedings: Planning and Assessment of Load Management (Palo

Alto, CA: Electric Power Research Institute, 1984), EPRI EA-3464,

pp. 16-7 through 16-10.

Jdsee: 1 ) Thomas A. Heberlein & Associates, Customer Acceptance of Direct Load Controls: Residential Water Heating and Air

Conditioning (Palo Alto, CA: Electric Power Research Institute,

1981 ), EPRI EA-21 51; 2) Thomas A. Heberlein, “Customer Attitudes

and Acceptance of Load Management, ” Workshop Proceedings:

P/arming and Assessment of Load Management (Palo Alto, CA: Electric Power Research Institute, 1984), EPRI EA-3464, pp. 4-1 through

4-21; and 3) Ebasco Business Consulting Co., /nnovativeRate Design Survey, op. cit., 1985.

Jssee Tom D. Stickels, San Diego Gas & Electric, “Analyzing CUStomer Acceptance of Load Management Programs, ” Workshop

Proceedings: Planning and Assessment of Load Management (Palo

Alto, CA: Electric Power Research Institute, 1984), EPRI EA-3464,

pp. 16-1 through 16-3.

management likely will characterize different utilities across the country.

The management of a relatively small number

of large individual loads, such as those commonly

found in the industrial and commercial sector,

typically will present fewer problems and impose

lower costs than management of a large number

of small loads. A rate structure which encourages

load management may be applied readily and effectively to large users. The deployment by utilities of the technologies required to implement

some of these rates among such users is generally inexpensive relative to the potential gains for

the utility. Moreover, once the economic incentive is offered, the users themselves (industrial and

commercial) frequently are capable of deploying technologies which are effective in changing

their demand in accordance with the utility’s incentives and their own economic interests. 36

Where a large number of small users are involved such as in the residential sector, the

difficulties are more limiting. In 1983, there were

over eight times as many residential customers

in the United States than commercial and industrial customers. And the average residential customer used less than 9 MWh/year, compared

with 1,560 MWh/year by the average industrial

customer and 53 MWh/year by the average commercial customer.

Consequently, special rates tend to be less

readily and profitably applied to the residential

sector, and the cost-benefit ratio for the utility for

each load, managed is likely to be larger. In addition, the cost and difficulty of installing, maintaining and operating the equipment, required

as an adjunct to such rates may be considered

excessive by utilities. Compounding the problems

is the utilities’ uncertainty about future residential electricity use, and the manner in which it

would change under alternative load management programs.

JbFor an assessment of the possible costs and benefits of load management using incentive rates for seven major industries, see: Chem

Systems, Inc., The Potential for Load Management in Selected industries (Palo Alto, CA: Electric Power Research Institute, 1981 ),

EPRI EA-1821-SY.
Ch. 5—Conventiona/ Technologies for E/ectric Utilities in the 1990s ● 151

At present about 1.5 million points are controlled,37 which is only a small fraction of the

number of residential loads that could be controlled (probably less than 1 percent). A much

larger potential exists in every region of the country, particularly in the South where residential

electricity demand is high and there are a large

number of all-electric homes. A recent survey of

the stated intentions of utilities indicates that if

currently planned load control programs are implemented, at least 5 million new points may be

controlled by 1990.38 Another report suggests that

8 million points will be controlled by 1990 and

20 million points by 1995,39 40

The potential magnitude of the impact of load

control is difficuIt to gauge. Evidence from current load management efforts indicates that the

impact couId be quite sizable. If, for example,

one air-conditioner in each of 5 million homes

were controlled, and if an average peak load reduction of 1 kWe were obtained, a peak load reduction of about 5,000 MWe would result. Note

that nearly 50 million homes have air-conditioning and that many of these have more than one

air-conditioner. Also residential air-conditioning

represents only one of many loads which could

be controlled.

Overall, the potential for load management is

such that it is an important strategic option in the

U.S. electricity supply outlook in the 1990s.

Whether utilities fulfill this potential will depend

on the cost, performance, and risk of load management technologies and on the ability of the

utilities to manage those technologies and develop innovative rates.

——.——

~zsynergic Resources Corp., 7983 Survey of LJtillty End-Use

Projects, op. cit., 1984.

’81 bid

JgThe La I rd Durham CO., The United States Market for Res/dentia/ Load Contro/ Equipment, 1983-7995 (San Francisco, CA: Laird

Durham Co., 1984).

‘$OA recent Frost & Sullivan report suggests that 7 mllllOn Points

will be controlled by 1992 (Frost & Sullivan, E/ectric Utility Customer Side Load Management Market (New York: Frost & Sullivan,

1984), as reported in “Load Management Systems Will Control

Seven Million by 1992, ” E/ectric Light& Power, vol. 62, No. 8, August 1984, p. 47).

Technologies for Load Management

Given the magnitude of demand in the residential sector, its importance in contributing to the

fluctuations in demand for electric power, and

the characteristics of individual residential customers, it is not surprising that the technologyrelated problems of current utility efforts to manage loads center on small users. This will also be

the emphasis here. Many of the technologies, issues, and problems in the residential sector, however, also are applicable to the other sectors.

Two principal groups of technologies are required in load management:

1. Advanced meters: Meters measure electricity use; recorders, often integrated into a

single device with the meter, record this information for later use. The data help in developing load management strategies, in implementing them, and in assessing their

results. They also facilitate the application

of rates which encourage the deployment

of customer-owned and operated load management technologies.

2. Load control systems: In order to control

loads, utilities may need to be capable of

communicating with the customer. Communications systems provide this link, allowing

the transmission from the utility to the customer, and perhaps vice versa. Required for

successful load control systems are decisionlogic technologies which interpret information and automatically generate decisions

necessary for effective load management,

Advanced Meters41

The predominant residential electric meter and

recorder used in the United States is the singlephase (see chapter 6 for definition of single phase

and other relevant terms) electromechanical watthour meter which requires periodic reading by

an individual on location. A variety of solid-state

meters, “hybrid meters”42 and other ancillary

~1 strictly Spea king, a meter only measures electrical Power ‘r

energy. Here however, the term IS used loosely to include devices

which not only perform the measuring function, but also record

and perhaps even manipulate the data.

4ZA hybridmeteris one which couples the common meter’s rotating sensing-element to a solid-state m Icroprocessor.

38-743 0 - 85 - 6
152 ● New Electric Power Technologies: Problems and Prospects for the 1990s

equipment (including communications technologies) are available and being developed to assist in meeting the rising information needs of

load management. Among the equipment being

developed is hardware which can be retrofitted

to existing equipment to enhance the capabilities

of common meters.

Advanced meters can perform many more

tasks. For example, they may provide the customer not only with data on current and past use,

but also information on present costs and other

matters; that additional information could be

wholly or partly generated by pre-programmed

equipment on site or transmitted from a remote

location. Where time-of-use rates were being applied as part of a load management program, the

information is essential for the consumer. Alternatively, the meter could provide direct and automatic input to the load control system. For example, a “demand-subscription service” meter

will automatically trigger a sequence of events

designed to curtail load when the meter indicates

that demand has exceeded a specified level.

Currently available advanced meters, however,

often are expensive, unreliable, and short-lived,

relative to conventional meters. Considerable evidence indicates that the technical problems could

be resolved relatively easily, but developers appear reluctant to do so without assurances that

a major market exists. Similarly, costs can only

be reduced sufficiently through mass production

and deployment.

Another consideration is that the conventional

meter is a long-established fixture in U.S. utility

operations. It performs the task expected of it

without imposing inordinately large operating

and maintenance costs. While new meter designs

could in the long run be superior, they would

require changes, People would have to be trained.

Some workers might no longer be needed;

others, with different skills, would be required.

New maintenance facilities likely would be

needed, and operating procedures would have

to be modified to accommodate the new technology.43

43’’ How to Get Meter Readers to Use Computers, ” E/ectrica/

Wodd, vol. 198, No. 10, October 1984, pp. 26-28.

While problems remain, no major unresolvable

technological barriers impede the deployment of

advanced meters. Rather, the problems appear

to be related to the development of an early market among utilities and to the need for changes

in utility practices. The evidence indicates that

unless concerted efforts are made to eliminate

these impediments by stimulating demand, the

deployment of advanced meters will be a slow

process. Their conventional competitors likely

will predominate well past the close of this century, though their position will be eroded slowly

by the newer technologies.

Load Control Systems

Load control systems vary in the extent to

which control is concentrated on either side of

the meter (customer or utility); in the extent to

which information from the customer side-of-themeter is used and in the nature of that information; and in the degree of automation on the customer side-of-the-meter. Some require relatively

active customer participation and a low level of

automation. For example, the utility may simply

call up the customer and ask that his load be reduced as much as possible; the customer could

respond by turning various appliances off, basing his actions on a multitude of considerations.

Other systems, however, may be more automated and are capable of operating with little or

no customer intervention.

Load control systems are classified into three

categories—local, distributed, and direct control—according to the degree to which decisions

are centralized and the extent to which the utility and customer interact before the load is manipulated. In a dlirect control system, the load is

controlled by the utility without any immediate

input in any form from the customer’s side of the

meter (see figure 5-1 2). This in the past has been

the dominant form of load control.

In a loca/ control system, the load is controlled

from the customer’s side of the meter, without

immediate input from the utility (see for example figure 5-1 3). With local control systems,

manipulation of the customer’s load is based

solely on immediate input from only the customer’s side of the meter. Utility involvement is re-
Ch. 5—Conventional Technologies for Electric Uti/ities in the 1990s ● 153

Figure 5-12.—A Direct”Control Load Management Technology: Domestic Water Heater

Service

Central load

Water heater

Meter

drop

control Ier / Receiverlswltch

/

Water heater

Cycling Control

Water heater

controls
154 ● New Electric Power Technologies: Problems and Prospects for the 1990s

Figure 5-13.— A Local-Control Load Management

Technology: Temperature-Activated Switches

Time and temperature

switch

Percentage

timer

Outdoor

temperature

sensor

stricted to indirect inputs such as incentive rates.

Local control devices have been encouraged

where appropriate rates have been instituted. But

their application has been limited in the residential sector, in part because such rates may require

replacement of conventional meters with more

advanced meters.

ity-sponsored load control projects— 1.2 million

points–utilized direct control systems, while

278,000 points were controlled by distributed

control systems, and 10,000 points fell under

utility-sponsored local control programs. Many

more points are locally controlled without the

utilities’ direct sponsorship, but with indirect utility support, usually through direct incentives and

rate structures.44

The key problem encountered in all control systems is the management of loads in a manner

which is satisfactory to the customer yet which

provides an acceptable degree of control and predictability to the utility. The greater the utilities’

direct control, the greater the risk of customer

dissatisfaction. Conversely, systems which give

the utility less direct control over the load—while

perhaps alleviating communications and customer problems—risk reducing the utility’s capacity to effectively manage the load. While direct

control has dominated in the past, utilities are increasingly moving towards distributed and local

centrol.

Discussed below are the two key technological components of load control: “decision-logic”

technologies and central controllers and communications technologies.

Central Controllers and Communications Technologies.– Direct and distributed control systems

use technologies which fall into three categories:

central controllers, transmission systems, and a

receiver/switch at the customer’s end of the system.45 If the system communicates in two directions, a “transponder,” which both receives and

transmits, is required on the customer side of the

meter; and a receiver must be in place on the

utiIity’s side of the meter to receive the information sent from the customer’s transponder.

The controller generates commands which are

encoded and dispatched through some transmission system, and received by the receiver which

translates the encoded message and accordingly

manipuIates the load. While the hardware component of modern computerized controllers is

QQSynergic Resources Corp., 1983 Survey of Utility End-use

Projects, op. cit., 1984.

451 bid.
Ch. 5—Conventional Technologies for Electric Utilities in the 1990s ● 155

.—

Cooling

Peak period

Heating

t

I Indoor temperature

I

01

e

well developed and readily available commer- The communications system–which includes

cially, the software is not. Recent utility experi- the transmission system and the receivers—has

ences indicate that software deficiencies are the been subject of greatest discussion among utilprimary cause of difficulties in the implementa- ity operators. A variety of systems are available

tion of load management programs. Current evi- to choose from:

dence suggests that software-problems are sur-

●

mountable, but that effective software is likely to

require considerable time to develop and refine,

and to some extent must be customized for each ●

ut i I it y.4b

Radio: This is currently the predominant

communication system used for load management.

Power-1ine carrier (PLC) systems: These systems use the utility’s already installed transmission or distribution networks (or both) to

carry the signal.
156 ● New Electric Power Technologies: Problems and Prospects for the 1990s

●

●

●

Telephone: Telephone lines can be used in

several different ways in communicating information to and from the utility.

Cable TV: Using a cable modulator, the utility injects its signals into the cable network.

Receivers are “hard-wired” to the cable at

the customer’s end.

Hybrid communications systems: These systems incorporate two or more of the above

systems in one load control system. This allows incorporation of the best features of

both systems while avoiding some of their

pitfalls.

Each of these communications systems has its

advantages and disadvantages. They differ in the

amount of information which can be communicated over any period of time; the reliability with

which the communication takes place; the extent to which the communication system already

exists; the cost and technical risk associated with

the system; and the ease with which the utility

can deploy and utilize the system in conjunction

with a load management program. It is important to note that the hardware itself is in many

instances fully mature, and involves little technical risk. In some cases, however, technical improvements remain to be made and costs may

still be reduced.

The current debate over communications systems centers around which best serves the needs

of the utility. These needs extend beyond the use

of the communications network for load control,

and touch on their application to remote meterreading, distribution system automation,d’ and

other uses. The needs also extend beyond the

near term in that the utilities seek systems which

are flexible enough to perform a variety of future

tasks.

For example, one choice the utilities have is

between one- and two-way communications systems. One-way systems are sufficient for load

control, but two-way systems allow utilities to

monitor more closely the results of load control

by transmitting information from the customer to

dTDiStribution automation is the remote control of the distribution system which transmits electricity to customers from local substations; such control could offer significant improvements in overall

power system operation.

qesynergic Resources Corp., 1983 Survey of Utility End-Use

Projects, op. cit., 1984.

qqDavid p, Towey and Norman M. Sinel, “An Electric Utility Explores the Use of Modern Communications Technologies, ” Pub-

/ic Uti/ities Fortnight/y, vol. 113, No. 9, April 1984, pp. 23-33.

SOAlan S. Miller and Irving Mintzer, Draft Repofl: Evoking Load

Management Technologies: Some Implications for Utility Planning

and Operations (Washington, DC: World Resources Institute, 1984).
Ch. 5—Conventiona/ Technologies for E/ectric Uti/ities in the 1990s . 157

mated in order to minimize or eliminate the need

for active and routine human involvement on the

customer’s premises. This is done with “local

decision-logic” devices which provide a degree

of “local intelligence. ” A variety of devices may

serve this purpose. These vary in their cost, performance, and uncertainty. Some presently are

available commercially at acceptable levels of

cost and performance. Others must be technically improved, or their costs must be brought

down before they will be deployed at significant

levels. Generally, the major technical problem

is in programming the devices so that they manage loads in ways that are acceptable to the customer while serving the utility’s load management

needs.

Ancillary Technologies Owned or

Controlled by the Customer

In addition to the load management technologies discussed above, there are technologies

which can be installed and operated by the customer to mitigate the potentially adverse effects

of load control (direct, distributed, or local) on

the customer. Among the technologies are two

major possibilities:

1. Ekctric and thermal energy storage: A wide

range of electric as well as thermal energy

storage schemes exist for mitigating the effects of periodic curtailments in electricity

supply. For example, a battery could be installed on the customer’s side of the meter;

the battery wouId be charged when power

is more readily available and the customer

couId draw on it instead of from the grid during peak periods. If a load management program applied to an electric water heater

threatens to leave the customer without sufficient hot water, a larger thermal storage device could be used. This device would be

heated with electricity during off-peak periods. of particuIar importance is ‘‘cool storage” for commercial establishments which

uses electricity during off-peak periods to

cool a medium such as water which then

cools the building during peak periods. 51

51 see: I ) Rc F, Inc., cornmerc;a/ coo/ .$rorage Primer (Palo Alto,

CA: Electrlc Power Research Institute, 1984), EPRI EM-3371. 2) San

2 Energy conservation: Of course, energy

conservation can also be employed as part

of a mitigation program. For example, if curtailing the operation of an electric heater

might result in lower house temperatures,

insulation could be used to lower heat losses

and keep household temperatures at a comfortable level.52

Some of these technologies are inexpensive,

reliable, and present little risk. Others, such as

large batteries systems, are less mature commercially and must overcome a variety of impediments before they could be deployed extensively

(see chapters 4 and 9). Note, too, that the deployment of these technologies in many cases depends heavily on the rate structure or other incentives provided by the utilities.

Major Impediments to

Load Management

Several difficulties must be overcome if load

management is to be extensively implemented

in the 1990s, It is necessary for utilities to develop

a detailed understanding of the manner in which

their customers now use electricity and are likely

to use electricity in the future. To this must be

coupled information regarding the utility’s future

supply of electric power. It also is important for

utilities to identify and understand the many combinations of load management strategies which

can be pursued. Each option must be weighed

and compared not only to other load management options but also to other alternatives such

as conventional generating technologies.

These difficulties are aggravated by the frequent

lack of adequate analytical tools with which to

evaluate load management. The planning and implementation of a load management program requires information and skills that differ from those

needed for building powerplants and other more

Diego Gas & Electric, Therrna/ Energy Storage: /nducernent Program for Commercia/ Space Cooling (San Diego, CA: San Diego

Gas & Electric, 1983). 3) Electric Power Research Institute, Opportunities in 7%erma/ Storage R&D (Palo Alto, CA: Electric Power Research Institute, 1983), EPRI EM-3 159.

~zjerome p. Harper and R, E. Sieber (TVA), “Effects of Electric Utillty

Residential Conservation Programs on Hourly Load Profiles, ” Proceedings of the American Power Conference, vol. 45, 1983, pp.

547-551.
158 ● New Electric Power Technologies: Problems and Prospects for the 1990s

traditional utility planning activities. SJ Moreover,

as will be discussed in chapter 8, systematic analytical tools for comparing load management

strategies with other strategic options are not

widespread.

Even if economic benefits of load management

are calculated to exceed direct costs, utility operators may prefer not to pursue load management.

They may encounter difficulties in reaching agreements to jointly use communications networks

with nonutilities. Access may be limited or prohibitively expensive; legal impediments may be

encountered. 54 Or customers themselves may be

sjEnergy Management Associates, t nc., /SSUeS in Implementing

a Load Management Program for Direct Load Control (Palo Alto,

CA: Electric Power Research Institute, 1983), EPRI EA-2904.

54’’ Justice Department States Cautious on Utility Telecommunications Ventures, ” E/ectric Uti/ity Week, June 18, 1984, p. 7,

reluctant to allow utiIities to control their loads.

While this has not been a widespread problem

so far—given incentives customers to date have

been very receptivess---it is a significant unknown that could potentially impede the deployment of direct and distributed load control technologies.57

—...—

SsAnge[ Economic Repofis and Heberlein-Baumga rtner Research

Services, Customer Attitudes and Response to Load Management

(Palo Alto, CA: Electric Power Research Institute, 1984), RDS 95.

SbThomas A. Heberlein & Associates, Customer Acceptance of

Direct Load Controls: Residential Water Heating and Air Conditioning, op. cit., 1981.

5TAla n S, Miller and Irving Mi ntzer, Draft Report: Evolving Load

Management Technologies: Some Implications for Utijity Planning

and Operations, op. cit., 1984.
Chapter 6

The Impact of Dispersed

Generation Technologies on

Utility System Operations

and Planning
CONTENTS

Page

Introduction. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..............161

Interconnection of Dispersed Generating Sources. . . . . . . . . . ..............,161

Overview . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ...............161

Current Industry Issues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. ..,162

Interconnection Performance. . . . . . . . . . . . . . . . . . . . . . . ...................165

overview . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .,165

Protection and Control Subsystems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ....165

Distribution System and DSG Device Protection Problem Areas . ............167

Power Conditioning. . . , ... . ........ .

Metering . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Interconnection Costs. . . . . . . . . . . . . . . . . . . . . . . . . .

Utility interconnection Standards . . . . . . . . . . . . . . . .

Utility System Planning and Operating Issues . . . . . .

Overview . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Electric System Planning ..., . . . . . . . . . . . . . . . . . .

Electric Power Systems Operations . . . . . . . . . . . . .

List of Figures

Figure No.

6-1. Layout of of an Electric Power System . . . . . . . . . .

6-2. Distribution System and DSG Device Protection

6-3. Costs for Interconnection of Qualifying Facilities
Chapter 6

The Impact of Dispersed Generation

Technologies on Utility System

Operations and Planning

INTRODUCTION

As the penetration of dispersed generating

sources increases in U,S. electric power systems,

the implications for system planning, operation,

performance, and reliability are receiving increased attention by the industry. I The interest

in dispersed generating technologies has been

stimuIated by new Federal laws that have increased the economic attractiveness of such systems. As discussed in chapter 3, the Public Utility Regulatory Policies Act of 1978 (PURPA)

opened the way for customer-owned generation

mandating interconnection with existing electric

systems.

The characteristics of many alternative generating technologies pose both potential benefits

and problems for electric system planning and

operation. The benefits of dispersed generation

generally stem from the potential of substituting

plentiful, environmentally acceptable and renewable sources of energy for conventional fuels.

Due to the modularity of many of these alternative technologies, deployment on an incremental

basis is possible, offering the potential for a more

economic expansion of the generation supply.

(Other benefits are discussed in chapter 3.)

The nonconventional aspects of dispersed

sources of generation concern electric utilities

largely because of the industry’s lack of knowledge regarding performance of these systems.

There is concern, for example, about the lack of

utility control over generating resources. in addition, where alternative generation supplies are

weather dependent, production is intermittent.

Similarly, many cogeneration supplies are highly

dependent on the process to which they are

linked. Finally, increasing production at the distribution level poses new questions regarding

reliability because the delivery system is less reliable at the distribution level than at the transmission or bulk level, i.e. a kilowatt of production

at the distribution level is less reliable than one

generated at the bulk level.

INTERCONNECTION OF DISPERSED GENERATING SOURCES

Overview

The concept of a dispersed source of generation (DSG) has a variety of meanings, often resulting in some confusion. In this document, a

DSG is any generating device (irrespective of size)

that introduces power into an electric delivery

system, but not at the bulk power level or at the

traditional point where a particular utility’s conventional generation injects power. By and large,

this means electric power production linked to

the distribution system of the utility, such as most

non utility power producers that are qualifying facilities (QFs) under PURPA.

While present day electric systems have been

structured (in capacity, protection, and configuration) to allow safe and reliable operation without the presence of a DSG device, most researchers agree that with proper modification of the

161
162 . New Electric Power Technologies: Problems and Prospects for the 1990s

electric network configuration and operation

practice, a DSG device can be compatible with

the electric system.

Current Industry Issues

Traditionally, utilities and the agencies that regulate them have primarily been concerned with

power flows in electric systems in one direction:2

either from utility-owned central station powerplants to customers through the transmission and

distribution network, or from one utility to

another. More recently, however, the incentives

offered under PURPA and other Federal and State

laws have promoted addition to the electric grid

of DSGs which are often nondispatchable and

predominantly nonutility-owned. Management of

these “two-way” power flows has introduced a

new element of complexity into the operation of

electric utilities. As a result, utilities and DSG customers have begun to focus some attention on

the nature, quality, and cost of the interconnection equipment, and regulators have begun to examine their role in managing the integration of

DSGs into the utility grid.

The issues associated with interconnection

have their roots in the way power is generated

and transmitted through the utility grid. A typical grid (shown in figure 6-1) is composed of several large central generating plants, connected

to bulk power transmission lines. These lines typically are maintained at the highest voltages in the

grid. Power is then transported through a network

of transformers and lower voltage lines until it

reaches the customer. Depending on the type of

end use, an industrial customer with large process needs may connect directly to primary distribution circuits, while most residential customers connect to secondary distribution circuits at

lower voltages.

In addition to power lines and transformers, the

grid also includes protection equipment such as

circuit breakers, relays, and switches as well as

control equipment such as voltage regulators,

capacitors, and tap-changing transformers. In

powerplants, control of turbine, frequency, and

excitation systems is performed. While, a central

Figure 6-1 .—Layout of an Electric Power System

——— — — —.———— — — ——— ———— ——————————— ————

I

I

I

I

I

I

I

I

I

I

I

I

I

I

I

Generating

statio n

Substatio n

I I

Distribution

lines to

customers
Ch. 6—The /mpact of Dispersed Generation Technologies on Uti/ity System Operations and Planning ● 163

control center manages, dispatches, and directs

the overall operation of the electric grid. Power

requirements of the system vary, depending on

the time of day and season because the demand

for power is changing over time. The protection

equipment is used to prevent damage to the grid

and its customers from abnormal circumstances

or faults and to maintain a highly reliable and dependable supply of electricity. The control equipment provides a high quality of electric power

and determines the system’s performance standards under normal operation.

Utility customers expect electric power to meet

quality and performance standards so that appliances, lights, and motors will operate efficiently

and not be damaged under normal conditions.

While there is no general agreement among utilities as to the definition of “acceptable” power

quality, typically a utility supplies ac power at

120/240 volts (single-phase3

) for residential and

240/480 volts or higher (three-phase) for industrial customers (with the voltage ranging between

95 to 106 percent). The frequency of the delivered power is 60 Hz ( *0.002 Hz).

The types of generating devices used in a DSG

can significantly influence its impact on the electric system. The generating equipment can be of

many varieties; table 6-1 categorizes different

generating types. Rotating machines (most traditional generating equipment) produce ac voltage

%ee box 6A for defl n It Ions of Interconnection terms.

Table 6-1 .—Classification of Dispersed

Generating Types

Line independent:

● Synchronous generator

● Forced-commutated converter

● Double output induction with a forced-commutated

converter

. DC source with a forced-commutated converter

. Permanent magnet reach ine

● Field-modulated generators

Line dependent:

● Induction generator

. Line-commutated inverter

● Double output induction with a line-commutated

converter

● DC source with a Iine-commutated converter

● AC commutator generator

SOURCE Office of Technology Assessment

as either synchronous or induction generators

(see box 6A for definitions), while inverters,

through the use of power conditioning equipment, change the current from DC sources (such

as a photovoltaic array) into AC current. Inverters

may be either Ii ne-commutated or self-commutated, i.e., either dependent on the utility’s voltage and frequency power signal or independent

of the utility line.

Both induction generators and line-commutated inverters consume reactive power (see box

6A for the definition of reactive power) in normal operation and, therefore, one issue for these

types of nonutility-owned DSGs is how to compensate for or charge costs of the reactive power

consumed. Usually, synchronous generators and

self-commutated inverters do not consume any

reactive power, i.e., they produce their own, and

can operate independently of the utility.

The power conditioning equipment used by inverters produces harmonic frequencies of 60 Hz

in the voltage and current signals in the grid.

These harmonics, which appear at frequencies

that are multiples of 60 Hz, combine to form a

complex waveform. The resulting levels of socalled total harmonic distortion (THD) can lead

to deterioration in customer appliances and motors. The presence of harmonics can shorten the

life of electrical devices by 5 to 32 percent

through thermal aging.4

Since harmonic voltages affect loads, it is important to understand how they are generated

at various parts of the electrical network. Many

systems inject current harmonics into the network; these current harmonics are conducted in

the various lines and transformers and into the

loads, inducing harmonic voltages within the

electric system. The location and amplitude of

these induced harmonic voltages are largely cletermined by the electrical parameters of the network. The point of injection and the amplitude

of current harmonics, however, are not likely to

determine the potential impacts; rather problems

and their location are determined by network

characteristics where harmonic voltages are in4E

, Fuchs, U n iversit y of Colorado, /rnpacf ot’ Harmonics on Home

App/lances, draft contractor report to the U.S. Department of

Energy, June 1982, DOE-RA-50150-9.
164 . New Electric Power Technologies: Problems and Prospects for the 1990s

duced. As a consequence, harmonic voltage problems typically will result in a location remote from

the point of injections

While there seems to be no general agreement

concerning the precise acceptable level of distortion, typically utilities limit THD at the point

of injection to less than 5 percent of the current

signal with any single harmonic less than 3 percent, and 2 percent of the voltage signal with any

single harmonic less than 1 percent. Filtering out

this distortion may be expensive for smaller sized

DSGs. Therefore, another issue that has surfaced

is whether or not all interconnected harmonic

sources should be required to meet specified

THD standards, or whether these standards

should vary according to DSG size and type.

In addition to power quality issues, utilities

are concerned with the proper measurement of

net power generated by DSG customers. Should

all DSG customers be required, and therefore

charged, for extra metering equipment? Utilities

are also concerned with the liability of DSG customers for utility employee accidents or equip- . , s

5“Computer Simulation Study, ” ORNL/SUB/81-9501 1/1, Oak ment damage that may result from improper in -

Ridge National Laboratory, Oak Ridge, TN, August 1983. terconnection.
Ch. 6—The Impact of Dispersed Generation Technologies on Utility System Operations and Planning • 165

As larger proportions of DSGs are installed

across the country, another concern is the effect

of DSG operation on system dispatching, control,

short-term transmission and distribution (T&D)

operations, and long-term, central-station capacity planning. b As more utilities gain experience

with interconnecting customers, guidelines for interconnection are evolving. Efforts are underway

to standardize these guidelines (discussed later).

in general, most researchers agree that the

technical aspects of interconnection and integra6H. Chestnut, et al., “Monltorlng and Control Requirements for

Dispersed Storage anci Generation, ‘‘ lnst/tute oi Electrical and EIcctrorrlc 5 Engineers (IEEE) Tran+?ct/on~ on Power ,A[]paratuq and Sy~-

terns, vol, PAS-101, J u Iy 1982, pp. 2355-2363; In 1984 the Electric

Power Research Institute Initiated a major tleld study on the lmp~ct ot’ DSG\ on power system operation; see “I ntegratlon ot Disperwd Storage ~nd Generation Into Power System Control DurI ng Norma I System oper~tlon~, EPRI RFP 2.? 36-1

tion with the grid seem to be relatively well understood; they are discussed in an earlier OTA

report. ’ The primary unresolved issue is determining appropriate cost-effective interconnection

requirements, i.e., how to balance the utilities’

technical risks with interconnection against the

non utility power producers’ desire to keep frontend costs of interconnection down. The resolution of this issue will depend on the costs of

interconnection equipment, the requirements

associated with the utilities’ legal obligation to

interconnect, and the availability of new hardware and operating practices for DSGs to lower

interconnection costs.

7U. S. Congress, Office of Technology Assessment, /ndu\?rla/ a nci

Cornrnercia/ Cogeneration (Washington, DC: U ,S. Go\ ernment

Pnntlng Office February 1983), OTA-E-192.

INTERCONNECTION PERFORMANCE

Overview

Interconnection equipment generally consists

of four major functional subsystems: 1 ) a protection and contro/ subsystem for monitoring DSG

power quality and disconnecting the DSG from

the grid in case of abnormal conditions on the

grid or in the generator itself; 2) a power conditioning subsystem PCS) for converting DC to AC

if necessary); 3) a metering subsystem for measuring: a) power flowing from and to the customer,

and b) perhaps time of day; and 4) other hardware associated with various types of electrical

converters chosen for the DSG. Synch ionization

equipment is required with many rotary converters;

capacitors, power factor correction, transformers,

and other equipment can also be required. Each

DSG technology may require a somewhat different configuration of subsystems, with the precise

configuration depending on current ~tility guidelines, existing distribution equipment, the type

of DSG customer, and other factors,

For example, induction machines and linecommutated inverters may continue to operate

after being disconnected from the utility grid, presenting a potential safety problem. Even though

these types of equipment require some kind of

external power supply to provide reactive current, there may be sufficient reactive power available in that part of the distribution grid near the

point of interconnection. This could occur when

a utility installs extra capacitors to compensate

for the reactive power drain of the DSG. This type

of equ ipment may need extra protective devices

to prevent problems associated with unscheduled

operation.

Another example is conventional cogeneration

equipment. While not requiring extensive investment in power conditioning equipment (these

systems typically produce ac power), a conventional cogeneration system requires additional

hardware such as: 1 ) a synchronizer to match its

frequency and phase with that of the grid and

2) a transformer for isolation and voltage match.

Most inverters have synchronization logic included in the PCS.

Protection and Control Subsystems

Perhaps the most heated debate concerning

utility interconnection equipment has centered

around the use of protective devices for each

DSG configuration. Typically, these devices are:

1 ) relays designed to detect over- and under-
166 . New Electric Power Technologies: Problems and Prospects for the 1990s

current, over- and under-voltage, and over- and

under-frequency of the power produced from the

DSG; and 2) filters to eliminate excessive harmonics and electromagnetic interference. A major issue is the setting of these relays to provide

an appropriate level of protection, yet avoid “nuisance tripping” of the DSG off-line whenever system power quality conditions vary over the normal course of the day. Of related concern are the

cost implications of the tolerance range—the

costs for more sensitive protection equipment are

higher. These issues are discussed later.

Protection philosophy covers both the normal

and abnormal operating conditions of the electric system. The problem of protecting the electric system involves protection of the distribution

system, loads, and other customers as well as protection of the DSG.8 The most concern arises during abnormal operation when potential damage

to the electric system, its customers, and the DSG

couid occur. The overall protection philosophy

and problems are presented in figure 6-2.

6D.T. Rizy, Personnel Safety Requirements for Electric Distribution Systems With Dispersed Storage and Generation (Oak Ridge,

TN: Oak Ridge National Laboratory, November 1982), ORNL/

TM-8455.

Figure 6-2.— Distribution System and DSG Device Protection Problem Areas
Ch. 6—The Impact of Dispersed Generation Technologies on Utility System Operations and Planning . 167

DISTRIBUTION SYSTEM AND

PROBLEM

Potential safety problems for electric utility personnel are also of concern to the electric utility

industry. Attention is focused on the adequacy

of present maintenance practices and hardware

to ensure a safe working environment. Work procedures 9 have been developed for both energized (live line) and de-energized (dead line)

maintenance practices.

For de-energized line work, there are six basic

safety steps: notification, certification, switching,

tagging, testing, and grounding. When work is

performed on energized systems, insulating devices such as rubber gloves and mats, insulating

stools and platforms, and/or insulated tools such

as hotsticks are used by utility personnel. Guidelines of the Occupational Safety and Health Administration (OSHA) require that utility personnel

may not approach or take a conductive object

without suitable insulation. The addition of a DSG

device has the potential of converting a dead line

to a live line without knowledge of the maintenance person. The easiest way to prevent this situation is to either place a manual disconnect at

the DSG or use live line maintenance practices

where DSGs are present.

Power Conditioning

For wind and photovoltaic generators, the PCS

is perhaps the most crucial link in the interconnection apparatus. Early PCS and many low cost

systems consisted of inverters which often

produced many harmonics and operated at low

conversion efficiencies. However, recently there

have been a number of important advances in

development of PCS technologies. These new

technologies use a method called high-frequency

modulation (H FM) to chop the dc output into the

sine wave pattern of ac power, using solid-state

switching devices.10 Such equipment generally

‘D,T, Rizy, et al., (lperdt;onal and Design Considerations for E/ectrvc Dlstrfbutlon Systems With D\spersed Storage and Generation

(DSG) (Oak Ridge, TN: Oak Ridge National Laboratory, September 1984), ORNL/CON-l 34.

‘“J. Ste\fens and and T. Key, Draft Report: The Utility lntertace–

Can State-of-the-Art f%t~er Cond\t\oners A//e\iate Our Concerns

(Albuquerque, NM: Sandla National Laboratories, 1984),

DSG DEVICE PROTECTION

AREAS

produces fewer harmonics; has higher efficiencies and power factors; increased fault and reclosing detection; and improved voltage regu Iation

compared to earlier, line-commutated designs. 11

Working with utilities, private PCS manufacturers and government researchers at Sandia

Laboratory have developed and improved upon

residential-sized ( <20 kW) “advanced-design”

PCS. A prototype Sandia-designed HFM-PCS performed well in utility simulator tests.12 Further research is underway at several utilities, such as at

Georgia Power (see box 6B). Most engineers

agree that the H FM-PC has superior performance

compared to earlier line-commutated inverters

in terms of power quality. For example, current

HFM devices in production (for 2 to 4 kW generators) produce harmonics similar to those of hair

blowdryers, and have power factors between

0.97 and 1.00. The new equipment has fast and

reliable reclosing and fau It detection capabilities,

accomplished through electronic sensing and

control. I n the case where a fau It (e. g., precipitated by a thunderstorm) disconnects the PCS

from a utility, logic and control circuits turn off

the PCS, thus preventing any danger to the utility and any reconnection of the DSG if the utility quickly returns on-line. 1s
168 • New Electric Power Technologies: Problems and Prospects for the 1990s

cation, July/August 1984’ and R.S. Das, et al., “Utility-Interactive

Photovoltaic Power Conditioners: Effects of Transformerless Design

and DC Inject ion,” paper presented at Intersociety Energy Conversion Engineering Conference, No. 849413, August 1984.

This increased PC performance, however, comes

at a premium price. If HFM devices were required

by utilities, the increase in price would burden the

smallest generating customer. (See figure 6-3 in next

section for cost comparisons of different sized interconnection equipment.) One suggested alternative

is to institute varying requirements for different sizes

and types of generators. Utilities have begun to use

this idea in their own guidelines for interconnection (as discussed in the next section) by having

different sections of the guidelines apply toward a

particular size of generator.

Some utilities are still concerned about the socalled “pollution” of their power systems, while

others consider this concern as overly restrictive.

Some researchers believe that if non-DSG customers cannot distinguish differences in power quality, the utility should not penalize DSG customers

with overly stringent and costly requirements.14 This

would shift the issue of “how high a power quality

is appropriate” to the question “what are customers willing to pay to receive higher power quality?”

These issues are being debated in the technical

community.

Metering

The third and last component of interconnection is the metering equipment used to measure

power consumed by the customer. In general,

the three types of meters available today are the

single watt-hour, double watt-hour with rachets,

and advanced meters.15 The single watt-hour meter is in common use in most homes and costs

about $30 (1 984$). If a DSG is producing power,

the meter simply runs backward. This configuration only measures net power use and assumes

that there is no difference between the utility’s

retail rates and its rate for purchasing power from

DSGs. If these rates are different, which is usually the case, then two meters are routinely used,

one of which runs in the reverse direction to

measure power produced; both meters have

rachets that prevent any reverse rotation. Another

configuration uses more advanced meters to

I qMartin Schlect, General Electric Co., personal Commun icatlon,

jU& 1984.

I SDiscussed in more detail in C)TA, /ndustria/ and COmmefc;a/

Cogeneratior?, op. cit., 1983.
Ch. 6—The Impact of Dispersed Generation Technologies on Utility System Operations and Planning • 169

measure such quantities as power factor, energy,

and time of use.

One metering issue is the incremental expense

of additional metering for DSG customers: should

the DSG customer be required to purchase meters that a non-DSG customer is not required to

have? For example, Wisconsin Power & Light

does not require those customers who did not

previously use time-of-day meters to install them

when interconnecting their DSGS.

16 Another

.—. - —.. .—

I ~wl~Con$l n Power & Light Co., “Various Gudellnes for Parallel

Generation, Madison WI, September 1983; and B. Bauman and

D. Flmreite, ‘‘ P~rallel Generation In Southern ~~’lsconsln, ’ paper

presented at the Summer ,Meetln8 of the American Society of Agricultural Engineers, No. 80-3041, June 1980.

metering issue centers around when and how

DSGs should be charged for consuming reactive

power.

Summary

The current evidence suggests that the technical issues of interconnection can be resolved and

that state-of-the-art power conditioners can alleviate many utiIity concerns about the quality of interconnection subsystems. Advances in automation in electric systems will tend to mitigate many

problems associated with DSGS. ’7

17D T Rlzy et al,,oper<]tl~nai and De$lgn Considerations fOr Elec-

,,

trlc Distrlhutjon Systenl~ with Dlsi]erwd Storage and Generation

(DSG), 1984.

INTERCONNECTION COSTS

Figure 6-3 shows the range of costs for both induction and synchronous DSGs, based on typicaI configurations for seven generator sizes and

I HFor ex,l mple, Jan ICe H a m rl n (Executive Director, Independent

Power Prociucers Asjoclatlon) inculcates that Paclflc Gas & Electric

opened Its blddfng IIrocess for tnterconnecllon equipment In mid1984 and this has tended to drive down the costs of interconnec--

tlon (OTA Electric Utility Advisory Panel, August 1984).

‘“t{, Geller, Selt-Rellance, Inc., ’ ‘The Interconnectmn of Cogenerdto r~ and 5ma I I Pom e r Prod ucers to a Utl I it y System, cent ractor

report to the Dlstrlct of Columbla Off Ice of the People’s Counsel,

wa5hlngton, DC, February 1982; T S. Key, “Power Conditioning

tor Grid-Connected PV Systems Less Than 250 kW, ” paper presented dt I ntersoclety Energy Con\ fersion Engi neerl ng Conference,

No. 849407, August 1984; P, Wood, “Central Station Advanced

Power Condltlonlng Technology, Utility Interface, and Performance ‘‘paper presented at Intersociety Energy Conversion Engineering Conference, No. 849411, August 1984; D. CurtIce and j, B. Patton, Systems Control Inc., /nterconnectlng DL” Energy Systems:

Re~ponw+ to Technlca/ /wue$, contractor report (Palo Alto, CA:

Electrlc Power Research I nst}tute, June 1983), EPRI AP)EM-31 24,

x)( )TA, /ndu Strlll/ and Cornmercla/ Cogeneratlon, OP. Clt. ~ 1983.

Fiaure 6.3.—Costs for Interconnection of

Qualifying Facilities

600

500

400

200

100

0

5 50 100 1,000

Capacity in kilowatts

SOURCE’ Office of Technology Assessment
170 ● New Electric Power Technologies: Problems and Prospects for the 1990s

two levels of protection, using manufacturers information and price catalogs currently available.

For the higher level of protection, additional interconnection equipment is used, such as dedicated transformers, more expensive “utility

grade” (see box 6A) relays, and more protection

devices.

interconnection costs include engineering labor and the equipment cost of switchgear, power

transformers, instrument transformers. For installations under 50 kW, these costs can be prohibitive when using utility-grade equipment and

providing the typical level of protection for generating equipment. (Many of the details of interconnecting DSGs have been tabulated elsewhere. 21) These costs are still much higher than

the Department of Energy’s (DOE) suggested

price of $200 to $300/kW for “economical”

interconnection equipment for residential generators.22 While future technological advances such

as microprocessor controls, less costly nonmetallic construction, and integration of different components could bring prices down, “the major cost

z I D T, RIZY, protection drl~ Safety Requirements for Electric Distribution Systems With Dispersed Storage and Generation (DSG)

(Oak Ridge, TN; Oak Ridge National Laboratory, August 1984),

ORNL/CON-l 43.

Zzstevens and Key, op. cit., 1984.

decrease is expected to come from volume production” of interconnection equipment.23

For systems using inverters, perhaps the most

costly component for interconnection is the

power conditioning subsystem (PCS). In 1981,

Sandia Laboratories asked four potential PCS

manufacturers to estimate their selling price for

these units, assuming they would be sold in quantity lots of 1,000. The prices ranged from $109

to $254/kW for 100 kW-sized units. Since receiving these estimates, Sandia reports that the cost

of solid-state power devices has fallen dramatically and predicts that prices will drop substantially in the future.24

Interconnection costs have continued to decline during the past 5 years. However, the cost

of interconnection for smaller units remains a

high proportion of the cost of the generation

equipment ($600/kW). The cost for intercon nection for larger units is about 5 to 10 percent of

the capital cost of these units.

23T. S. Key, “Power Conditioning for Grid-Connected PV Systems

Less Than 250 kW, ’’op. cit., 1984.

Z4D. Chu and T.S. Key, “Assessment of Power Conditioning for

Photovoltaic Central Power Stations, ’’paper presented at IEEE Photovoltaic Specialist Conference, May 1984.

UTILITY INTERCONNECTION STANDARDS

In the first years since the enactment of PURPA,

few utilities had any published guidelines dealing with interconnection requirements. In 1983,

OTA reported that most interconnection configurations were custom-fitted and no general patterns for utility standards had emerged.zs Since

1983, the number of applications from dispersed

generating customers to interconnect to utilities

has increased. As a result, more utilities have

standardized their interconnection requirements

in the form of published guidelines. The guidelines, approved by the Public Service Commission, usually require data and drawings on the

type of generator and PC equipment as well as

anticipated customer loads.

25(3TA, /ndu5tria/ and Commercial Cogeneration, op. cit. t 1983.

It is important that such requirements be sensitive to the needs of both the utility and DSG customers. The customer should know exactly what

equipment is necessary so that costs can be predicted with some certainty, and the utility should

be able to reduce design review approval time

and costs so that its power quality and operations

can be maintained. Knowing probable interconnection costs ahead of time may be as important

as the actual cost itself. zb

interconnection guidelines should also stimulate the exchange of information between the

utility and the DSG customer. Ideally, the DSG

ZGF.V. strnisa, et al., New York State Energy Research dnd Development Administration, “Interconnection Requirements in New

York State, ’’paper presented at Tenth Energy Technology Conference, Washington, DC, 1983.
Ch. 6—The Impact of Dispersed Generation Technologies on Utility System Operations and Planning • 171

customer shouId have access to necessary information regarding technical characteristics of the

utility system’s power circuits, such as relay tolerance settings, the short circuit capacity at the

point of interconnection, and the speed and operation of reclosers after detecting faults.

Utilities currently use two different philosophies

in preparing guidelines: they either prescribe

functional performance requirements that must

be met by the interconnection equipment, or

nonfunctional, equipment-specific requirements.

For example, a utility might require equipment

to detect when the DSG generates power with

a frequency outside a certain range (a functional

requirement) or require specifically an underfrequency relay (technology-specific).

While a combined approach may be used by

a utility in preparing its guidelines, research to

date suggests that performance-based standards

appear preferable since they allow cogenerators

to meet functional criteria rather than requiring

them to install particular types of equipment that

might later be found unnecessary. New interconnection equipment is being introduced continually with better performance and reduced cost.

Perhaps in response to the fast pace of technological change and improvements in the dispersed

generation industry, many utilities are instituting

function-based interconnection guidelines.

Typically, utilities have different requirement s

for different sized DSGs, with fewer and less stringent protective functions for the smaller generators. While the precise definition of “smaller”

versus “larger” is not agreed upon by all utilities, usually, generators less than 20 kW are considered small DSGs and have fewer functional requirements imposed on them than generators

larger than 100 kW. The rationale behind this

scaling is, as mentioned earlier, to relate the level

of protection and cost of the interconnection

equipment to the size of the generator. In spite

of this, the per-kilowatt cost of even the least stringent interconnection requirements is much higher

for smaller generators (see figure 6-3.)

There are other variations in the exact requirements specified by utility guidelines (see box 6C).

Even within a particular State, such as New York,

requirements differ among utilities for particuIar

kinds of equipment, compliance with specific

electrical codes, etc.27 (see table 6-2 and box 6D).

In addition to these changes, there are the ongoing efforts by standard-setting committees of

the Institute of Electrical and Electronics Engineers

(IEEE) and the National Electric Code (NEC) as

well as research sponsored by DOE, and the Electric Power Research Institute (EPRI) to develop

national “model” guidelines. While all of these

organizations have published draft standards or

suggestions for model guidelines, none has as yet

released final versions.28One of the more influential of such efforts is the preparation of revisions

to the NEC. Working groups meet periodically

to suggest revisions, and the overall committee

publishes the consensus every 3 years, with the

next revision planned for 1987. Once the revisions are published, they are usually circulated

to all local city, county, and other municipal bodies, which then incorporate the changes into their

own local building and inspection codes. This

process of incorporation, however, may take a

decade or longer.

The delays inherent in this process work against

the fast-changing nature of interconnection technology. Even with the adoption of NEC or other

national standards, utilities are reluctant to accept equipment which is unknown to their own

experience, even if it is in wide use in some other

utility’s service territory. For example, New York

State Electric & Gas requires that interconnection

equipment meet American National Standards institute standard C37.90 (for power quality) but

stipulates the utility must have already tested the

equipment, surveyed users by telephone, and

collected successful performance histories i n

other utilities .29

Another example is the requirement that DSG

customers use “utility-grade” relays, which cost

.?71bi~,

2’%. Chalmers, “Status Report of Standards Development tor

Photovoltalc Systems Utillty Interface, ’’paper presented at lntersociety Energy Conversion Engineering Conference, No. 849406,

August 1984; IEEE Standards Coordinating Committee for Photovol-

(aIcs, “Terrestrial Photovoltaic System Utillty Interface for Rcwdentlal

and Intermediate Appllcatlons, ” Standard 929 (Draft), November

1983; and D, CurtIce and J. B. Patton, /rtterconnectirrg DC Energy

Systems: Responses to Technica/ /ssues, op. cit., 1983 .

29F.V. Strnlsa, et al,, “InterconnectIon Requirements In New York

State, ” op. cit., 1983,
172 ● New Electric Power Technologies: Problems and Prospects for the 1990s

more and have supposedly better reliability than

ordinary commercial-grade relays. There is no

general agreement as to what relays are of which

grade. For example, Central Hudson Electric &

Gas defines relays as “utility-grade” if the utility

has had experience with it and can predict its performance. 30 As yet, however, no utility has published any assessments linking reliability with the

level of equipment grade. Thus, the requirement

of and definition of “utility-grade” equipment

may be largely attributed to general utility conservatism towards equipment performance, rather

than towards specific groups of interconnection

apparatus.

Equipment grade stipulations can present an

awkward situation for DSG customers wishing to

interconnect. For example, a utility refuses to approve an interconnection unless the eauipment

Wbid. has undergone prior safety inspection’, yet the
Ch. 6—The Impact of Dispersed Generation Technologies on Utility System Operations and Planning ● 1 7 3

Table 6.2.—New York Utility

Interconnection Requirements

al (Albany, NY New York State Energy Research and Development

Authority, March 1984)

safety inspectors have refused to approve the installation of interconnection equipment unles s

they have prior utility consent. An example of this

dilemma is the case of a wind generator control

panel, which several utilities insist must have

Underwriter’s Laboratories (UL) approval. UL,

however, does not test assembled control panels,

although they do test the components used in the

panels. Such subtleties can create significant delays in granting interconnection approval, increase the cost both to the utility and the customer, In such instances, some experts argue that:

the burden of proof for refusing to accept

a “relay that has passed the standard tests [should]

be placed on the utilities. [The utility should eiConEd’s interconnection guidelines delineate

the precise responsibility of the potential DSG

customer in obtaining an interconnection, the

engineering considerations, and the data that the

customer must supply to Con Ed with the application. Some DSG applicants claim that these

guidelines are too stringent for any economical

interconnection, while the utility counters these

criticisms by saying that the cost for interconnection is higher due to the network configuration

of its transmission and distribution (T&D) system

within Manhattan, and that the detailed guidelines are necessary for the proper operation of

its T&D system.

ConEd argues that Manhattan network has a

different topology from that of other utilities

around the country. Rather than a radial, huband-spoke type of pattern (as shown in figure 6-

1), the Manhattan-network is a criss-cross grid

with many intersecting nodes between dktribution lines. In a radial system each customer has

one centralized source of electricity supply, and

if that source goes out of service, the customer

is without power. In the network system, each

customer has multiple sources of centralized

supply. At many places in ConEd’s Manhattan

network certain types of protective devices are

placed to allow power to flow from source to

customer and not in the reverse direction. Because of this, if DSGs were placed at the customer site, power could not be fed back into the

grid and a critical benefit, that of sales of power

back to the utility, would not be possible.

SOURCE: Roch Cappelli, Consolidated Edison Co., personal communication, August 19B4; and Bill Wagers, Consolidated

Edison Co., personal communication, May and August

1984.
174 ● New Electric Power Technologies: Problems and Prospects for the 1990s

ther be required to] show negative operating system experience, or they must develop a testing

program . . . rapidly and systematically. . . . If

one utility tests relays and finds them acceptable

the results should [constitute compelling evidence for other utilities].3T

ences in individual utility’s guidelines, and the

lack of model national standards, DSG customers are likely to face a confusing array of interconnection guidelines well into the next decade.

The extreme diversity among utility guidelines

may also make it difficult to produce high volumes of standardized equipment and to achieve

accompanying economies of scale. All of these

factors may slow the deployment of DSGs.

UTILITY SYSTEM PLANNING AND OPERATING ISSUES

Overview

The process of planning and operating an electric utility system is a very complex one. P/arming

focuses on the selection of technology requirements (generation, transmission, and distribution)

to satisfy predicted demand by the most financially attractive means. Operations management

refers to the day-to-day, hour-to-hour, and

second-to-second deployment of existing facilities

to meet the demand on the electric system. Both

processes have an overriding goal: to provide the

production and delivery capabilities to meet electricity demand in a safe, reliable, and economic

manner.

The addition of DSGs to the utility network

complicates both planning and operations. In the

short-term, if utility system controllers do not correctly anticipate load changes, network elements

(transformer, lines, generators, etc.) may become

overloaded and circuit breakers may open, possibly causing power reductions or interruptions

for customers. In the medium-term, insufficient

transmission and distribution capacity may cause

poor quality of service. And over the long term,

if utility planners underestimate or overestimate

future demands, the utility may be placed in financial jeopardy by having to purchase power

from its neighbors at high rates (for underbuilding) or by having too much idle capacity (for overbuilding). This section discusses the effect of increasing DSG capacity on utility operations and

planning.

Electric System Planning

Good planning of electric systems is the key

to controlling costs since the timing and type of

additions will likely determine overall costs. There

are two components in the electric supply cost

equation: fixed or capital costs, and variable

costs, e.g., fuel, operation, and maintenance. Although the overall cost tends to be dominated

by generation costs, on the order 60 to 65 percent, transmission and distribution costs can not

be ignored. The greatest impact of DSGs is likely

to be on the distribution system itself.

Determining DSG’s impact on the overall electric system involves: 1 ) estimating the performance of the DSG, 2) establishing the relationship

between system load and DSG performance, and

3) calculating the change in the utility’s performance resulting from the DSG.32

Generation System Planning.–As discussed in

chapter 3, utilities perform fundamental economic studies of their systems so that the most

financially attractive generation option can be

chosen to meet predicted demand and so that

they can determine when to retire existing units.

The basic calculation involves the estimation of

the value resulting from the installation of a power

source—defined as the savings in conventional

fuel, operation, maintenance, and capacity costs.

~ZT, Flairn, et al., Econorn;c Assessments of /rfterrnitterrr, CridConnected Solar Electric Technologies: A Review ot’ Methods

(Golden, CO: Solar Energy Research Institute, September 1981),

sERl/TR-353-474.
Ch. 6—The Impact of Dispersed Generation Technologies on Utility System Operations and Planning “ 175

A number of value studies of incorporating solar energy generating sources into utility resource

plans have been performed on a variety of specific utility systems since 1975.33 Typically, these

studies analyze a base case (without solar technologies) and then a case with solar. The value

assigned to the solar energy is the cost difference

between the two study cases.

These studies34 generally incorporate the following steps in evaluating the value of DSGs in

a utility’s resource plan. First, a base case analysis of an expansion plan without solar technology establishes a benchmark against which solar

technologies are evaluated. Next, a second case

is analyzed with solar technologies in three steps:

1 ) estimating the power output of the solar technologies, 2) modification of the hourly loads by

the solar production to determine the residual

hourly loads on the nonsolar technologies generation, and 3) recalculating production costs and

the reliability impacts. Typically, generation planning studies for the 20- to 30-year planning horizon do not use detailed, hourly data, but the intermittent nature of solar energy requires this type

of representation. The difference in reliability between the base case and the solar alternative can

be used to compute the solar technologies’ capacity credit in the utility’s generation plan. As

a final step in the process, the cost difference between the cases with and without solar technologies are examined to obtain the single year savings. Using the single year savings, the present

value of the total savings is accumuIated over the

expected lifetime of the solar facility under study.

The most important factor affecting the breakeven energy cost is the utility’s present and

planned future generation mix, which determines

the type and quantity of fuel and capacity displaced. Evidence strongly suggests that while solar technologies may displace some conventional

production capacity, the greatest value of solar

rests with the displacement of energy, i.e., fuel

savi rigs.

Key areas of future work include the development and validation of models that accurately

characterize the dynamic behavior of solar technologies. Capacity potential will be measured in

part by the effectiveness of solar technologies to

participate in short-term load following process,

i.e., load frequency control.

Transmission Planning.—Electric transmission

systems are studied in terms of network capacity and reliability requirements. Criteria for sizing the transmission system vary from utility to

utility; however, the basic purpose of all transmission system design studies is to establish when

and where new lines should be added and at

what voltage level.

A transmission plan consists of three major

components: 1 ) a generation dispatch strategy

and the projected load profile for the system are

used to determine the expected transmission line

loading levels over the planning period; 2) a minimum cost transmission expansion plan for the

horizon year which meets the reliability criteria;

and 3) and a “through-time plan, ” i.e., the sequence of changes in the transmission system in

transition to the horizon year.35 Key parameters

for comparing alternative expansion plans are the

number of line additions required per unit of time

and the present worth cost of those additions.

Studies sponsored by EPRI36 estimate transmission “credits,” i.e., capital cost savings, associated with DSG siting close to load centers of $66

to $133/kW, for a variety of transmission system

configurations. If more expensive underground

cables are involved, the savings were estimated

to be as high as $250/kw. The simulations showed

that an optimal DSG market penetration, from

the point of view of transmission system planning,

appeared to be about 20 percent of metropolitan load growth. Below or above that level, the

transmission credits per kilowatt decreased.

Distribution Planning.–The effect of DSGs on

the distribution system (typically 13 kilovolts and

~Jlbid.; ~nd T. Flalm and S, Hock, Wind Energy SYstems for E/ec’-

tnc Uti/ities: A Synthesis ot’ Va/ue Studies (Golden, CO: Solar Energy

Research Institute, May 1984), SERI/TR-211 -2318

~~T. Fla I m and S. Hock, wind Energy Systems for E/ectric Ut;/ities: A Synthesis of’ \/a/ue Stud/es, op. cit., 1984.

31B ~Kaupang, Assessment of Distributed Wind po~$’er -$Ystems

,,

(Palo Alto, CA: Electric Power Research Instttute, February 1983),

EPRI AP-2882.

16 Systems Contro[, Inc., /mpacf on Transmission Requirements

of Dispersed Storage and Generation (Palo Alto, CA: Electric Power

Research Institute, December 1979), EPRI EM-1 192.
176 . New Electric Power Technologies: Problems and Prospects for the” 1990s

below) is determined by the deployment strategy of the equipment. Clusters of generating

equipment, irrespective of individual unit size,

that are placed on feeders or in substations, affect the system very differently than small generators distributed throughout the electric system.

In substations, the primary element for concern

is the transformer. The addition of DSGs has the

potential for changing significantly the operating

conditions of the transformer. Deferring additional substation capacity is the desirable attribute. For small additions of DSGs up to some minimum level, no deferral of transformer capacity

results because the substation is largely responsible for serving all the load. Above this minimum

up to some maximum level, deferrals will result;

above the maximum, additional transformer capacity is required for the generator itself. In sum,

the effect of deferral is captured by the particular sizing policy of the utility, but DSGs can defer the addition of both transformer and feeder

capacity .37

The addition of DSGs to the substation has no

influence on distribution system losses, but placing generating equipment on the feeder can reduce losses because the production will be closer

to the load. When generation is placed closer to

the load, less power is transported through the

system, thereby reducing losses. DSG installation

must be well planned so that existing circuits are

not a limitation. Again, the amount of loss reduction depends on the utility.

Excessive voltage fluctuations offer greater potential concern when DSGs are placed in the distribution system, especially since they are nearer

the loads. Under wind gust or cloud cover conditions, solar technologies can cause large voltage

swings due to current surges from the electrical

converter. Voltage regulators and tap-changing

transformers in the power system are very slow

to respond (on the order of a minute) resulting

in no influence on the short-term problem.

Electric Power Systems Operations

Overall management of power system operation consist of two phases—operation planning

JZlbid

and real-time operation. Operation planning consists of the scheduling of generation and transmission facilities for use during a 1- to 3-day

period; it is the so called “redispatch problem.”

Real-time operation involves the on-line management and control of all facities on a second-tosecond basis. In most utilities, daily operations

are directed from a central control center.38 

Operations Planning.–A strategy is formulated

to deploy the system’s available resources to meet

the anticipated load of the next day economically

and reliably. First a load forecast of hourly loads

and load ramp rates (minute to minute changes

in load) is made to determine the generation and

transmission requirements. Subsequently, a “unit

commitment” strategy is determined based on

available facilities as determined by any scheduled or unscheduled down-time of equipment.

The resulting plan is the guideline to daily operations. 39

Real-Time Operations.— Utilities must continually adjust electricity production to follow the

constantly changing electric demand. Production

and demand are maintained in balance by the

combined actions of speed governors on individual generating units (frequency regulation) and

a closed loop automatic generation control system which performs load frequency control (regulation) and economic dispatch functions.40 In

addition, the instantaneous balance of load and

demand is known as stability. A configuration is

chosen which assures a stable system under a

credible list of potential system component

failures (faults, equipment trips, etc.).

Automatic Generation Control.–There remains

much uncertainty and debate over what DSG

penetration level will negatively affect utility system performance. An earlier OTA report41 discusses concerns about the effects of a high

penetration of DSGs. A common definition of

“high penetration” is a DSG capacity over 25 percent of the capacity of the particuIar distribution

JET. W. Reddoch( et al., “Strategies for Minimizing Operational

Impacts of Large Wind Turbine Arrays on Automatic Generation

Control Systems,” Jxfrrra/ of So/ar Engineering, vol. 104, May 1982.

391 bid .

Aolbid .

AI OTA, /ndustria/ and Commercial Cogeneration, op. cit., 1983.
Ch. 6—The Impact of Dispersed Generation Technologies on Utility System Operations and Planning ● 1 7 7

feeder or over 25 percent of overall utility system capacity.

There are no utilities today approaching this

definition of high penetration of DSG equipment

on particular distribution feeders—even the utilities with the most DSG installations have less

than one-tenth of 1 percent penetration. Yet, for

most utilities, the penetration level is increasing

and some, such as Houston Lighting & Power,

are planning for the possibility of penetrations as

high as 30 percent by the year 2000.42 One utility in Hawaii currently has 10 percent DSG

penetration (see box 6E).

The effect DSGs have on an electrical system’s

area control error (ACE) is of particular interest.

ACE measures a combination of frequency deviation and net tie-line power flow (see box 6A).

North American utilities have agreed on certain

minimum standards for ACE values: ACE must

equal zero at least once and must not vary beyond a certain range during each 10-minute interval .43

Analysts measuring utility system performance

with high penetrations of DSGs must measure the

increase in ACE caused by the DSGs, rather than

by other influences unrelated to DSGs. These

measurements are difficult to make in the field,

since ACE often results from the demand shifts

caused by fast-changing, unpredictable conditions such as a quickly moving thunderstorm, a

fast drop in temperature, or a drop in power coming from a neighboring utility across a highvoltage tie-line.

Most researchers agree that at the present low

levels and continuing up to at least 5 percent of

DSG penetration, there are no ill effects on system operations as measured by ACE. However,

there is no general agreement on what increase

in penetration of DSGs beyond 5 percent will increase ACE.

4ZHenry Vad ie, Houston Lighting & Power, OTA workshop on

Cost and Performance of New Generating Technologies, June 1984.

43M, G. Thomas, et al., Arizona State University, Dfdft Report :

The Effect of Photovoltaic Systems on Utility Operations, contractor

report (Albuquerque, NM: Sandia National Laboratories, February

1984), SAND84-7000.

Curtice and Patton44 used data on wind generators and estimated ACE for four different generator penetration levels. Their results indicated that

ACE increases only 1 percent when total wind

capacity is at 20 percent of the overall utility system. When penetration reaches 50 percent, ACE

increases to 10 percent. While these changes in

ACE were not significant, the authors noted, with

5 percent penetration, wind output variations

, . . did not cause a significant change in the

control process. . . . However, increased energy

flow over the tie-lines connected to neighboring

utilities compensated for generator/load mismatches occurring too fast for the utility’s generators to follow. If the utility’s control process is

designed to minimize tie-line flow deviations,

. . . then generator/load mismatches show up as

increased ACE and decreased system performance.

These results suggest that, although measured

ACE was not large, there is a potential problem

with installing wind machines. /f there is a high

enough fluctuation in wind speed, if there is a

high proportion of wind generation on a particular feeder, and if the utility optimizes its control

procedures for minimizing tie-line variations (an

electric industry standard), a decrease in system

performance could occur. Moreover, there is a

potential for overloading the distribution feeder.

(Other research notes the need to develop alternative generation control algorithms to better accommodate DSGS.

45)

A Sandia Laboratories study46 also supports the

view that DSGs have a limited effect on system

44D, cu~ice ancj J. B. Patton, /interconnecting DC Energy !$ystems:

Responses to Technical Issues, op. cit., 1983.

45S. H. Javid, et al., “A Method for Determining How to Operate and Control Wind Tu;bine Arrays in Utility Systems, ” /EEE Transaction on Power Apparatus and Systems, IEEE Summer Power Meeting, Seattle, WA, 1984; F. S. Ma and D. H. Curtice, ‘ ‘Distribution

Planning and Operations With Intermittent Power Production, ” /EEE

Transactions on Power Apparatus and Systems, August 1982; Systems Control, Inc., The Effect of Distributed Power Systems on Customer Service Re/iabi/ity, contractor report (Palo Alto, CA: Electric

Power Research Institute, August 1982), No. EPRI 3L-2549; and T.

W. Reddoch, et al., “Strategies for Minimizing Operational Impacts

of Large Wind Turbine Arrays on Automatic Generation Control

Systems, ” op. cit., May 1982. Another recent study examined how

to efficiently operate and control wind turbine arrays; see Stevens

and Key, op. cit., 1984.

*Thomas, et al., op. cit., 1984, SAN D84-7000; and M. G. Thomas

and G. J. Jones, Draft Report: Grid-Connected PV Systems: How

and Where They Fit (Albuquerque, NM: Sandia National Laboratories, 1984).
178 ● New Electric Power Technologies: Problems and Prospects for the 1990s

performance. The researchers modeled photovoltaic (PV) arrays on a long rural distribution line

with 30 percent of the homes on the line using

small (1 O to 20 kW) PVs. In order to observe any

significant increase in ACE, “a solid cloud cover

would engulf all 10 miles of the distribution feeder

simultaneously masking every PV home . . . and

this scenario would be repeated every 6 minutes. ”

The study maintains this is a very unlikely situation and in any event represents the worst possible condition for PV interconnection equipment.

The sudden and unpredicted loss of a large

generator can drastically unbalance the supply

system of a utility, especially when this generator represents a large proportion of the entire system capacity. Two modelers have studied such

a situation:

Researchers from Arizona State University simulated the effects of larger PVs with a three region model (the regions are the service areas of

Arizona Public Service and The Salt River Project

as well as a third region representing the remainder of the Western United States and Canadian grid). A PV generator was placed in each

area and its output changed in response to predetermined cloud movement and wind velocity.

Five different-sized PVs were used, ranging from

50 to 250 MW. The researchers found no significant increase in ACE as long as: 1 ) any single

central-station PV unit was less than 5 percent
Ch. 6—The Impact of Dispersed Generation Technologies on Ufi/ity System Operations and Planning ● 1 7 9

of total system capacity or less than 5 percent of

any particular distribution feeder; and 2) a combination of smaller, home-sized PVs was less than

50 percent of total system capacity or particular

feeders. 47

Dynamics and Transient Stability.—Most concerns with stability have focused on wind turbines. The special characteristics of wind turbine

generators which cause their dynamic behavior

to be different from that of conventional units can

be traced to the large turbine rotor diameter and

slow turbine speed necessary to capture sufficient

quantities of power from the relatively low power

density of the wind. The electrical generators for

“R. M. Belt, ‘‘Ut]lity Scale AppJlcatlon of WInci Turbines, ” paper pre~ented at V1’inter Power ,Meetlng of the IEEE, No, CH 1664,

February 1981,

large wind turbine applications are generally four

or six pole designs and a high ratio gear box is

essential to step up the low turbine speed to the

synchronous speed of the generator (] ,800 or

1,200 rpm). The high ratio gear box causes wind

turbine drive trains to have torsional properties

which are not characteristic of conventional turbine generators. But the dynamics of large wind

turbines are compatible with conventional power

systems and pose no apparent barrier to their application. The same could be said of the transient

stability properties of wind turbines during electrical or mechanical disturbances. 48

J8E N H I n ric hsen a ncj p, J. NOla n, ~ynamfc+ Ot S//lg/e- ,Ind A’fu/f/-

.

Unit Wind Energy Con~erslon Plants Sui>p/}’\ng Electric UtIIIt}/ S}sferns, contractor report, US, Department of Energy (W’ashtngtonf

DC: National Technical Information Ser\lce, August 1981), DOE /

ET/20466-78/ 1 .
Chapter 7

Regional Differences

Affecting Technology Choices

for the 1990s
CONTENTS

Page

Introduction . . . . . . . . . . . . . . . . . . . . . . . . . 183

overview . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 183

Definition of Regions . . . . . . . . . . . . . . . . . . . 183

Regional Issues Defined by

Electricity Demand . . . . . . . . . . . . . . . . . . . . 183

The Role of Uncertainty in Regional

Demand Forecasts. . . . . . . . . . . . . . . . . . . . 183

opportunities for Consumer Side

Alternatives to New Capacity . . . . . . . . . . . 188

Regional Economic and Regulatory

Characteristics Affecting

Technology Choices . . . . . . . . . . . . . . . . . . 190

Rate Regulation Issues . . . . . . . . . . . . . . . . . . 190

Licensing and Permitting of

Small-Scale Systems . . . . . . . . . . . . . . . . . . . 192

Key Characteristics of Regional Electricity

Supply Systems . . . . . . . . . . . . . . . . . . . . . 194

Present and Projected Fuel Reliance . . . . . . . 194

Opportunities for Plant Betterment and

Life Extension. . . . . . . . . . . . . . . . . . . . . . . . 195

Supply Enhancements From Interregional

and Intraregional Power Trdnsfers . . . . . . . 197

Prospects for Nonutility Generation. . . . . . . . 198

Regional Fuel and Technology Reliance

Profiles . . . . . . . . . . . . . . . . . . . . . . . . . . . ..203

East Central Area Reliability Coordination

Agreement (ECAR) . . . . . . . .............203

Electric Reliability Council of Texas

(ERCOT) . ...........................20 4

Mid-Atlantic Area Council (MAAC) . .......204

Mid-America Interpool Network (MAIN) ....205

Mid-Continent Area Power POOI

(MAPP-U.S.) . .......................20 6

Northeast Power Coordinating Council

(NPCC-U.S.) . . . . . . ...................207

Southeastern Electric Reliability Council

(SERC) . ............................20 8

Southwest Power Pool (SAP) . . . . . . . . . . . . . .209

Western Systems Coordinating Council

(Wscc-u.s.) . .......................21 0

Alaska Systems Coordinating Council

(ASCC) . . . . . . . . . . . . . . . . . . . . . ........211

Hawaii . . . , . . . . . . . . . . . . . . . . . . . . . . . . . . . 212

Summary of Major Regional Issues . .........214

Demand Uncertainty. . . .................214

Present and Projected Fuel Reliance . ...,..214

Page

Plant Life Extension. . . ..................215

Other Key Variables . . . . . . . . . . . . . . . . . . . . 215

Table

7-1.

7-2.

7-3.

7-4.

7-5.

7-6.

7-7.

List of Tables

N o . Page

Utility Type, By Region . ..............188

Average Fuel Prices, By Region . .......190

Average Residential Commercial and

Industrial Electricity Prices,

By Census Region . ..................191

Selected Characteristics of Regional

Electric Utility Generation Systems. .. ...193

Life Extension Resource Base: Age of

Fossil-Fired Steam Plants, By Region ....196

Actual and Expected Power Transfers,

1983-1993 ..........................19 9

Estimated Maximum Industrial

Cogeneration Potential Available

as of 1980 . . . . . . . . . . . . . . . . . . . .. ...200

List of Figures

Figure No. Page

7-1.

7-2.

7-3.

7-4.

7-5.

7-6.

7-7.

7-8.

7-9.

7-10.

7-11.

7-12.

Map of North American Electric

Reliability Council Regions . . . . ........184

Map of U.S. Census Regions. . .........185

1993 Regional Capacity Shortfalls or

Surplus Relative to 20 Percent Reserve

Margin Given Varying National Demand

Growth Rates and Current Utility

Capacity Projections . ................186

Sample Load Curve for a Utility in the

ECAR Region on a Day in January ... ...l89

Regional Utility Capacity by Fuel Use,

1984 and 1993 ......................195

Regional Utility Generation by Fuel Use,

1984 and 1993 . . . . . . . . . . . . . . . . .. ....196

Historical Transmission Loading

Patterns in MAAC . ..................197

Interregional and Intraregional Power

Transfer Capabilities . ................198

Major U.S. Hydrothermal Resources ....200

Average Annual Wind Power . .........201

Average Annual Solar Radiation . .......202

Geological Formations Potentially

Appropriate for Compressed Air

Energy Storage ., . ...................202
Chapter 7

Regional Differences Affecting

Technology Choices for the 1990s

INTRODUCTION

Overview

The inherent uncertainty associated with estimating future electricity demand is one of the

most important factors affecting utility choices

among electricity supply options. Demand growth

rates differ dramatically within and among regions, and unanticipated changes in these rates

can substantially affect both overall system reliability and the need for new generating capacity.

Other factors that vary by region also strongly influence utility technology choices. This chapter

focuses on these differences, quantifies them

where possible, and speculates on their shortand long-term influence.

Among these other differences are plant life extension opportunities (defined by the age and

type of existing generating facilities) and present

and projected fuel dependence, which generally

establishes regional benchmarks for technology

cost comparisons. Other variables discussed in

this chapter include opportunities for

REGIONAL ISSUES

The Role of Uncertainty

power transfers; potential supply contributions

from load management, conservation, and cogeneration; constraints imposed by natural resource availability; and differences in regional

regulatory and economic environments.

Definition of Regions

While regions can be defined by many

characteristics—e. .g., demographics, economic

make-up, census divisions, and/or physical

geography—the regions used most often in this

chapter will be those of the electric reliability

councils. There are nine regional councils in the

United States and one national group: the North

American Electric reliability Council (N ERC). Figure 7- I summarizes what the councils do and

shows which areas of the country they cover. Figure 7-2 illustrates how these regions compare

with census divisions, because occasionally data

will be presented in this format as well.

increased

DEFINED BY ELECTRICITY DEMAND

in

Regional Demand Forecasts

As noted in chapter 3, the national average annual rate of growth in electricity demand fluctuated greatly through the 1970s. Growth rate

predictions have similarly varied. For example,

in 1975, NERC expected demand growth to stabilize at 6.9 percent per year through 1984; as

of early 1984, the council expected growth

through 1993 to average 2.5 percent, ’ Other esti-

‘North American Electric Reliability Council (N ERC), 14th Annua/

Review of Overall Reliability and Adequacy of Bulk Power Supply

in the E/ectrlc Uti/lty Systems of North America (Princeton, NJ:

NERC, 1984).

mates range between 1 and 5 percent (see figure 3-4 in chapter 3). As figure 7-3 illustrates,

small changes in expected growth lead to substantial differences in capacity requirements to

meet overall demand.

Wide regional variations in demand growth

rates have been and continue to be common.

NERC 1984 projections for average annual demand growth in the next decade range from 1.3

(MAAC) to 4.0 percent (ERCOT). Comparable disparities also occur within regions. For example,

within WSCC, which is divided into four subregions, the California-Southern Nevada Power

Area expects demand growth of 1.9 percent,

183

38 -743 0 - 85 - 7
184 . New Electric Power Technologies: Problems and Prospects for the 1990s

Figure 7-1 .—Map of North American Electric Reliability Council (NERC) Regions

NERC helps ensure the adequacy and reliability of the U.S./Canadian electricity power supply system by acting as a forum for greater coordination between regional utility systems. The nine regional organizations listed below provide similar services to their member utilltles,

Several of the regional councils have member systems in Canada. Throughout this chapter, statistics will be cited for U.S. members only,

East Central Area Reliability Coordination Agreement

Electric Reliability Council of Texas

Mid-Atlantic Area Council

Mid-America Interpool Network

Mid-continent Area Power Pool

Northeast Power Coordinating Council

Southeastern Electric Reliability Council

Southwest Power Pool

Western Systems Coordinating Council
Ch. 7—Regional Differences Affecting Technology Choices for the 1990s ● 185

Northeast

Middle

Atlantic

SOURCE U S Bureau of the Census

while the Arizona-New Mexico Power Area expects growth on the order of 4.4 percent.2 Many

factors underlie these differences in growth rates,

including observed and expected consumer response to electricity prices and the prices of competing energy sources; regional and national economic structure and trends; the anticipated

effects of cogeneration, load management, and

conservation; varied utility system efficiency improvements; and new uses for electricity.

Historically, reserve mat-gins have been used

as general indices of system reliability. As explained in box 7A, the definition of what constitutes an adequate reserve varies. While the tradiZlb;d.

tional target has been 20 percent, utility systems

within the same region may adopt different standards depending on many factors, including individual plant characteristics, access to power from

other systems, and characteristics of customer demand. Looking at reserve margins on a regional

scale thus suggests rather than defines the reliability issues in a given region.

As figure 7-3 suggests, reserve margin estimates

are particularly sensitive to demand growth predictions. U.S. Department of Energy (DOE) projections based on current NERC demand and capacity forecasts indicate that, between 1984 and

1993, six of the nine NERC regions will at some

point fall short of selected reliability criteria (see

table 7-4). If future demand growth proves higher
u –

N;tional Demand Growth Rates and Current Utility Capacity Projections - —

25

20

15

10

5

0

-5

-lo

-15

-20

ECAR ERCOT MAAC MAIN MAPP NPCC SERC SPP WSCC

(Us.) (Us.) (Us.)

Region

In the figure above, regional demand is calculated under four different national demand growth rates: 1.5, 2.5, 3.5, and 4.50/o.

The regional growth rates expected by NERC councils under the 1984 2,!5°/. forecast for national demand were used to establish relative

weights for each region. These weights were then applied to the three other scenarios so regional differences in growth rates would be

accounted for.

The 20 percent reserve margin for 1993 was calculated with the following formula:

capacity planned for 1993 – expected peak x 100

expected peak

These capacity projections do not account for contributions from power interchanges, nor are they adjusted for expected maintenance,

outages, and similar factors.

Shortfalls and/or excesses were calculated as follows:
Ch. 7—Regional Differences Affecting Technology Choices for the 1990s • 187

qFor example, a recent study by J. Steven Herod and Jeffrey Skeer

of the Office of Coal and Electricity Policy, U.S. Department of

Energy projects regional reserve margins through 2000 under two

different national demand growth scenarios. The first scenario assumes growth at 2.6 percent through 1990 and 2.4 percent from

199o through 2000. The second, higher growth scenario assumes

3.3 percent growth through 1990 and 2.9 percent growth from 1990

to 2000, The utility capacity projections used in Herod and Skeer’s

analysis exclude: 1 ) coal units planned but not yet under construction as of the end of 1983, and 2) nuclear units only one-third complete as of that date. As would be expected, under these assumptions several regions show reserve margin problems earlier than

indicated in figure 7-3. In particular, both ERCOT and MAPP would

fall below 20 percent in the mid to late 1980s, highlighting these

regions’ dependence on planned additions. All regions would fall

below 20 percent by 1994 under the high growth scenario. For further information, see J. Steven Herod and Jeffrey Skeer, “A Look

at National and Regional Electric Supply Needs, ’’presented at the

12th Energy Technology Conference and Exposition, March 1985.

The views expressed in the report are those of the authors.

5u. s. Depaflment of Energy (DOE), E/ectric Power SUPP/Yand

Demand for tk Contiguous United States 1984-1993 (Washington,

DC: DOE, June 1984.
188 ● New E/ectric Power Technologies: Problems and Prospects for the 1990s

Table 7-1.-Utility Type, By Region

Percent total

Percent total electricity sales to

Number of electricity sales to ultimate customers

publicly ultimate customers from publicly owned

owned from IOUS, by census utilities, by census

utilities region, 1983 region,- 1983

43

49

165

217

152

138

113

52

55

984

91

92

90

64

81

36

81

70

62

76

9

8

10

36

19

64

19

30

39

24

cent margin may not completely assure system

reliability in those systems which place heavy emphasis on large plants, Whether or not this will

emerge as an issue remains unclear; as of 1980,

ECAR, ERCOT, MAAC, and SERC were the only

regions with more than 15 percent of total capacity in units equaling or exceeding 500 MW;

of these regions, ERCOT had the highest

percentage–25 percent.G

Opportunities for Consumer Side

Alternatives to New Capacity

Conservation

Conservation can offer a cost effective alternative to a significant quantity of new capacity construction, and the National Association of Regulatory Utility Commissioners (NARUC) is actively

encouraging utilities across the country to include

conservation in their resource plans. From a utility’s perspective, one of the major issues associated with relying on this “consumer side” supply strategy is that implementation depends on

actions outside the utility’s direct control. While

different pricing strategies have been used to encourage conservation, customer responses are

not entirely predictable. Utilities are also concerned about conservation efforts which might

reduce off-peak demand without affecting the

G@rlVecf f~om generating plant database prepared for OTA in

January 1985 by E.H. Pechan & Associates, Inc.

peak, thereby decreasing system load factor without decreasing the need for new capacity.

The energy conservation resource appears

quite large, although estimates of the potential

energy savings and capacity deferrals vary widely.

OTA’S assessment of conservation opportunities

in specific energy-use categories can be found

in several previous studies. ’

Load Management

NARUC is also encouraging U.S. utilities to

consider load management in their resource

plans, Load shape patterns define the opportunities for load management, As figure 7-4 illustrates, these patterns differ among end-use sectors, with industrial loads generally more uniform

than commercial or residential ones. Load shape

variations between utility systems within NERC

regions are as marked as the variations among

regions. The load management opportunities

within a given region are defined by many factors, including system reserve margins, expected

load factors, customer profiles, the degree to

which a utility generates its own power or purchases it from other systems, and public utility

commission policies.

7U. S. Congress, Office of Technology Assessment (OTA), Energy

Efficiency of Buildings in Cities (Washington, DC: U.S. Government

printing Office (GPO), March 1982); OTA, Industrial Energy Use

(Washington, DC: GPO, June 1983); OTA, U.S. Vu/nerabi/ity to an

Oil Import Curtailment: The Oil Replacement Capability (Washington, DC: GPO, September 1984.)
Ch. 7—Regiona/ Differences Affecting Technology Choices for the 1990s ● 189

Figure 7.4.— Sample Load Curve for a Utility in the

ECAR Region on a Day in January

100

90

80

70

60

50

4 8 12 16 20

Hour of the day

I

Residential

Commercial

Industrial

One of the key operational objectives behind

load management is to increase system loa d

factor–the ratio of average load to total load over

a specified time interval. I n the united States, regions with high load factors are generally characterized by moderate, stable climates and/or heavy

industrial loads, while low load factors usually are

indicative of high seasonal peaks in electricity use

and/or little heavy industry.8

In all regions, there appear to be substantial opportunities for load management; these opportunities are discussed in detail in chapter 5. I n particular, the residential market remains largely

untapped, making areas characterized by high

population density or high population growth attractive candidates (see table 5-I ) if the obstacles

discussed in chapter 5 can be overcome. Opportunities also remain in the commercial and industrial sectors.

In the long run, fuel reliance patterns may make

load management an unattractive option in some

regions if it defers replacement of costly oil- or

gas-fired units.9 This may be especially important

in oil- or gas-dependent areas such as ERCOT,

MAAC, NPCC, SPP, the Florida subregion in

SERC, and two subregions of WSCC–the Ca!iforniaSouthern Nevada Power Area and the Arizona

New Mexico Power Area. From the consumer’s

standpoint, the deciding factor regarding the

desirability of such deferrals will be the ultimate

impact on electricity bills—a function of both

electricity rates and electricity use. For utilities,

the desirability of such deferrals will be heavily

influenced by their cost relative to other electricity supply options.

Municipal utilities (munies) and rural cooperatives (coops), most of which buy the bulk of their

power from other systems, are already actively

pursuing load management to both improve load

factor and minimize the cost of purchased power.

These systems accounted for one-third of all the

load control points in 1983. Munies and coops

facing high demand charges on purchased power

are expected to continue to provide a strong load

BNERC, E/ectr/c power Supply and Demand, 1984-1993 (pr; riceton, Nj: NERC, 1984).

gjames j, Mulvaney, planning and Evaluation Division, Electric

Power Research Institute, E/ectric Generation System Development:

An Overview, November 1983.
IW . New Electric Power Technologies: Problems and Prospects for the 1990s

Table 7-2.—Average Fuel Prices, By Region

(in cents per million Btu)

Residual Distillate

Region oil a

o i l

b

and year Coal (#6) (#2) Gas

ECAR:

1983 ......., . 168.1

1984 . . . . . . . . . 165.9

ERCOT:

1983 . . . . . . . . . 164.3

1984 . . . . . . . . . 156.5

MAAC:

1983 . . . . . . . . . 158.1

1984 . . . . . . . . . 166.3

MAIN:

1983 . . . . . . . . . 186.7

1984. . . . . . . . . 180.3

MAPP (U.S.):

1983. . . . . . . . . 128.8

1984. . . . . . . . . 132.1

NPCC (U.S.):

1983. . . . . . . . . 194.8

1984. . . . . . . . . 192.5

SERC:

1983. . . . . . . . . 191.8

1984. . . . . . . . . 191.9

SPP:

1983. ...,.... 166.3

1984. . . . . . . . . 172.6

WSCC(u.s):

1983. . . . . . . . . 109.4

1984. . . . . . . . . 112.6

451.9

460.4

503.7

567.3

464.0

488.0

605.6

613.1

419.5

453.0

446.8

476.0

427.3

463.2

373.8

410.9

602.5

620.9

625.6

628.9

517.9

601.5

602.5

614.6

621.4

629.9

596.9

603.9

635.4

637.7

621.0

608.4

615.3

625.3

619.0

616.2

426.9

419.8

362.3

358.0

405.4

434.1

506.4

474.8

365.9

363.9

395.9

398.1

261.3

332.6

251.3

254.6

500.5

502.9

aMost of the oiI burned by utilities (e.g., ~ percent) k residual oil; it is usuallY

burned in base and intermediate load boilers.

bDistillate OiI IS burned in peaking units (i.e., combustion turbines and diesel

engines).

SOURCE: Data generated for OTA by Energy Information Administration, Electric Power Division, U.S. Department of Energy, November 1964.

REGIONAL ECONOMIC AND REGULATORY CHARACTERISTICS

AFFECTING TECHNOLOGY CHOICES

Rate Regulation Issues

Avoided Cost

Potential markets for many new generating

technologies depend on the buy-back rates being offered by utilities under the avoided cost

guidelines of the Public Utility Regulatory Policies

Act (PURPA). Regional generalizations about

these rates are complicated by the substantial variations within regions as well as the continued

changes in rate offerings, primarily due to fluctuating projections of the costs of avoided fuel

use,

Since fuel costs are a critical factor in the economics of technology alternatives, regional averages are presented in table 7-2. As this table illustrates, fuel costs are particularly high in NPCC

and WSCC, two areas within which avoided cost

rates are also high relative to the rest of the country. In general, the highest avoided energy rates

(as of October 1984) were offered in NPCC,

WSCC, ERCOT, and MAAC, with utilities in States

in each of these regions offering rates equal to

or above 6 cents/kWh. With the exception of

Florida (SERC), States within these four regions

were also the ones with utilities offering the highest capacity credits.10

IOFrom data presented in “’States’ Cogeneration Rate-Setting Under PURPA, Part 4,” Energy User News, vol. 9, Nos. 40-43, Oct.

1, 8, 15, and 22, 1984
Table 7-3.—Average Residential, Commercial, and Industrial Electricity Prices, By Census Region

I

I
192 ● New Electric Power Technologies: Problems and Prospects for the 1990s

While avoided cost rates could fall in the near

term (e.g., due to declining oil and gas prices)

there is considerable disagreement on this issue. 11

As a policy decision to encourage cogeneration

and new technologies, some State regulatory

agencies (e. g., New York, New Jersey, and Iowa)

are deliberately establishing or encouraging high

buy-back rates .12 These actions have often been

the impetus for litigation; the Iowa rate was being challenged in court at the time this report

went to press, while the New York rate had just

avoided further challenge when, based on jurisdictional issues, the Supreme Court declined to

review a lower court’s decision upholding the

rate.

Construction Work in-Progress

State policies towards construction work inprogress (CWIP) for new generating facilities are

another factor which may strongly influence technology choices. Allowing CWIP in the ratebase

helps avert the sudden rate shocks which can occur when major new plants come into operation;

this assumes added importance in areas such as

the New England and Mid-Atlantic States (see

table 7-3) where electricity rates are already high

relative to the rest of the country. Allowing CWIP

in the ratebase can also make it easier for utilities to obtain financing for new construction projects, since this reduces the perceived and actual

financial risks associated with new construction.

Conceivably, such a policy could encourage all

types of technology, but industry observers suggest it is most likely to favor conventional

technologies—systems with which utilities are the

most familiar and comfortable (see chapter 3 for

a more detailed discussion).

Handling CWIP in retail rates is a State decision; rate policies are highly variable both between States and within the same States over

I IOTA workshop on Economic and Regu Iatory Issues Affecting

New Generating Technologies, February 1985.

I Zsome industry observers also note that several uti Iity commissions are beginning to react against high avoided cost rates and

may move to set artificially low rates in an effort to protect their

ratepayers. Other States such as California are stepping back from

long-term Ievelized rates and returning to annual ones. Source: Allen

Clapp, Director of Financial and Economic Analysis, North Carolina Alternative Energy Corp., personal communication, November 1984,

time.13 As of 1981, about 50 percent of all State

regulatory agencies allowed some form of CWIP

in the ratebase.14 The Federal Energy Regulatory

Commission (FERC), which controls wholesale

rates, allows 50 percent of the funds used for construction to be treated as CWIP.

Licensing and Permitting of

Small-Scale Systems

Because the economics of small or undercapitalized projects are particularly vulnerable to

unanticipated costs or delays, regulatory policies

affecting faciIity siting can also have a strong impact on technology deployment, especially when

third-party producers are involved. To date, most

of the experience in licensing and permitting

small-scale alternative (especially renewable)

technology projects has been in California. Although California’s environmental review process is unique and perhaps the most rigorous in

the country, some general trends appear to be

emerging. Of these, the most important is that

new, small-scale (i.e., less than 50 MW) technologies are not immune to controversy and opposition. While their impacts tend to be localized,

concerns about them have in some cases led to

lengthy and expensive environmental review,

with the review costs borne by the developers.

In other cases, the same types of projects have

met no local resistance at all (see box 76).

These experiences suggest that implementation

of small-scale solar, geothermal, and wind technologies will be substantially influenced by local regulatory policies, the most influential being local zoning ordinances, land use permits,

and public health standards. In areas where a

land intensive project is proposed and sensitive

habitat is affected, State and Federal laws may

assume a dominant role, but these effects will be

more site than region specific.

While siting of alternative technologies can be

expected to be carefully monitored, especially

in States with strongly protective environmental

13For examp~, the Texas public Utility Commission allowed Cwlp

in the rate base in 1980, but a subsequent 1984 ruling excluded it.

14Energy Information Administration, /fT1/JdCtS Of ~/flaf7C/c3/ CO~-

s(raints on the E/ectric UtI/ity /rtdustry (Washington, DC: December 1981), DOE/EIA-0311.
Ch. 7—Regional Differences Affecting Technology Choices for the 1990s “ 193

●

●

●

✎

✌

●

✎

●

✌

☛

●

●

.

.

●

● ☛

✌ ☞

✌ ✌

✌ ✌

●

●

●

●

●

●

●

✎

●

●

●

m

●

.

●

,

,

*

●
KEY CHARACTERISTICS OF REGIONAL

ELECTRICITY SUPPLY SYSTEMS

Present and Projected Fuel Reliance

Regional fuel and technology reliance establish the benchmarks for technology cost comparisons. While most systems with substantial oil and

gas capacity are expected to decrease use of these

fuels over the next decade, reliance on premium

fuels is expected to be strong enough in some

areas, i.e., ERCOT, MAAC, NPCC, and some subregions of SERC, SPP, and WSCC, that the economics of competing technologies will remain

particularly sensitive to the price and availability of oil and gas (see figures 7-5 and 7-6, and table 7-2).15 As discussed in the section on demand

uncertainty, this sensitivity will be heightened if

there are significant changes in actual demand

1 sThese fuel reliance projections are from N ERC, E/ectric power

Supp/y and Demand, 1984-1993, op. cit., 1984; and from NERC,

14th Annual Review, op. cit., 1984

The reader should note that all of the 1984 figures cited from

these two NERC documents are projections made by the reliability councils in early 1984 (i. e., January-April).
Ch. 7—Regiona/ Differences Affecting Technology Choices for the 1990s . 195

Figure 7-5.— Regional Utility Capacity by Fuel Use, 1984 and 1993

1601

150

t

Key:

120

110 [

19841993 19841993 1984 1993 1984 1993 1984 1993 19841993 19841993 1984 1993 1984 1993

(Trenton, NJ: NER~; 1984).

growth requiring either cancellation of plants under construction or rapid construction of new capacity. These issues are more fully described in

the regional profiles.

Opportunities for Plant Betterment

and Life Extension

If scheduled retirement of aging powerplants

can be delayed by plant rehabilitation or efficiency improvements, the need for new construction may be deferred. As table 7-5 illustrates,

deferral prospects vary considerably by region.

At least 40 percent of the fossil-fired steam plants

in the MAIN, NPCC, and WSCC regions will be

over 30 years old by 1995, making life extension

a potentially attractive option. In terms of total

capacity, the opportunities for life extension appear highest in ECAR, SERC, SPP, and WSCC.

Having a large number of older plants does not

mean life extension or plant betterment will be

the most cost-effective supply enhancement option; as discussed in chapter 5, choosing this option will depend on site-specific economics.

Nonetheless, the resource scope alone promises

to make it an important factor affecting regional

adoption of new technologies; in all but one region, the life extension base exceeds regional capacity additions planned for the decade of 1983-93.
IM ● New Electric Power Technologies: Problems and Prospects for the 1990s

Figure 7-6.– Regional Utility Generation by Fuel Use, 1984 and 1993

■

I
Ch. 7—Regional Differences Affecting Technology Choices for the 1990s • 197

Supply Enhancements From

Interregional and Intraregional

Power Transfers

The amount and importance of interregional

and intra regional power transfers has increased

dramatically over the past four decades. While

such transfers historically have been used to increase overall system reliability (i. e., emergency

transfers to support energy-deficient areas during emergencies), the more recent emphasis has

been on economy transfers which displace high

cost, fossil fuel generation with cheaper electricity from neighboring systems. This trend has led

many transmission systems to be consistently

operated at or near maximum secure loading

levels. In systems throughout the country, high

loading levels are now raising concern about impacts on overall system reliability. Related physical transmission limits are curtailing economically

attractive exchanges into many oil- and gas-dependent regions.16

The situation in MAAC, where considerable

amounts of energy are imported from ECAR and

SERC, highlights these growing problems. In

1982, MAAC’s most limiting bulk power facilities

were loaded to full capacity 40 percent of the

time; 1 year later, this climbed to 70 percent. In

that same year (1 983), the system was used at 90

percent of rated capacity almost 95 percent of

the time17 (see figure 7-7). When systems are used

at this intensity, their ability to respond to u nexpected, severe disturbances is reduced, thereby

increasing the risk of service interruption.

Rather than increasing reliability through redundancy, i.e., building new power lines, utilities are responding by developing more sophisticated protective relaying schemes and operating

procedures. Some engineers argue that the net

result of this new trend may be increased load

shedding, indicating acceptance of increased risk

of customer service interruptions (perhaps at

preselected sites) when it results in net economic

gain.18 A combination of factors probably underI GN ERC, 14(II Anrtua/ Review, op. cit,, 1984; and Energy I nformat]on Administration, /rrteruti/ity Elu)k Power Transactmrrs (Washington, DC: U.S. Department of Energy, October 1983),

DOE/EIA-0418.

I ZN E RC, 74th A~n~a/ Review, op. cit. , 1984.

‘

8

1 bid.

I

20

t -

1

I

10 “

0

I 1 1 I I I I I I ●

0 10 20 30 40 50 60 70 80 90 100

Percent loading of most limiting bulk power system facilities

lies this new trend, including anticipation of continued escalation of construction costs, interest

rates, and fuel costs, as well as public opposition

to (and the regulatory complexity of) building

new plants or new transmission lines .19

Figure 7-8 summarizes power transfer capabilities among regions; table 7-6 shows expected net

import/export levels by region through 1993

(these are relatively long-term “firm capacity” exchanges set by contract; economy transfers are

far more variable and predictions regarding their

regional levels are not included). In general, if

demand growth follows present predictions and

current construction plans are implemented, utilities with large amounts of coal-fired generation

probably will continue to be net exporters of

power, while systems trying to reduce use of

expensive-to-operate oil and gas units will be net

purchasers of cheaper power–if they have access to it. However, it is unlikely that power transfers will be a substantial source of alternative capacity in many NERC regions due to the heavy

use of existing transmission capacity, the limited
198 ● New Electric Power Technologies: Problems and Prospects for the 1990s

frc

(t)

Figure 7-8.—lnterregional and Intraregional Power Transfer Capabilities

● Total amount of power that can be transferred in a reliable manner.

“ ● With a specific operating procedure in effect.

( + ) No significant transmission limit at this level.

number of new lines scheduled for operation

within the next decade, and the long lead times

associated with siting additional lines. The few

exceptions are discussed in the regional profiles.

Prospects for Nonutility Generation

Cogeneration

A 1983 OTA assessment estimated the technical cogeneration potential in the United States

by the year 2000 at 200,000 MW in the industrial sector and 3,000 to 5,000 MW in the commercial, agricultural, and residential sectors.

Actual implementation is expected to be considerably less, depending on a broad range of

economic and institutional considerations.20 For

example, if a 7 percent rate of return after inflation is used as the cut-off point for acceptable

project economics a 1984 study prepared for
Ch. 7—Regional Differences Affecting Technology Choices for the 1990s ● 199

Table 7-6.—Actual and Expected Power Transfers, 1983-93°

Years expected to Net exports (range in MW) Years expected to Net imports (range in MW)

Region be net exporter Low High be net importer Low High

ECAR . . . . . . . . . . . 1984-92 270 3,938 1993 175 178

summer 1992 summer 1994 winter 1993 summer 1993

ERCOT . . . . . . . . . 0 0 1984-93 582 709

winter 1986 winter 1989

summer 1987

IvIAAC . . . . . . . . . . 0 0 1984-93 107 1,582

winter/ winter/

summer 1993 summer 1984

MAIN . . . . . . . . . . . 1985-93 65 536 1984 42 462

summer 1993 winter 1989 winter 1984 summer 1984

MAPP (U. S.) . . . . . 1984-92 354 658 1984-93 327 556

winters winter 1984 winter 1986 summers summer 1987 summer 1993

NPCC (U. S.) . . . . . Winters of 1991, 81 101 1984-93 77 1,747

1992, 1993 winter 1991 winter 1993 winter 1990 summer 1985

SERC . . . . . . . . . . . 1984-89 300 1,540, summer 1984; 200 1,300

winter summer summer 1985 winter 1984 1989-93 winter 1989- winter 1992

winter 1991

SPP . . . . . . . . . . . . 1992-93 240 539 1984-92 226 1,017

summer 1993 winter 1993 winter 1984 summer 1987

Wscc (Us.) . . . . . 0 0 1984-93 183 610

winter 1984 winter 1983

estimates are based on 1980 data; the study projects that 47,435 MW in addition to the 39,348

MW presently available will be available by the

year 2000.22

While some utilities consider the anticipated

impact of power from nonutility generators in

their demand forecasts, capacity plans, and other

data submitted to NERC for preparation of its annual reports, many others do not. This results in

inconsistent treatment and probable underrepresentation of these potential resources by the

NERC projections cited in this chapter.

Resource Availability

Regional differences in resource availability will

define the range of opportunity for many new

technologies considered in this assessment.

As figure 7-9 illustrates, geothermal development is expected

west and Hawaii

ZI Dun & Bradstreet Technical Economic Services and TRW Energy

Development Group, /ndustria/ Cogeneration Potentia/ (1980-2000)

for Application of Four Commercially Available Prime Movers at

the Plant Site, Final Report, 1984. 221 bid.

to be co~fined to the South-
200 ● New Electric Power Technologies: Problems and Prospects for the 1990s

Table 7.7.–Estimated Maximum Industrial Cogeneration Potential Available as of 1980

by the U.S. Department of Energy, April 1985.

Figure 7-9.— Major U.S. Hydrothermal Resources

Reproduced from R L. Smith and t-i. R. Shawl U.S. Geological Su’wey

Circular 76, 1975.

While the wind resource is strong in the West

(WSCC) and most of the development to date has

occurred there, the resource is promising in many

other areas, including parts of ERCOT, MAPP,

NPCC, and SPP (figure 7-10).

“incompatible” land uses may limit the landintensive wind and solar technologies, especially

in areas where a high premium is placed on visual

esthetics (see the earlier discussion on licensing

and permitting). In densely populated regions

such as NPCC, development of these technologies may be more affected by land availability

rather than by resource availability, For example,

solar electric development will be particularly

constrained in heavily populated areas where insolation levels require high acreage per kilowatt

of power production. Figure 7-1 Iillustrates the

national solar resource .23

While land availability constraints may limit

solar and wind development, these same constraints are expected to augment the attractiveness of fuel cells and batteries in urban areas. Resources for CAES development are available in

all regions, as illustrated in figure 7- I 2.

Regions projecting continued and/or expanded

emphasis on coal generation (especially ECAR,

MAIN, MAPP, and SERC) will be likely candidates

for AFBC and IGCC development (see table 7-4).

ZJSolar availability i n the United States varies by close to a factor

of 2 between the Southwest, on the one hand, and the Northwest

and Northeast on the other.
Ch. 7—Regiona/ Differences Affecting Technology Choices for the 1990s • 201

Figure 7-10.—Average Annual Wind Power (watts per square meter)
202 ● New Electric Power Technologies: Problems and Prospects for the 1990s

1

,400

Figure 7.12.—Geological Formations Potentially Appropriate for Compressed Air Energy Storage
Ch. 7—Regiona/ Differences Affecting Technology Choices for the 1990s • 203

REGIONAL FUEL AND TECHNOLOGY RELIANCE24 PROFILES

East Central Area Reliability

Coordination Agreement (ECAR)

In anticipation of a

2.4 percent regional

annual growth rate

in summer peak demand, ECAR is projecting a 14 percent PENNSYLVANIA

increase in its 1983

installed capacity INDIANA

levels by 1993.25 The

region relies heavily

on coal (93 percent

of 1984 electricity

generation) and is expected to continue this reliance well into the 1990s. Present constructior~

plans also project a substantial increase in dependence on nuclear energy, from 7 percent of total generation in 1984 to 13 percent in 1993.26

There is a possibility that several of these nuclear

plants will not be completed on schedule; member systems have already had to cancel four nuclear units27 (3,600 MW) which were well along

in construction. Two of these (Midland 2 and

Zimmer 1) are among the costliest plants in the

count ry.28

Assuming completion of presently planned

units (i. e., as of the 1984 14th Annual NERC report), ECAR’s 1993 reserve margin is currently

estimated at 32 percentzg—well above traditional

measures of adequacy, According to the region’s

1984 annual report, of the units planned and/or

currently under construction, five nuclear units

(5,1OO MW) scheduled for completion by 1988,

nine combustion turbines (735 MW) and three

Z 4 A ]I of the NERC regio~al maps included in this section are

reprinted with permission from NERC, 14th Annual Review, op.

cit., 1984.

Z5H ;Storically, ECAR has been winter peaking, but the region is

expected to be summer peaking from 1984 on.

ZGN ERC, 14th Artrrua/ Review, op. cit., 1984.

z7Marble Hill I and 2, Midland 1, and Zimmer 1.

28According t. ~~&5 (James Cook, “Nuclear Follies, ” ~~~bes,

vol. 135, No. 3, Feb. 11, 1985, pp. 82-100), the cost per installed

kilowatt at Midland 2 was $4,889, and the cost per kilowatt at Zimmer 1 was at $3,827, compared with an $1,180 cost per kilowatt

at Duke Power’s McGuire 2 plant.

291xx, .E/ectrjc power Supply and Demand for the Cmtkwous

United States, 1984-1993, op. cit., 1984.

coal plants (1 ,550 MW) scheduled for completion between 1989 and 1993 may not be finished

on schedule, raising some questions about adequate reserves at the end of the decade if demand

grows as expected. If these plants are completed

on time, 1993 projections for adjusted reserves

(4.6 percent) fall slightly below suggested reliability criteriaso (see table 7-4), while reserve margin estimates remain well above 20 percent. As

figure 7-3 suggests, the national high demand

growth scenario could lead to reserve shortfalls

in the region, while lower demand scenarios

leave ECAR with a sizable capacity surplus.

ECAR’s heavy dependence on coal makes it

particulady vulnerable to the cost of more stringent acid rain regulations. Plant derating, retirement of older units which cannot be economically retrofitted, and increased down-time from

maintaining additional flue gas desulfurization

equipment could create a need for additional capacity, depending on the emissions reductions

required, the age-mix of the plants affected, projected electricity demand in the area, and related

factors. Concerns regarding these regulations are

expressed in the annual NERC reports for all the

coal-dependent regions.31

ECAR is characterized by moderate levels of

both intraregional and interregional transfers, including power imports from Canada. Within the

region, these transfers are due to load diversity;

inter-regional sales are economy transfers displacing costlier fuel, especially i n the MAAC region.

The region is expected to be a net exporter through

the early 1990s,32 ECAR’s current transmission

system is being used close to its limit; 1,800 miles

of new line are under construction to strengthen

the region’s overall transfer ability.33

301 bid,

II NERC, 14th Annual Ret<iew, op. cit., I %x.

32 Dc)E, E/ectric power Supply and Demand for the Contiguous

United States, 1984-1993, op. cit., 1984.

33NERC, 14th AnnUa/ I?ev;ew, op. cit., 1984; and EIA, /nteruti/ity

Bulk Power Transactions, op. cit., 1983.
204 ● New Electric Power Technologies: Problems and Prospects for the 1990s

Electric Reliability Council

of Texas (ERCOT)

Demand is expected to grow at an

average annual rate

of 4 percent i n

ERCOT over the

next decade—the

highest growth rate

of all the NERC regions. Member utilities depend heavily

on gas (60 percent of

total electricity generation in 1984; ‘projected to decrease to 35 percent in 1993); they are planning to decrease this

dependence by building several thousand megawatts of new coal/lignite and nuclear capacity. 34

Present utility capacity plans call for a 40 percent increase in installed capacity over 1983

levels by 1993 (see table 7-4). Even with this

construction, ERCOT may approach or fall below

several suggested reliability criteria within the

next decade if present demand predictions prove

to be accurate. For example, the adjusted reserve

margin is projected to fall to 4.3 percent as of 1991,

and the installed reserve margin is expected to

fall below 19 percent from 1990 through 1993.35

Figure 7-3 suggests the region may experience large

capacity shortfalls relative to other regions under

all but the lowest national growth scenarios.

power from cogenerators could offset possible

shortfalls in the region, since potential contributions from cogeneration may be inadequately reflected by current utility resource plans. While

the present industrial cogeneration potential in

ERCOT is estimated at 5,110 MW,36 the cogeneration capacity additions shown in the region’s 1984

report total 885 MW for the 1984-93 planning

period; total capacity contributions from “other”

sources for 1993 is estimated at 4,862 MW—this

figure includes conservation, load management,

energy from refuse, and other undesignated

JAN ERC, 14th Annua/ Review, op. cit., 1984.

3SDOE, E/ectric power supply and Demand for the Contiguous

United States, 1984-1993, op. cit., 1984.

JbDun & Bradstreet and TRW, /ndustria/ Cogeneration pOtent;a/

(1980-2000), op. cit., 1984.

sources as well as cogeneration .37 I n response to

the large cogeneration resource in-state, the

Texas utilities commission recently ordered one

Texas utility to show cause why several planned

lignite-fired plants should not be decertified in

light of potential capacity from cogenerators.ga

Whether or not the full cogeneration potential

in ERCOT is realized will depend to a large extent on relative economics; it is likely that cogeneration will be one of the major supply options

with which new power generating technologies

will have to compete.

Imports from other regions are expected to play

an increasing role in ERCOT. Historically, there

have been large amounts of interchanges among

ERCOT member systems, mainly for emergency

purposes, but ERCOT has been relatively isolated

from other regions. Lines are presently under construction to link ERCOT systems with SPP and better integrate remote generating sources within

ERCOT.39 The region is expected to be a net importer for the next decade (see table 7-6).

Mid-Atlantic Area Council (MAAC)

MAAC utilities rely

predominately on

nuclear and coal- -

fired generation. By

1993, n u c lea r’s

share of total generation is expected to

jump from 28 to 45 MAAC

percent, while coal’s

share of generation

will drop about 10 percentage points.40 According to a recent NERC report, the “comparatively

J7N ERC, j4th Annua/ Report, op. cit., 1984; and N ERC, Electric

Power Supply and Demand, 1984-1993, op. cit., 1984.

JBAt a recent conference on utility applications for renewable technologies, the vice president of Houston Light and Power noted this

fact and also remarked that “We have had 1300 MWe (of cogenerated power) thrust on us over two years. ” In addition, in 1984 when

the company sought to add 300 MW from third-party producers

to boost its reserve margin to 20 percent, cogenerators offered 1,275

MW. (Sources: RE1/EEl Conference, op. cit., November 1984; and

“Developers, Utilities, Lay Out Their Arguments, ” So/ar Energy /rrte/ligence Report, Nov. 19, 1984, p. 365).

WNERC, 74th Annua/ Review, op. cit., 1984; and EIA, lnteruti/-

ity Bulk Power Transactions, op. cit., 1983.

40N ERC, E/e~rjc Power Supply and Demand, 1984-1993, op. cit.,

1984.
Ch. 7—Regiona/ Differences Affecting Technology Choices for the 1990s • 205

weak financial position of some electric utilities

in the Region may force decisions to reduce capital expenditures, which will delay the service

dates of generating units under construction."41

Two units (one nuclear, one oil-fired) have already been delayed (the nuclear unit by 2 years,

from October 1988 to April 1990; the oil unit from

June 1992 to beyond the 1984-93 planning period).

MAAC planners cite reduced demand forecasts

and financing problems as the major reasons for

the delays.

Presently, annual demand growth is predicted

to remain at 1.3 percent and reserve margins are

expected to be adequate through the early 1990s.

As figure 7-3 illustrates, given present construction plans, reserves would fall below 20 percent

only u rider the 4.5 percent national growth scenario. of course, further plant delays (or unexpected changes in demand growth) could change

this situation. The region is already taking maximum possible advantage of economy power

transfers from neighboring regions, notably ECAR

and SERC; transmission limitations are expected

to keep these levels below the amount MAAC

utility systems would prefer. These factors may

create an attractive climate for short lead time,

new technologies if those technologies are economically competitive at the time a need for additional power is recognized.

While only 7 percent of the electricity generated in 1984 in MAAC was expected to be oilfired (decreasing to 4 percent by 1993), oil and

gas comprise nearly 52 percent of MAAC’s1984

installed capacity and will probably account for

44 percent in 1993.42 Oil is the region’s “swing”

fuel: if circumstances delay construction or in

some way impede use of the region’s coal and

nuclear capacity, or if demand increases substantially faster than expected, oil use will increase.

In that case, oil costs will strongly influence the

relative economics of alternative generating options.

Like other coal-using regions, MAAC is vulnerable to changes in present environmental regulations. Regional planners note that, if present regulations are substantially tightened, the impact

on some of the area’s older coal plants could af4 I N ERC, r#th Annual Review, op. cit., 1984, P. s 1.

42 N E RC, 7 qth A nnua/ Review, op. cit., 1984.

feet overall system reliability, because some units

might have to be retired and the output of others

would be substantially reduced. This could create a need for additional power sources—another

potential opportunity for new technologies.

Nuclear power is another important issue in the

region. In particular, developing sufficient awayfrom-reactor storage facilities for radioactive

wastes is a concern for some MAAC utilities

which face shortages in onsite storage facilities

at some of their older nuclear plants.43I n the long

run, this too may affect technology choices in the

region.

Mid= America Interpool Network (MAIN)

MAIN expects its

installed capability

to exceed 1983

levels by 22 percent

in 1993; this construction level is

based on a predicted

demand growth rate

of only 1.8 percent.

The region presently

relies heavily on coal

(68 percent of total

electricity generation in 1984) and nuclear power (29 percent). By 1993, coal

is expected to decrease to 56 percent

MICHIGAN

of total electricity generated by electric utilities

in the region, while nuclear’s share is expected

to increase to 41 percent.44

Given their emphasis on coal generation, the

region’s utility systems are sensitive to changes

in air emissions regulations. Potential construction delays could also be a problem—85 percent

of all of the plants presently under construction

in MAIN are nuclear; seven new units are planned

to come into commercial service between 1984

and 1987.45 Delays would be especially important in light of projected reliability criteria for the

431 bid.

441 bid.

4Jlbid.
206 •New E/ectric Power Technologies: Prob/ems and Prospects for the 1990s

Mid-Continent Area Power Pool

(MAPP-U.S.)

The U.S. members

of MAPP presently

rely on coal and nuclear power for the

bulk of their electricity generation—20

percent nuclear, 66

percent coal; hydroelectric power supplies 14 percent.

MAPP is expected to

continue its reliance

on these technologies through the 1990s. While

oil and gas accounted for less than 1 percent of

total generation in 1984 and are expected to supply about the same in 1993, installed nuclear capability in the region is expected to exceed oil

and gas by less than 2 percent during the same

time period. so This makes oil and gas “swing

fuels” in the region, with all the associated implications for avoided cost rates.

Demand growth is predicted to increase at an

average annual rate of 2.4 percent over the next

10 years; utilities within the region are planning

an 11.5 percent increase in capacity levels by

1993. 51 DOE projections of reserve margins

(which assume scheduled completion of all units

planned as of the end of 1983) indicate the region may fall below traditional reliability criteria

in the late 1980s and early 1990s (see table 7-4).

In addition, figure 7-3 suggests shortfalls of the

20 percent reserve margin under all but the lowest national demand growth case. Since construction has not yet begun on roughly 50 percent of

the plants scheduled to come on line afier 1989,5

system reliability concerns may create a window

of opportunity for short lead-time technologies

in the region.

50NERC, Electric Power Supply and Demand, 1984-1993, op. cit.,

1984; and NERC, 14th Annual Review, op. cit., 1984.

JINERC, E/ectric Power Supply and Demand, 1984-1993, op. cit.,

1984.

52N ERC, ldt~ Annua/ Review, op. cit., 1984.
Ch. 7—Regional Differences Affecting Technology Choices for the 1990s •207

MAPP members echo the concerns of other

coal-reliant systems regarding the potential impact of more stringent air quality controls. Besides

impeding overall reliability, increasing maintenance needs, and spurring “premature” plant

retirements, they think retrofits could also lead

to higher electricity costs for consumers. 53

While MAPP’s member utilities will not be

increasing their reliance on nuclear power, storage of spent fuel from existing plants is a concern for the 1990s because onsite storage capacity will be fully used by that time. If national

nuclear waste repositories for away-from-reactor

storage are not available, some member systems

expect they may have to reduce generation from

their nuclear units.sq As in MAAC, this could create further need for new capacity.

The U.S. members of MAPP are summer peaking; its Canadian members are winter peaking.

MAPP’s U.S. members import power from its

Canadian members, exchange power with neighboring council such as MAIN, and engage in a

substantial amount of intraregional transfers available due to load diversity within the region.

Studies are now underway regarding the feasibility of increasing the region’s ability to import

hydroelectric power from Manitoba into Minnesota and Wisconsin, and the Dakotas. 55Given the

usual economic attractiveness of such transactions, imports could emerge as a more costeffective supply option than competing generating technologies if MAPP’s import capabilities are

increased.

’31 bid.

5A! bid.

55EIA, /nterut;/;ty Bulk power Transactions, op. cit., 1983; and

NERC, 14th Annual Review, op. cit., 1984.

Northeast Power Coordinating Council

(N PCC-U.S.)

More than 50 percent of installed capacity in NPCC is oilfired. Oil accounted

for 38 percent of

total generation in

1984; it is expected

to account for 21

percent in 1993,

Nuclear units ac- NEW YORK

. .

counted for 16 percent of 1984 capac- NPCC-U.S.

ity and are expected to represent 23 percent by

1993 (23 percent and 38 percent of total generation, respectively), while coal-fired units accounted for 1 1 percent of 1984 capacity and are

expected to contribute 17 percent by 1993 (18

and 27 percent of generation, respectively). 56

Decreasing the region’s heavy dependence on

oil hinges on completion of several new coal and

nuclear units ranging in size from 800 to 1,150

MW. Some of these plants have proven quite

controversial. For example, two of NPCC’s nuclear units—Shoreham and Seabrook l—are

among the most expensive plants in the country, with installed costs of $5,192 and $3,913 per

kilowatt, respectively .57 increased electric rates

associated with bringing these plants into the ratebase could run as much as 53 percent for Shoreham (Long Island Lighting Co.’s service area)

and 63 percent for Seabrook I (for Public Service of New Hampshire’s customers) .58 If demand

growth continues as predicted (1.7 percent) and

if some of these new plants are not completed

and brought into service during the 1985-90 time

period, the opportunities for new technologies

will depend to a large extent on their competitiveness with new oil-fired, conventional units.

(As discussed below, imports from Canada are

not likely to be able to fill the resulting demand

for power.) Given the high population density of

many NPCC States, modular technologies which

JGPJERC, E/e~riC Power Supply and Demand, 1984-1993, op. cit.,

1984.

J7Cook, Op. cit., Feb. 11, 1985.

Jalbid.
208 . New Electric Power Technologies: Problems and Prospects for the 1990s

are not land intensive might prove the easiest to

site.

Cancellation of currently planned facilities

could also adversely affect reliability criteria

within the region. Given present plans to increase

generating capability 14 percent over 1983 levels

by 1993, it is expected that the systems within

NPCC will meet traditional reliability measures

into the 1990s. But problems are anticipated in

mid-decade if these units are not brought on line,

peak demand growth substantially increases beyond present forecasts, and/or presently operating nuclear units are not kept in operation,

On the other hand, if currently planned units

come into service as scheduled, figure 7-3 suggests a shortfall of the 20 percent reserve margin

in the early 199os only under the 4.5 percent national demand growth scenario.

NPCC systems import power primarily from the

Canadian NPCC systems and ECAR. Reliance on

oil makes economy transfers especially attractive

to NPCC members, but the demand for such

transfers exceeds existing, under construction,

and planned transmission capacity both within

the United States and between NPCC’s U.S. and

Canadian members. Present economy energy

transfer levels leave little capacity for emergency

flows; if emergency transfers are needed, economy transfers will be reduced. Even NPCCs coal

burning utilities buy economy power when possible, since they have large loads and heavy peaks

which must otherwise be met with oil-fired steam

and peaking units. 59

WEIA, /nterutj/jty Bu/k Power Transactions, op. cit., 1983; NERC,

14th Annual Review, op. cit., 1984; and DOE, Electric Power Supply and Demand for the Contiguous United States, 1984-1993, op.

Southeastern Electric Reliability

Council (SERC)

SERC is characterized by a diverse fuel KENTUCKY

base which encourages heavy intraregional economy

transfers as well as

exchanges with interconnected systems in neighboring

ECAR and SPP.bO Re- MISSISSIPPI

gionwide, coal and

nuclear plants ac- SERC

counted for 68 percent of 1984 installed capacity and 87 percent

of total generation; 1993 projections call for continuation of these patterns,bl

Twenty-two percent of the capacity in SERC is

oil- or gas-fired. While these plants accounted for

only 7 percent of total generation in 1984, this

pattern varies markedly, with Florida’s installed

oil/gas capacity exceeding levels in the other

SERC subregions by a factor of 5 or more.bz

Florida’s reliance on oil and gas accounts for substantial intraregional economy transfers from

other members of SERC, although transmission

capacity constraints are limiting otherwise desirable transfers from hydroelectric and coal-fired

generators in Alabama and Georgia.63

While Florida plans to decrease gas generation

in 1993 to slightly less than 50 percent of 1984

levels, oil generation is expected to increase by

4 percent. The overall region is following a similar but less pronounced pattern; gas generation

as a percent of total electricity generation is expected to decline by about 2 percent while oil

generation increases about 1 percent.64 Oil and

gas costs and the availability of intraregional and

60EIA, /nterutj/jty Bulk Power Transactions, op. cit., 1983.

61 N ERC, IJth Annua/ Review, op. cit., 1984.

GZSixty.seven percent of 1984 installed capacity and 35 percent

of total generation in Florida was oil- or gas-fired; by 1993, this is

projected to decrease to 57 percent of capacity and 31 percent of

generation.

GJN ERC, 14th Annua/ Review, op. cit., 1984; and EIA, /nteruti/ity

Bulk Power Transactions, op. cit., 1983.

154 NERC, E/ectrjc Power Supply and Demand, 1984-1993, OP. cit.,

“cit., 1984. 1984,
Ch. 7—Regiona/ Differences Affecting Technology Choices for the 1990s ● 209

interregional power will continue to be important factors affecting the relative economics of

power supply alternatives in the region.

predicted average annual growth in summer

peak demand varies between SERC subregions

from 2.6 to 3.8 percent. Increased conservation

and load management, changing demand patterns, increased construction costs, and the addition of customer generation are cited by the

council as reasons for canceling or deferring construction on five nuclear plants and five coal units.

Current construction plans call for a 22 percent

increase over 1983 capacity levels by 1993. This

includes 23 coal units (average size 588 MW), 9

nuclear units, 13 pumped storage facilities (average size 207 MW), and 19 hydro units (average

size 40 MW).65 If all of these units are completed

on schedule, reserve margins in the area appear

more than adequate through the early 1990s. As

figure 7-3 illustrates, higher than expected demand growth (e. g., a national rate of 3.5 percent

or more) could create potential capacity needs

in the region and an opportunity for competitive

new technologies. Assuming continued utility

commitment to the plants now under construction, lower than expected growth could have the

opposite elffect.

Southwest Power Pool (SPP)

Average annual

peak demand growth

predictions for SPP’s

three subregions for

the 1985-93 p!anning period range

from 1.1 to 6.1 percent. overall, the region’s 1984 generating capability was

predominately oil,

SPP joins SERC as one of the only regions projecting an increase in reliance on oil for generation (from 4 percent in 1984 to 8 percent in 1993).

Actual and projected fuel reliance for electricity

generation in the region emphasizes coal, gas,

and nuclear fuels, with coal increasing from 51

percent in 1984 to 53 percent in 1993; gas decreasing substantially, from 36 percent in 1984

to 23 percent in 1993; and nuclear doubling from

7 percent in 1984 to 14 percent in 1993.67

Fuel reliance within SPP is variable between

subregions, encouraging intraregional transfers

from coal-reliant areas to those emphasizing oil

or gas. Both the Southeast and West Central subregions are heavily reliant on oil and gas, although both plan to decrease capability and generation from these fuels as a fraction of total

capability and generation by the 1990s.68

Member utilities in SPP are planning to increase

1993 installed capacity by 21 percent over 1983

levels. As figure 7-3 shows, these plans leave reserves above the 20 percent margin through 1993

u rider all but the high national growth scenarios

(i.e., 3.5 percent or more). The majority of these

new plants are coal or lignite (1 0,200 MW), but

more than half of them (about 6,000 MW) were

only in the planning stage as of January 1984. The

remaining new plants are nuclear (5,700 MW)

and peaking capacity (1, 100 MW, mainly combustion turbines). if all of these plants are completed on schedule, the region will still be dependent on gas and oil (i.e., 44 percent of total

planned capacity for 1993).69 Delays could create potential opportunities for new technologies.

671 bid.; and N ERC, 14th Annua/ Review, Op. cit., 1984.

bBFOr example, 73 percent of 1984 generating capability in the

Southeast subregion was oil- or gas-fired; 46 percent of total generation was from gas. In the West Central subregion, 51 percent

of installed capability was oil or gas in 1984; 43 percent of total

generation was from gas. By 1993, oil-gas capability as a percent

of total plant is expected to decrease to 56 percent in the Southeast subregion and 42 percent in the West Central subregion, with

generation from gas sources also decreasing. Dependence on oil

generation, while small, is expected to increase in both

subregions—from 11 to 17 percent in the Southeast, from 0,05 to

1.5 percent in the West Central. In contrast, the Northern subregion expects generation from gas to remain around 5 percent from

1984 through 1993, with oil generation less than 1 percent; installed

oil and gas capacity was 29 percent in 1984 and is projected at

25 percent in 1993. From NERC, E/ectric Power Supp/y and Demand, 1984-1993, op. cit., 1984.

69N ERC, 14th Annual Review, op. cit., 1984.
210 ● New Electric Power Technologies: Problems and Prospects for the 19S0s

As a hedge against possible oil and gas availability problems or price increases, member utilities are installing (or planning to install by the

early 1990s) several new transmission lines to take

better advantage of available economy power

transfers from SERC, ERCOT, MAPP, and WSCC.70

if new generating sources are needed, major factors affecting their comparative economics will

include the price and availability of oil and gas,

the regulatory climate affecting the region’s coal

plants, and the degree to which the promising

cogeneration resource in Louisiana (see table 7-

7) has been tapped.

Western Systems Coordinating Council

(WSCC-u.s.)

Of ail the NERC

regions, subregional

differences in generation mix are most

pronou need in

WSCC, where there

are four separate

power pools–the

Northwest Power

Pool, The Rocky

Mountain Power

Area, the ArizonaNew Mexico Power

Area (ANMPA), and

the California-Southern Nevada Power

Area (CSNPA).

UTAH COLORADO

TEXAS

71 N ERC, Iqth Annual Review, op. cit., 1984, P. 58.

7ZNERC, E/@ric power Supply and Demand, 1984-1993, op. cit.,

1984; and NERC, 14th Annua/ Review, op. cit., 1984.

TIFor example, as of April 1985, Texaco and Chevron were each

proposing to erect 1,200 MW of cogeneration capacity in the heavy

oil fields in Kern County (total projected capacity of 1200 MW).

Source: Burt Solomon, “Paradise Lost In California, ” The Energy

Dai/y, vol. 13, No. 80, Apr. 26, 1985.
Ch. 7—Regiona/ Differences Affecting Technology Choices for the 1990s ● 211

western States in WSCC also import power from

the Pacific Northwest when it is available. Construction plans are underway to improve transmission capability within WSCC itself as well as

among it and SPP, MAPP, and MAAC to take better advantage of economy power transfers. ANMPA

members are especially interested in maximizing

use of available transmission facilities because

they are capacity rich and financially dependent

on selling surplus power to other WSCC members. Presently, there are insufficient facilities in

place to take full advantage of available economy

power transfers; in particular, transmission capability is insufficient to meet the demand for such

transfers into the California-Southern Nevada subregion and for transfers between the Rocky

Mountain and Arizona-New Mexico subregions.74

Predicted demand growth varies dramatically

between WSCC subregions, with the predicted

average annual increase in summer peak demand

ranging from 1.9 percent (CSNPA) to 4.4 percent

(ANMPA). If only 65 percent of the capacity presently planned to come on line in 1993 (41 percent coal and 34 percent nuclear) is actually built,

member utilities expect that, while some reliability criteria may not be met, overall resources

will be adequate as long as demand does not increase faster than currently projected.75

Alaska Systems Coordinating Council

(ASCC)

Most of Alaska’s population (i.e., 75 percent)

resides in the “Rail belt” area stretching between

Seward, Anchorage, and Fairbanks. Electricity in

this region is provided primarily by indigenous

natural gas, supplemented by coal, oil, and

hydropower. The Railbelt is the only subregion

interconnected by a common grid. If pending

license applications with FERC for two hydropower projects are approved (Bradley Lake–90

MW, and Susitna–1 ,600 MW), ASCC expects the

subregion will have sufficient capacity to meet

expected demand past the year 2000.76 It is

74N ERC, T4th Annua/ Review, op. cit., 1984; and EIA, /nteruti/ity

Bulk Power Transactions, op. cit., 1983.

Z5NERC, ]4th Annual Review, op. cit., 1984.

761 nformationprovided to OTA by the Alaska Systems Coordinate ng Cou ncll (ASCC), a N ERC affiliate, personal communication,

May 1985.

doubtful that capacity credits for akernative technologies wou Id be available in the near term unrider this scenario; the Railbelt’s projected 1985

peak is 717 MW; the 1990 peak is expected to

be 918 MW.77

While the technical and environmental concerns surrounding the Susitna Project appear resolved, its size and cost are controversial. In response, the State is proposing to build the project

in stages, starting with 500 MW and eventually

upgrading the facility to 1,600 MW.78 FERC is not

expected to make a licensing decision until sometime in 1986.79

The ASCC expects greater development of the

Railbelt’s indigenous coal reserves if Susitna is not

approved, creating a potential opportunity for

new coal technologies. In addition, there are

pending applications for waivers of the Fuel Use

Act’s natural gas generation prohibitions to allow

Railbelt utilities to take greater advantage of the

State’s natural gas reserves.

Southeastern Alaska is served primarily by Federal and State hydropower projects. The rest of

the State—consisting of widely dispersed villages

(the “bush’ ’)-obtains electricity from dieselfueled generators. Access to many of these areas

is difficult. The bush subregion appears to offer

the best development potential for dispersed

electric generating technologies in Alaska. Of the

technologies considered in this report, wind turbines appear among the likeliest candidates.

There also has been some development of photovoltaics (PV) in remote areas, and hybrid systems

linking wind or PV with battery storage may prove

attractive. For any new technologies considered

for electricity generation in the bush, project econom ics will be strongly influenced by the Power

Cost Equalization Program.

Diesel fuel costs in the bush are high, resulting in electricity costs of up to $1 /kWh in some

areas (e.g., where fuel has to be flown in). Electricity costs from 35 to 50 cents/kWh are typical.

Under the Power Cost Equalization Program,

these costs are subsidized by the State, so that

zzlbld.

781 bid.

79Vic Reinemer, “Electrifying Alaska, ” Pub/ic Power, NovemberDecember 1983, vol. 41, No. 6, pp. 10-19.
212 ● New Electric Power Technologies: Problems and Prospects for the 1990s

village residents pay only a small fraction (in some

instances, less than 9 cents/kWh for the first 75o

kWh used each month) of the production cost

of electricity.BO The program is funded by royalties from oil sales.81

Outside of the comparative cost issues raised

by present implementation of this cost equalization program, the main constraint on extensive

wind development appears to be the absence of

a grid allowing power transfers among villages

and from dispersed sources to the State’s major

load centers. Obtaining third-party financing for

small facilities could also be a problem, although

the State has shown willingness to help facilitate

new projects .82

Technical issues affecting wind development

in the State include the substandard installation

of many of the village diesel generator systems

(e.g., systems with transmission lines running on

the ground covered with wood boxes and/or

generators housed in plywood structures susceptible to fire).83 Gaining access to remote areas for

construction and/or maintenance could also be

a problem84 for wind as well as any other technology.

The Alaska wind resource is especially attractive along the coast. The solar resource is strong

but subject to extreme seasonal variation: in late

winter, daylight is only available for 4 hours; in

midsummer, light is available for about 20 hours.

Geothermal resources are available on the Aleutian Islands, but there is no power transfer capability, either existing or planned, to transfer electricity from this area to the State’s load centers,

making substantial development of this resource

for electricity generation unlikely.

sOFor the first i’SO kWh used each month, the State picks uP anY

additional charge above 8.5 cents, and below 52 cents, per kWh.

Source: Information provided to OTA by Kinetic Energy Systems,

an energy firm in Anchorage, AK personal communication, May

1985.

al I nformation provided to OTA by Polarconsu h, an energy @Chnology consulting firm i n Anchorage, AK, personal com mu n ication, May 1985.

Bzlbid.

831 bid.

841nf’ormation provided to OTA by Independent Energy producers, a California-based alternative technology trade association, personal communication, May 1985.

Hawaii

The State of Hawaii is a chain of islands in the

Hawaiian Archipelago. Most of the State’s businesses and residents are on Oahu in or near Honolulu, the State capital. Oahu accounts for about

80 percent of Hawaii’s peak electricity demand.

The State is served by a handful of investorowned electric utilities relying almost exclusively

on oil-fired capacity (99 percent of utility-owned

generation in 1983 was oil-fired).85 This generation is supplemented by seasonal purchases from

third-party producers, most of which are sugar

processing facilities cogenerating electricity from

boilers fueled with bagasse, the pulpy residue

from processing sugar.86 Sugar is the State’s main

agricultural crop.87 For approximately 48 weeks

each year, firm power contracts from bagassefired cogeneration provide about 20 MW on the

Big island (expected 1985 peak demand for the

island: 99 MW), 20 MW on Maui (expected peak

demand: about 102 MW), and 15 MW on Kauai

(expected peak demand: 40 MW). Oahu, with

an approximate peak demand of 949 MW, has

no power from these sources. 88

Power contributions from sugar processors are

not expected to increase substantially over the

next decade due to economic uncertainties in the

industry. 89 Significant increases in power contributions from other biomass fuels are not expected. 90

While the islands are too new geologically to

have indigenous fossil fuels and there are no

known offshore oil reserves nearby, Hawaii has

abundant renewable and geothermal resources.

A recent study predicts that, by 2005, indigenous

6tEdiSon Electric ] nstltute (EEI), s~a~jS~jCd/ Year~oo& of ~~e E/eC.

(ric Uti/ity /ncfustry/1983 (Washington, DC: EEI, 1984).

.96Many sugar plantations also generate hydroelectric Power, but

this is used mainly onsite for irrigation.

BzThe sugar industry accounts for 80 percent of the jobs on the

neighbor islands to Oahu. Source: Hawaii /ntegrated Energy Assessment (HI EA), vol. I, prepared for U.S. Department of Energy by

the Department of Planning and Economic Development, State of

Hawaii; and Lawrence Berkeley Laboratory, University of California at Berkeley, June 1981.

aBThese peak demand figures are estimates for 1985 provided to

OTA by the Hawaiian Electric Power Co., Inc., in June 1985.

w! “formation provided to OTA by the Hawaiian Electric power

Co., Inc., May 1985.

90 HIEA, Op. cit., 1981.
Ch. 7—Regiona/ Differences Affecting Technology Choices for the 1990s . 213

renewable resources could provide 90 percent

of the island’s electricity; each county has developed an energy plan aimed at decreasing dependence on imported fuels within cost and environmental constraints 91

The State’s solar resource is strong and consistent; the average insolation rate is higher than

that of the mainland United States and there is

also less seasonal variation. 9z Hawaii’s wind resource is similarly promising; the northeast trade

winds blowing across the islands offer one of the

most consistent wind regimes in the world. Hawaiian Electric Renewable Systems, I nc.,93 is installing fifteen 625-kW wind turbines on Oahu;

these are scheduled to come on line by the end

of 1985. There are also about 3 MW of wind capacity operating intermittently on the Big Island

of Hawaii .94 The State may also be the site of a

DOE demonstration project for a multi-megawatt

wind turbine (MO D-5 B).

Most of Hawaii’s energy resources are located

far from the Oahu load center. High-temperature

geothermal reserves are a case in point: the Puna

resource on the Big Island of Hawaii is considered extensive enough to fulfill most of the State’s

power needs for decades to come.95 However,

presently there is no means of transferring power

from the Big Island to oahu. This lack of transmission capability is the single biggest impediment to development of the islands’ indigenous

energy resources.

Development of an interconnected power

transfer system hinges on successful design and

installation of an undersea transmission cable capable of withstanding greater pressures, and extending greater distances, than has been attempted before. To date, submarine cables have

not been installed below a depth of 1,800 feet

and the longest distance a submerged cable has

9’ Ibid.

‘zJc.hn W, Sh u pe, “Energy SeIf-Sufficiency for Hawaii, ” science,

vol. 216, june 11, 1982, pp. 1193-1199,

93A Subsldlary of Hawaiian Electrlc Power Co. ’s parent company,

Hawaiian Electrlc Industries,

WI n(ormatlon Provided tO OTA by Hawa(la n Electric power CO.,

lnc,, May 1985.

gjH/EA (op. cit., 1981, p. 41) estimates the Puna resource at 100

to 3,000 MW centuries; other sources estimate It at 1,000 to 5,000

MW (information provided to OTA by Hawaiian Electric Power Co.,

Inc., May 1985).

covered is 80 miles. A cable linking Hawaii with

oahu would be submerged in a 150-mile wide,

7,000-foot deep channel (the Alenuihaha Channel). 96 One source estimates construction costs

at anywhere between $250 and $600 million; this

excludes the cost of research and development,

which has been funded primarily by Federal

sources.g7 Whether or not the cable will ultimately prove feasible, or affordable, has not been

demonstrated. The research phase is expected

to be finished in the late 1980s.98

Hawaii’s dependence on imported fuel provides a strong incentive to develop its energy resources.gg Solar, wind, and geothermal technologies are the most likely to be extensively

developed; 100 batteries or fuel cells might offer

some advantages but might be seen as undesirable if they continued the State’s dependence on

shipped-in fuels or materials. Switching to coalfired technologies currently is unlikely given the

land requirements for solid waste disposal, the

resulting air quality impacts, and the lack of indigenous coal resources.

Load management is not a particularly attractive option for Hawaiian utilities since there is little incremental cost difference between their oilfired generating units and there are no opportunities for off-peak, lower cost power purchases

from neighboring facilities. System load factors

have continued to improve since 1979, however,

due to decreased electricity demand.101 Load

growth is expected to be minimal on Oahu; the

—...— 9GHIE,.4, Op. cit., 1981.

971 nformatio n pro~rided to (~TA by the Hawaiian Electric Powrer

Co., Inc., May 1985.

gecable feasibi I Ity studies are progressing; a tentative cable design has been selected, test protocol are being developed, and the

requirements of handl I ng I i ne installation and maintenance at sea

are being studied.

‘WAS of 1984, the State’s average residential electricity rates were

the highest in the United States (i.e., 11,4 cents/kWh based on 75o

kWh): Energy Information Administration, Typica/ Electric 6;//s, January 7, 1984 (Washington, DC: U.S. Department of Energy, December 1984), DOE/E lA-O040(84). Residential rates vary substantially between the islands; e.g., in 1982 electricity cost were 11.4

cents/kWh in Honolulu (Oahu), while rates on Molokai were more

than 19 cents/kWh (Shupe, op. cit., 1982).

IOOpotentlal contributions from OTEC systems may be substantial in the long run, but the technical and economic issues associated with this technology make it an unlikely candidate for development in the 1990s,

101 Information pro~,ided to OTA by the Hawaiian Electric Power

Co., Inc., May 1985.
214 • New Electric Power Technologies: Problems and Prospects for the 1990s

neighboring islands may experience 2 to 5 per- Development of the land-intensive solar and wind

cent annual growth, but this is from very small technologies to meet the State’s electric power

peak demand levels to begin with. 102 needs will definitely be affected by these factors.

The State’s economy is heavily dependent on But the lack of transmission capacity between the

tourism and agriculture. Land values are at a islands poses the most immediate impediment to

premium, and Hawaii has strict zoning laws to substantial development.

protect its agricultural and recreational lands.103

102E5timateS provided to C)TA by the Hawaiian Electric power CO.,

Inc., May, 1985.

103H/EA, op. cit., 1981

SUMMARY OF MAJOR REGIONAL ISSUES

Demand Uncertainty

Future electricity demand and the inherent uncertainty associated with estimating it are two of

the most important factors affecting utility choices

between electricity supply options. Predicted

electricity demand growth rates differ dramatically within and among regions, and unanticipated changes in these predictions could substantially affect both overall system reliability and the

need for new generating capacity. Traditional

reliability measures such as generating reserve

margins are very sensitive to demand predictions.

This sensitivity is especially high in regions where

substantial numbers of new coal and nuclear

plants are under construction. In the long run,

consumer reaction to the cumulative “rate

shock” associated with bringing such large plants

into the ratebase may increase utility commission

actions encouraging greater reliance on alternative supply options.

The 1993 capacity levels in four NERC regions

are expected to exceed 1983 levels by more than

20 percent; for three of these regions—ERCOT,

MAIN, and SPP—this entails an increase of more

than 75 percent in installed nuclear capacity. The

oil-dependent NPCC region will be increasing its

coal capability by similar percentages, although

its overail capability increase over 1983 levels will

be below 20 percent. If demand increases faster

than predicted and construction delays occur, reserve margins in some of these regions may be

adversely affected. If demand growth predictions

have been overestimated, construction plans may

have to be altered, with uncertain effects on the

financial status of the utilities affected.

Present and Projected Fuel Reliance

Capacity needs and the relative attractiveness

of available supply options are also strongly influenced by regional fuel and technology reliance, since these plant characteristics generally

establish the benchmarks for technology cost

comparisons. While most systems with substantial oil and gas capacity are expected to decrease

use of these fuels over the next decade, reliance

on premium fuels is expected to be strong enough

in ERCOT, MAAC, NPCC, and some subregions

of SERC, SPP, and WSCC that the economics of

competing technologies will remain very sensitive to the price and availability of oil and gas.104

This will apply even more strongly in the Florida

subregion of SERC, the Southeast subregion of

SPP, and the Arizona-New Mexico subregion of

WSCC where, due to predictions of high demand

growth and continued decreases in (or stabilization of) oil prices, reliability councils are forecasting increased dependence on oil. Regions characterized by heavy reliance on coal or nuclear

power will be vulnerable to changes in present

environmental regulations; the ultimate effect of

regulatory changes will vary between utility systems and may create the need for additional

power sources in some areas.

104TheSe fuelreliance projections are from N ERC, ~/ectr;c power

Supply and Demand, 1984-1993, op. cit., 1984.
Ch. 7–Regional Differences Affecting Technology Choices for the 1990s • 215

Plant Life Extension

Over the next several decades, the age of existing generating facilities is likely to influence the

need for new capacity because construction may

be deferred if scheduled retirement of aging powerplants can be delayed by plant rehabilitation

or efficiency improvements. Deferral prospects

vary considerably by region, By 1995, approximately 40 percent of the fossil steam generating

plants in MAIN, NPCC, and WSCC will be over

30 years old; many of these plants may be promising candidates for life extension. In terms of total

installed capacity, the opportunities for life extension will be greatest in ECAR, SERC, SPP, and

WSCC. In all regions, the degree to which this

option is exercised will be heavily influenced by

the comparative economics of other supply alternatives.

Other Key Variables

Opportunities for increased economy power

transfers between and within regions are found

to be attractive to a majority of utilities, but existing and planned transmission capacity will limit

these transfers.

The potential for cogeneration tends to be State

specific; opportunities are proving particularly

strong in the Gulf States, e.g., Texas and Louisiana, and in California. These systems will often

be in direct competition with the new technologies considered in this assessment.

Load management appears attractive in all regions, although peak reduction in oil-dependent

systems could prove counterproductive in the

long run if it defers replacement of costly peaking units.

Conservation is similarly attractive, although the

resource is both difficuIt to define and tap completely.

Land and/or energy resource availability constraints are expected to limit development of geothermal, wind and solar technologies in some

regions.

Utility economic and financial characteristics

are so variable within as well as among regions

that no clear regional generalizations are drawn.

Generalizations about regional regulatory characteristics prove similarly difficuIt, although the

policies of some innovative utilities commissions

are creating more favorable environments for

new technologies than might otherwise be the

case in their jurisdictions. In addition, given siting experiences to date, it seems reasonable to

expect that developers of new technologies may

experience permitting delays as localities adjust

the regulatory process to accommodate new

electric generating systems.

38-743 0 - 85 - 8
Chapter 8

Conventional v. Alternative

Technologies: Utility and

Nonutility Decisions
CONTENTS

Page

Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..............219

Utility Investment in Power Generation . . . . . . . . . . . . . . . . . . . . . ..................219

Overview . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ...........................219

Utility Decisionmaking. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .......219

Comparative Analysis. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .....................222

Utility Strategic Options. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 225

Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ...................227

Nonutility Investment in Power Generation . . . . . . . . . . . . . . . . . . . . . ...............228

Overview . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ................228

Historical Nonutility Generation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ....228

Current Nonutility Electric Power Generation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ...228

Characteristicsof Nonutility Producers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. ....229

Nonutility Investment Decisionmaking. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ......231

Comparative Profitability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .................234

Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .........................241

Cross-Technology Comparison . . . . . . . . . . . . . . . . . . . . . . .........................241

Overview . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..241

Cross-Technology issues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 243

Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ....245

Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..245

Appendix 8A: Investment Decision Cash Flow Models For

Cross-Technology Comparisons . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ........246

List of Tables

Table No. Page

8-1.

8-2.

8-3.

Typical Power Planning Functions . . . . . . . . . . . . . . . . . . . . . ...................221

Alternative Tax Incentives: Cumulative Effect on Real Internal Rate of Return. ....242

Cross-Technology Comparison: OTA Reference Systems . .....................244

List of Figures

Figure No. Page

6-1.

8-2.

8-3.

8-4.

8-5.

8-6.

8-7.

8-8.

8-9.

8-10.

8-11.

8-12.

8-13.

8-14,

8-15.

8A-1,

Technology Cost Range: Utility Ownership-West . .........................223

Base Load Technology Costs: Utility Ownership-West . .....................224

Peaking/Intermittent Technology Costs: Utility Ownership-West . .............225

Life Extension Costs: Sensitivity to Capital Cost . ............................226

Shortv. Long Lead-Time Analysis: Impacton Financial Health . ...............227

Survey Responses by Technology . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. ...229

Nonutility Ownership: Current and Projected Companies . ...................230

Survey Responses by Project Location . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. ....230

wind Farm installed Capacity Distribution . . . . . . . ..........................231

Initial Year of Generation: Currently Producing Companies . ..................231

Investment Risk Continuum. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .............234

Breakeven Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ......237

Breakeven Buy-Back Rates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. ...238

Technology Profitability Range: Nonutility Ownership-West . .................239

Tax Incentives for New Electric Generating Technologies:

Cumulative Effecton Real Internal Rate of Return... . .......................243

Calculation of Capital Cost per Kilowatt-Hour . .............................247
Chapter 8

Conventional v. Alternative Technologies:

Utility and Nonutility Decisions

INTRODUCTION

Deployment of the technologies addressed in

this assessment in the 199os hinges on investment

decisions made by both electric utilities and nonutility power producers. They are the primary

(and in some cases, the only) markets for these

new technologies. Their investment decisions will

determine the future commercial viability of the

technologies. Investment in these technologies

will only occur if they can compete with existing electricity-generating technologies. In addition, the new technologies will have to compete

amongst themselves for limited sources of capital.

This chapter focuses primarily on the process

of technology choice by utilities and nonutility

entities, and the relative economics of the various new generating technologies. The first and

second sections discuss these issues for utilities

and nonutilities. The third section provides crosstechnology comparisons on issues concerning

deployment, environmental impact, and ease of

siting. Emphasis in the latter section will be on

the nonquantifiable issues which cannot be addressed in cost and profitability calculations.

UTILITY INVESTMENT IN POWER GENERATION

Overview

Electric utilities in the United States are regulated to meet customer electricity demands at all

times with reliable and reasonable cost power.

If customer demand increases, sufficient generating capacity must be available. Utility planners

attempt to examine all options available to them

to meet this demand; traditionally, the least cost

option—or at least what was thought to be least

cost—has been the preferred option. Recent demand and operating cost uncertainties have

forced the consideration of other investment criteria, e.g., financial health, and has complicated

the traditional decision making process. This section focuses on electric utility decisionmaking

and, using the methodology of the utility decisionmaking process, compares new technologies

and load management with traditional utility options such as conventional pulverized coal-fired

plants and utility-owned combustion turbines.

Utility Decisionmaking

Electric utilities operate under a different set of

decision rules and constraints than other businesses (see box 8A for a brief description). I n return for the privilege to operate as a monopoly,

investor-owned electric utilities are subject to

government regulation of prices, profits, and service quality. ’ Because of this regulation, utilities

cannot maximize profit. For example, a utility

must install added capacity to meet increased de-

! Pu blicly owned utilities are also subject to governmental control and oversight of utility operations and finances. The source of

control can be municipal government, local entities, or the Federal Government. Since investor-owned utilities (IOU) account for

the majority of U.S. energy sales to ultimate customers (76

percent—see table 7-1 ), emphasis will be placed on IOU decisionmaking. Moreover, many publicly owned utilities, primarily

municipally owned utilities, are distribution-only utilities and do

not invest in powerplants. Nevertheless, these municipal utilities

will be very Interested in demand side alternatives, e.g., load management.

219
220 ● New Electric Power Technologies: Problems and Prospects for the 1990s

and, even though it may decrease profits.2 Electric utilities have a legal obligation to serve all the

demand of their customers at any time.3 Utilities

normally construct enough extra capacity to provide a reserve margin against the possibility of

being unable to serve customer load if a generating unit fails.

Utility decisionmakers also have obligations: 1)

to ratepayers to minimize their rate burden over

time, and 2) to their stockholders to maximize

the utilities’ financial health. The accepted means

of accomplishing this is to minimize costs within

reliability, regulatory, environmental, and financial constraints.4

Utility Planning Process

Electric utility decisionmaking on new plants

is a four-step process: load forecasting, generation planning, transmission planning, and distribution planning. Table 8-1 lists the different characteristics of these power planning functions. The

first step, load forecasting, determines the need

for additional plants. Typical forecasting techniques include time series analysis, econometric

modeling, and end-use models. In the past, utilities could rely on simple trend analysis to project

future demand based on past growth rates, e.g.,

7 percent a year. Recent unpredictable demand

growth, however, has made this method undependable and more sophisticated methods are

gaining wider acceptance.

Generation planning focuses on two important

questions: the capacity needed for adequate reserve margins and the mix of capacity needed for

least cost operation. Capacity expansion models

are used to examine possible generation alternatives and to determine the least costly mix of future generation additions. Next, the operation

costs and reliability of this generation mix are examined. Finally, the impact of the candidate capacity plan on the utility’s financial position is

assessed. These modeling and analysis functions

often rely on complex optimization and simulation models. s Transmission and distribution plan2G. R. Corey, “Plant Investment Decision Making in the Electric

Power Industry, ” Discounting for Time and Risk in Energy Policy,

Robert C. Lind (cd.) (Baltimore, MD: Resources for the Future/Johns

Hopkins, 1982), pp. 377-403.

]Garfield and LOve jOy provide a good summary of this Obligation: “public utilities are further distinguished from other sectors

of business by the legal requirement to serve every financially responsible customer in their service areas, at reasonable rates, and

without unjust discrimination. ” (P.). Garfield and W,F. Lovejoy,

Pub//c Uti/ity Economics (Englewood Cliffs, NJ: Prentice-Hall, 1964),

p. 1.

4 A large body of economics Iiteratu re is devoted to the incentive (or lack of incentive) for cost minimization under rate of return regulation. The seminal piece by H. Averch and L. Johnson

(H. Averch and L. Johnson, “Behavior of the Firm Under Regulatory Constraint,” American Economic Review, vol. 52, No. 6, 1962,

pp. 1053-1069) argues that rate-of-return regulation provides an opposite incentive towards capital maximization.

sGood reviews of generation planning models have been done

by S. Lee, et al. (S. Lee, et al., Comparative Ana/ysis of Generation

Planning Models for Application to Regional Power System Planning (Palo Alto, CA: System Control, Inc., 1978); and D. Anderson

(D. Anderson, “Models for Determining Least Cost Investment in

Electricity Supply,” Be// Journa/ of Economics, vol. 3, spring 1972).
Ch. 8—Conventiona/ v. Alternative Technologies: Utility and Nonuti/ity Decisions “ 221

Table 8-1 .—Typical Power Planning Functions

Load forecasting:

● Energy forecast ●

● Peak demand

●

●

Generation planning:

● Capacity studies ●

. Production costing ●

● Investment analysis ●

. Siting studies

●

●

Transmission piannhg:

● Load flow studies ●

● Stability studies ●

●

Distribution pianning:

● Substation ●

● Major distribution

Changing weather ●

patterns

Short/long-term trends in ●

national/local economic ●

variables

Changes in energy

consumption patterns

from: ●

—Load management

—Conservation

—New technologies

System reliability ●

Pool requirements ●

New energy conversion ●

technologies/costs ●

Capital availability

Regulatory requirements

●

●

System reliability ●

Changes in major load .

center locations ●

Interconnection

requirements

Changes in service area ●

growth patterns ●

●

Historical consumption ●

data

Weather data

Economic data

–GNP

—Employment

—Many others ●

Appliance use data

●

●

Peak load ●

Energy sales

Capital/equipment costs

Equipment operating and

maintenance ●

characteristics

Fuel costs

Construction cost “S”

curves (expenditure

patterns)

Energy sources ●

Load flows

Load stability

Load growth by area .

New developments

Major industrial

customers

Location, size, and

timing of transmission

facilities to support

system needs

Location, size, and

timing of new substation

and major distribution

lines

SOURCE Theodore Barry & Associates, A Study of the E/ectrw Uti/ity /rrdustry (Los Angeles, CA: Theodore Barry & Associates, 1980)

ning activities are used to assure system adequacy

and reliability given projected demand and generation facility location.

In the past, this planning process was straightforward–electric demands could be predicted

accurately and generation planning was not unduly hampered by financial and environmental

constraints. The situation is now considerably

changed. A survey of electric utility executives

indicates that the following major changes have

affected their planning function the most in recent years: unpredictable demand growth, longer

lead-times, and uncertain technology costs.

Chapter 3 discusses these changes in depth.

bTheodore Barry & Associates, A Study oi the U.S. Electr/c Ut/lity/ncfustry (Los Angeles, CA: Theodore Barry & Associates, 1980),

p. IV-6.

Short: O-1 year

Intermediate: 1-5

years

Long: 10-30 years

10-30 years

2-10 years

1-3 years

These new factors have complicated the utility planning process. Utilities are required by Federal statutes, regulatory commissions, consumers,

and stockholders to investigate all the possible

costs and consequences, e.g., environmental impacts, of a generation alternative prior to investment. Consideration of many of these factors has

been incorporated into structured regulatory proceedings like powerplant siting, but many of the

issues and consequences can only be included

in utility decision making through judgments

made by utility executives and planners. The current inactivity in new plant construction start-ups

is due in par-t to the reluctance of utility decisionmakers to make these judgments. These factors

are discussed in greater detail in subsection entitled Required Project Characteristics.
222 . New Etectric Power Technologies: Problems and Prospects for the 1990s

Comparative Analysis

As mentioned earlier, unlike unregulated firms,

utilities have not based their investment decisions

strictly on profit maximization. Instead, they have

traditionally examined all available means of

meeting customer demand (both generation and

demand-side options) and then selected the alternative that is least costly in terms of the revenue

required from the consumers. This comparison

approach, known as the minimum revenue requirement approach, is derived from standard

utility rate-making techniques (see box 8B). It has

been used throughout the industry8 One recent

survey indicated that 91 percent of investorowned electric and combination electric and gas

systems used a minimum revenue requirement

approach.9

In this analysis, the comparative costs of the

new technologies and of the conventional alternatives were arrived at by applying the minimum

revenue requirement concept to each investment

alternative and then deriving its Ievelized cost.

OTA staff developed a cost analysis model using

standard utility accounting and investment decision methodologies for comparison purposes. 1

0

This model projects yearly revenue requirements,

i.e., costs, taxes, and allowed rate of return, for

the expected life of a new plant. Levelized costs

in cents per kilowatt-hour are derived from this

revenue requirement stream, and form the basis

of cross-technology cost comparisons, (Appendix 8A discusses the Ievelized cost estimation in

much greater detail.)

7“Available” in this context refers to the technologies utilities perceive as being able to meet their needs. The utility planners may

feel that adequate information on a technology or commercial demonstrations are not sufficiently available for new technologies, and

will not consider the technology.

sPublicly owned utilities perform a similar comparison. The components of revenue requirement will be different-reflecting factors such as rate of return.

9G. R. Corey, “Plant Investment Decision Making in the Electric

Power Industry, ” op. cit., 1982,

IOThe analysis structure usecf to develop the OTA model was derived from the techniques used by Philadelphia Electric Co. ’s Rates

Division (Philadelphia Electric Co., Engineering Economics Course

(Philadelphia, PA: Philadelphia Electric Co., Rates Division, Finance

and Accounting Department, January 1980), p. 2-2.).

Basic Assumptions

In order to compare different technologies on

a consistent basis, several assumptions had to be

made. The technologies considered for utility investment were assumed to be electric-only technologies—no cogeneration technologies were

considered. Cost estimates calculated in this

model were made on a constant dollar (1983) ba-
Ch. 8—Conventional v. Alternative Technologies: Utility and Nonutility Decisions ● 223

70

60

50

40

30

20

1 0

0

Figure 8-1 .—Technology Cost Range: Utility Ownership—West

“Worst case”

“Most likely”

n

. . . 50 150 500 500 537 10 10 20 11 1 5 0 20 220

sis. This allows the comparison of technologies

with different reference years, lead-times, and lifetimes. Figure 8-1 lists the basic parameters that

are assumed not to vary across technologies.

Later in this section, the sensitivity of the costs

to changes in these parameters will be addressed.

For the basic cost comparison, the technologies

were examined for three scenarios: worst case,

most likely case, and best case. These scenarios

were derived from the parameter ranges included

in the cost and performance projections developed in chapters 4 and 5. The worst case scenario incorporates the “worst” (most pessimistic) values for each parameter, while the best case

uses the “best” (most optimistic) values. For example, the worst case uses the high end of the

capital cost range, but uses the low end of the

capacity factor range. In addition, the worst case

scenario assumes little improvement in current

technology conditions. Comparison of the worst

and best case scenarios provides a range of levelized costs. The most-likely case numbers represent OTA’s best estimates of future utility costs.
224 . New Electric Power Technologies: Problems and Prospects for the 1990s

Cross-Technology Cost Comparison

The results of the comparative cost analysis are

shown in figure 8-1. Costs for pulverized coalfired plants, combustion turbines, and coal pIant

life extension were included for comparison

purposes.

One of the striking features of the results shown

in figure 8-1 is the wide cost ranges for solar

photovoltaics and fuel cells. Both of these technologies are currently in early stages of development relative to the other technologies in the figure and are currently not competitive with other

technologies. Nevertheless, as figure 8-1 shows,

these technologies have the potential of significant cost reductions, and they could compete

with peaking technologies, e.g., combustion turbines, or even base load technologies. To become competitive, however, they must be deployed in significant numbers, and important

research, development, and deployment questions must be resolved (see chapter 4).

Comparison of the new base load technologies–

geothermal, atmospheric fluidized-bed combustors (AFBC), and integrated coal gasification/combined-cycle (lGCC)–with the primary conventional alternatives—pulverized coal-fired plants

with flue gas desulfurization (FGD) and existing

coal plant life extension—indicates that all of

these new technologies are likely to be competitive with current technology in the 1990s. Figure 8-2 shows Ievelized costs for each of these

technologies under the most likely case. These

resu Its indicate that coal powerplant betterment

is the cheapest source of base load power.

Among the new technologies, IGCC appears to

be the best competitor followed by AFBC. The

competitiveness of these new “clean coal” technologies is important because both produce less

negative environmental impacts than conventional coal-burning technologies. The potentially

attractive economics of the plant betterment option, however, could lead to extended use of old,

dirtier coal plants, many without scrubbers. Geothermal plants are also attractive in terms of comparative cost, but the site-specific nature of geothermal power will probably limit widespread

deployment,

Figure 8-2.— Base Load Technology Costs: Utility

Ownership—West

a ~

Geothermal AFBC IGCC Coal Life

Technology

extension

SOURCE: Office of Technology Assessment.

The new, intermittent, and peaking technologies addressed in this assessment are also expected to compete favorably with current technologies in the 1990s, Figure 8-3 shows the most

likely-case costs for solar thermal electric, solar

photovoltaics, wind, fuel cells, battery storage,

and compressed air energy storage (CAES), as

well as the most likely costs for combustion turbine powerplants. Wind power from utility-owned

small turbines ( <400 kW) in wind farms shows

the lowest cost among the new generation technologies. The expected future Ievelized cost of

wind technology is significantly lower than the

other non-base load technologies. Wind also has

the potential of competing with the base load

technologies (see figure 8-2). The relatively low

cost estimates for the storage technologies indicate that these technologies could compete favorably with peaking technologies to satisfy peak

electric loads.

Sensitivity to Uncertainty

Despite the optimism reflected in the crosstechnology comparison, the projections of these

future costs for the new technologies are subject

to a great deal of uncertainty. This uncertainty

is reflected in the Ievelized cost ranges in figure

8-1. Several of the technologies–solar photovoltaics, wind and fuel cells—show particularly wide
Ch. 8—Conventiona/ v. Alternative Technologies: Utility and Nonutjlity Decisions . 225

Fiqure 8-3.— Peaking/Intermittent Technology Costs:

Utility-Ownership—West ‘ -

t

20

t

—

1

hotoparabolic voltaics

dish

cell bustlon storage

turbine

Technology

SOURCE. Off Ice of Technology Assessment

cost ranges. Unless resolved, this uncertainty, and

the investment risk it represents, will probably

hamper widespread deployment of many new

technologies well into the 1990s.

A sensitivity analysis was performed for each

technology considered in this assessment. This

analysis highlights the most sensitive parameters

and provides insight into the technological developments that could produce the most improvement in future cost and performance. The

sensitivity of a technology’s Ievelized cost to

changes in key parameters—capital cost, operation and maintenance (O&M) cost, capacity factor, and fuel cost—was tested by varying each parameter above and below the base case estimate

by 25 percent. This analysis indicates, for example, that a 1 ()-percent increase in wind farm capital cost could cause our most likely estimate of

utility Ievelized costs to increase 1.5 cents/kWh

or about 21 percent.

In general, the results of sensitivity analyses for

all the technologies indicate that the three most

critical parameters are capital cost, capacity factor, and fuel cost. The capacity factor is the most

critical parameter for electric utility operation,

Fuel costs were also very important for non solar

technologies, but capacity factor consistently produced the largest variations in Ievelized costs. A

somewhat surprising result from the analysis was

that capital cost changes do not produce as much

variation as these other parameters. Nevertheless,

the relative importance of each of these parameters varies according to duty cycle, heat rate,

and capital intensiveness. For example, fuel costs

are the most sensitive parameter for combustion

turbines, but capacity factor is more important

for fuel cells. This is because of the lower capital

costs and higher heat rates of combustion

turbines.

A possible explanation for the relative importance of capacity factor vis-a-vis capital cost is

found by examining the Ievelized cost formula.11

The numerator of the formula is the Ievelized annual revenue requirement. The denominator is

average kilowatt-hour production. Increases in

capacity factor will directly increase electricity

production and reduce levelized costs. Capital

costs are recovered through economic depreciation over a number of years (1 5 years under

present tax law). The Ievelization calculation discounts the depreciation costs more in later years

than in early years. Thus, changes in initial capital cost do not produce as significant and direct

an effect. This suggests that utilities are likely to

continue to be very concerned with the availability and reliability of future generating options

since these factors cause significant levelized lifecycle cost uncertainty.

Utility Strategic Options

Most utilities have put off decisions on new,

large coal or nuclear plants. To commit large

sums of capital to such long lead-time projects

in the highly uncertain investment environment

which has prevailed in this industry since the

1970s, they think, is too financially risky. Instead,

many utiIities are considering a variety of strategic options that will defer the need for such largescale commitments. Chapters 3 and 5 discuss

these options in detail. The discussion that follows focuses primarily on three of these options,

namely life extension and rehabilitation of existing generating facilities, increased reliance on

load management, and construction of small

modular plants.

1 IThe general form of the Ievelized cost formula is:

Ievellzeci annual revenue requirement

average annual electricity production
226 ● New Electric Power Technologies: Problems and Prospects for the 1990s

Plant betterment—i.e., life extension and rehabilitation of existing generating facilities–is a

way to defer new generation investment. The capacity base for this option is sizable–by the year

2000, nearly a third of the existing U.S. fossil generating capacity will be more than 30 years old.

In addition, the capital investment required–

$200 to $800/kW–is relatively small. The attractiveness of this option is partially explained by

its low expected Ievelized cost. As can be seen

in figure 8-2, the expected costs of existing coal

plant betterment are lower than both conventional and new base load generating technologies. Moreover, figure 8-4 shows that capital cost

levels for life extension up to $1 ,500/kW can produce lower cost power than conventional pulverized coal plants with FGD, or an IGCC plant.

Additional OTA modeling efforts12 using EPRI Regional Systems datals indicate that at the system

level, at least in the Southeast, fossil life extension (coal, oil, and gas-fired units) could produce

overall utility system revenue requirements14 as

much as 5 percent lower than a capacity expansion plan based on large unit construction (the

base case) to meet the same load. Nevertheless,

the results also indicate that focusing plant betterment activity solely on oil and gas units could

produce higher revenue requirements than the

base case.15

Load management is the other primary nongeneration option available to utilities. Its principal goals are to permit a higher proportion of

demand to be served by lower cost electricity

(from base load sources) and to defer the need

for new generating capacity. There is the poten12A state-of-the-art uti Iity si mu Iation model, the Utility System

Analysis Model (USAM) by Lotus Consulting Co., was used for this

analysis.

I JElectric power Research Institute, The Ef’/?/ Regional S)@em5

(Palo Alto, CA: Electric Power Research Institute, July 1981), EPRI

P-1 950-SR. The load and system data used by OTA were the basic

EPRI typical utility data sets that were modified by Lotus Consulting Co. to include plant additions.

1 oThis value refers to a Ievelization of the utility SyStem revenue

requirements (using a 5 percent discount rate) over the 10-year

period between 1990 and 2000.

1 sThe assumptions used in this analysis were: 1 ) all plants which

are 25 to 35 years old in 1985 through 2000 will have their life extended; 2) plant efficiency is increased by 5 percent, capacity is

increased by 5 percent, and 10 years are added to design plant

lifetime; 3) the plant betterment costs $200/kW (based on the new

plant size); and 4) future capacity is deferred to achieve the same

reserve margins as in the base case.

IGElectrotek Concepts, Inc., Future Cost and Performance of New

Load Management Technologies, final report to the Office of Technology Assessment, January 1985, OTA Solicitation US-84-7. For

the Southeast, 5.4 percent reduction equals 891 MW in 1990.

I The basic assumptions used in this analysis are the same as for

the plant betterment analysis. The capital costs of the utility load

management program (calculated by Electrotek to be $191 /kW) are

annualized and expensed over the life of the equipment. Further

analysis by OTA has shown that utility revenue requirements do

not significantly differ when expensing or capitalizing the load management program.
Ch. 8—Conventional v. Alternative Technologies: Utility and Nonutility Decisions . 227

Comparison of the results for the plant life extension and load management cases in a typical

Southeast utility indicates that plant life extension

is the more attractive option at currently projected load management levels and assumed program costs,

Of particular interest to many utilities are the

potential benefits of increased flexibility and financial performance offered by small-scale, short

lead-time generating plants. OTA modeling

studies indicate that under uncertain demand

growth, the cash flow benefits of such plants in

the short term couId be considerable .18 For example, as shown in figure 8-5, the interest coverage ratio, which measures a utility’s ability to

repay its debt obligations—and is the principal

consideration in bond rating decisions, tends to

decline for a utility engaged in a major construction project as outlays are made during the construction period. Under the low demand growth

scenario in figure 8-5,19 investment in a series of ——. .— 18A sca~ed.cJown ~orttleast EPRI Regional System was used for

this analysis, The Inltlal capacity IS 6,600 MW and Initial peak load

is 5,500. The first year of the scenario IS 1990 and continues u ntl I

2000. A 800 MW coal plant IS assumed to start-up in 1992. A pulverized coal plant is the technology examined, The only differences

between the two types of plants are:

Small Ldrge

Capacit y 100 MW 500 MW

Lead-tim e 1 year 7 years

I $ITwo percent load growth i n the ti rst 5 years and O percent i I I

the last 5 years. Edison Electrlc Inst]tute, Strateg~c /mp/icatJorrs ot’

6 L

1990 1992 1994 1996 1998

Years

SOURCE Office of Technology Assessment

small modular plants results in a considerably better interest coverage ratio trend, even with a 10

percent capital cost premium (per kilowatt) associated with the smaller plants. The primary reason for the difference in financial performance

is the ability of the smaller plant to track demand

growth. Under the low demand growth scenario,

the interest coverage ratio for the large plant is

relatively low both during the construction period

of the plant20 and during the period that the system has high reserve margins. Use of a low-high

demand scenario2l narrows the difference. Indeed, the interest coverage ratio trend for the

large plant surpasses the small plant trend after

the large plant comes on-line in 1997.

Summay

The new technologies addressed in this assessment have the potential to compete economically

with conventional generating technologies, e.g.,

pulverized coal, combustion turbines. The new

technologies which are most likely to provide

lower cost power are AFBC, IGCC, geothermal,

and wind power. Fuel cells and photovoltaics

could compete favorably with peaking technologies such as combustion turbines. Storage technologies could also compete effectively with

these peaking technologies. In addition, most of

the generating technologies considered in this

assessment offer the small-scale modular features

many utilities are seeking, although many are subject to significant cost and performance uncertainty.

A more serious impediment to utility investment in these new technologies for the next 10

to 15 years is that most of them are not likely to

compete effectively with other generally more

cost effective strategic options—life extension and

rehabilitation of existing generating facilities, and

increased reliance on load management. These

strategic options are being aggressively pursued

by many utilities. OTA analysis of these options

indicates that their implementation could provide

A/ternatiie Electric Generating Technologies (Washington, DC: EEI,

April 1984).

zOThe 500 MW plant is assumed to come On-llne in 1997.

Z1 TWO percent load growth in t+e first 5 years and 6 percent In

the last 5 years.
228 ● New Electric Power Technologies: Problems and Prospects for the 1990s

sizable benefits to utilities and enhance utility financial health. As a result, the new technologies

may take longer to achieve the low costs projected in this section.

NONUTILITY INVESTMENT IN POWER GENERATION

Overview

Interest in nonutility electric power generation

has increased in recent years. In some parts of

the country, California being the most notable

example, nonutility generation has emerged both

as a significant source of power and as a strategic option for utilities. In addition to existing industrial self-generation, power is now being sold

by companies operating low-head hydroelectric

dams, cogeneration, wind turbines, geothermal

powerplants, and, to a much more limited extent,

photovoltaic arrays and solar thermal electric faciIities.

Non utility generating facilities are owned by industrial and commercial firms, and third-party

entrepreneurs. This increase in activity is due, primarily, to a supportive regulatory climate and the

availability of tax benefits. And whether a healthy

nonutility power generation industry emerges in

the 1990s will depend on policy decisions over

the next few years. This section examines:

1. characteristics of current nonutility producers,

2. nonutility technology choice decisionmaking,

3. the comparative profitability of these technologies, and

4. the impact of Federal tax policy.

Historical Nonutility Generation

Industry has generated electricity since the

earliest days of electric power. This power generation included both onsite production to meet

industrial needs and cogeneration. The contribution of this industrial capacity to overall electricity production has declined over time, however.

In 1962, capacity at non utility owned generating

plants represented 8.5 percent of total installed

generating capacity. By 1979, this contribution,

while remaining relatively constant in absolute

terms, had slipped to 2.8 percent of total generating capacity .22 In the 197os, industrial selfgeneration (including cogeneration) of electricity

decreased in the face of increasing fossil fuel

prices, aging plant, a flattening of demand, and

a generally lower rate of increase in the price of

purchased electricity23 Changes in this trend,

however, may be emerging in the 1980s–the real

price of oil has stabilized, curtailments of natural gas no longer occur, the retail price of utility

power has continued to increase, and regulatory

changes that make it economically attractive to

produce electric power for sale to utilities.

Current Nonutility Electric Power

Generation

With the passage of the Public Utility Regulatory Policies Act of 1978 (PURPA), the prospects

for generation of power outside of electric utility

ownership improved markedly. Prior to PURPA,

owners of nonutility powerplants did not have

guaranteed markets for their power beyond their

own use, and were subject to possible public utility regulation. Rates for sales of power to utilities were open to negotiation without a consistent “yardstick” against which negotiated rates

could be measured, PURPA changed this situation by providing a 100 percent “avoided cost

criterion” for these rates and removing potential

for regulation. Chapter 3 discusses PURPA in

more detail.

The non utility market for sale of power has increased significantly since the early 1980s. installed nonuti Iity generating capacity in 1985 consists primarily of cogeneration applications

(mostly from natural gas), biomass-fired generazzEdison Electric Institute, Statistic/ Yearbook Of the E/ectrk Uti/@’

/ndusfry/1982 (Washington, DC: EEI, 1983).

23R.C. Marlay, “Trends in Industrial Use of Energy,” Science, vol.

226, No. 4680, Dec. 14, 1984, pp. 1277-1283. These numbers do

not include boilers using nonfossil fuels.
Ch. 8—Conventional v. Alternative Technologies: Utility and Nonutility Decisions ● 229

tion, wind, geothermal, AFBC, and hydro. Additional activity is occurring in solar thermal electric

and photovoltaics. Table 4-4 shows the installed

capacity breakdown for the new tech nologies in

1985. Wind power and AFBC are the subject of

the most activity.

Characteristics of Nonutility

Producers

Nonutility involvement in new technology development is being initiated by both industrial

firms and third-party investors. Industrial investment in new technology projects is primarily undertaken to reduce the cost of meeting electrical and/or process heat needs. Either revenues

from power sales to electric utilities or the avoidance of electricity purchases can make a project

economic. By contrast, third-party investment in

these technologies is organized by entrepreneurs

who obtain financing and develop projects as

profit-making ventures from sale of the electricity and any byproduct steam. Both types of development have occurred in recent years—with

industrial involvement centering on cogeneration

and third-party investment principally occurring

in cogeneration, low-head hydroelectric dams,

and wind power.

In order to gauge the level and type of current

nonutility power generation, OTA sponsored a

survey24 conducted by the Investor Responsibility Research Center (1 RRC). The trends and characteristics in the I RRC sample provide insight into

the nature of the industry and the direction it appears to be headed.

IRRC sent a survey form to current and projected nonutility power producers in the wind,

solar thermal electric, geothermal, and photovoltaic

i ng

●

●

industries. 25 It asked questions on the followtopics:

ownership,

financial structures,

24 I nvestor Responsibi[ ity Research Center, Survey of ~on-Uti/ity

E/ectric Power Producers, OTA contract 433-7640, July 11, 1984.

25A total of 4S companies (25 current and 20 projected producers) responded to the survey. IRRC also surveyed the biomass and

hydroelectric small power industries. The remaining technologies

highlighted in this report (fuel cells, AFBC, and ICCC) were not sufficiently commercialized or deployed in 1983 to be surveyed.

● generating plant characteristics,

● vendor agreements,

● operational data, and

● purchase agreements with utilities

Figure 8-6 shows the breakdown by technology of the survey respondents. Note that wind

power companies represented 76.7 percent of

the respondents, and geothermal power came in

a distant second at 11.6 percent. I n terms of total installed capacity, the disparity is even greater.

By the end of 1983, the IRRC sample reports that

wind power accounted for over 134 MW of capacity.2b

The survey results reveal two important industry characteristics which could affect industry

health and the impact of Federal policy in the mid

1980s. First, most companies involved in nonuti!-

ity power projects are relatively young—less than

3 years old. Second, these companies are quite

small, typically maintaining generating capacity

of less than 6 MW. Any significant changes i n tax

and regulatory policy could severely affect the

operations and profitability of these young firms.

zbcornparisorl of this reported capacity with the 239 MW repot-ted

in D. Marler, “Windfarm Update .. .117 Megawatts and Still Growing, ’’Alternative Sources of Energy, No. 63, September/October

1983, suggests that the IRRC sample contains a little over one-half

of the industry in 1983.

Figure 8-6.—Survey Responses by Technology

SOURCE: Office of Technology Assessment
230 • New Electric Power Technologies: Problems and Prospects for the 1990s

Figure 8-7 shows the cross-section of ownership of current and projected non utility producers. The majority (78.6 percent) of these producers are privately owned companies, most of

which are small in size and were formed strictly

to sell power to utilities. Far fewer publicly held

companies and subsidiaries, particularly more

established, older, and larger firms, have entered

the market as yet.

The survey respondents were also asked about

the financing methods they have used to capitalize and operate their generating facilities. The responses from the currently producing companies

fall generally into four major categories: sole

ownership, joint ventures, partnerships, and leasing. Partnerships are the most prevalent, account-

 ng for half of the projects surveyed. Sole ownership ranked second—29.4 percent; joint ventures

and leases accounted for 14.7 and 5.9 percent,

respectively. This cross-section indicates that most

of the current projects, i e., wind farms, are generally financed with private investor capital, although over one-quarter of the respondents

noted that they have used a mixture of financing methods such as sole ownership along with

partnerships.

The survey indicates that the project location

of most of the current and anticipated nonutiiity

Figure 8-7.— Nonutility Ownership: Current and

Projected Companies

projects represented in the survey is California

(see figure 8-8). California represents an even

larger portion of nonutility capacity–over 90 percent of the 1983 reported installed capacity. The

primary reasons are the availability of high utility

avoided cost rates, tax credits (State and Federal),

and California’s generally supportive reguIatory

environment for alternative energy development.

Wind power represents all of the reported 1983

installed capacity of 134 MW in the survey. The

average wind farm in the survey had an average

capacity of 5,8 MW, Figure 8-9 shows that while

small companies dominate the market in terms

of total projects, in terms of installed capacity

larger companies represent a much greater share

of the industry.

The year of initial generation for most companies has been within the last 3 years. Although

PURPA and the business renewable tax credits

were first passed in 1978, significant nonutility

generation did not occur until 1982 because of

court challenges to PURPA and slow implementation by States. As mentioned earlier, most of

the companies involved in nonutility production

are less than 3 years old; over 60 percent’of the

companies in the survey started producing in

1982 and 1983 (see figure 8-10).

Figure 8-8.—Survey Responses by Project Location

New Hampshire

(2.40/o) New York Oregon

Montana \ (4.8°/0) (4.8°/0) Texas

SOURCE: Office of Technology Assessment. SOURCE: Office of Technology Assessment.
Ch. 8—Conventional v. Alternative Technologies: Utility and Nonutility Decisions . 231

Figure 8-9.—Wind Farm Installed Capacity Distribution

(number of companies and total kilowatts)

12,985

15 ~

14 -

13 —

12 —

11 —

10 .

9 —

% —

7 —

6 —

5 —

35,750

4 —

3 —

39,500

r f

2 —

46,000 1 —

o ~ t 1

0 - 5 5-1 0 10-2 0 20-5 0

Size categories (MW)

SOURCE: Off Ice of Technology Assessment

Figure 8-10.— Initial Year of Generation: Currently

Producing Companies

1984 (4.30 /,) 1976 (4.30/, ) 1980 (8,7°/0)

Hence, investor interest will increase if nonuti]ity

power project investments offer potentially high

returns relative to other investment options. But

the rationale for the investment will vary according to the types of investors. Additional considerations for investors include tax status, timing of

the investment, cash flow patterns, and maintenance of a balanced portfolio of risky and nonrisky investments.

Financing Alternative Technology

Projects

Investment in nonutility generation projects can

be initiated through a variety of financing structures. For a corporation (industrial or commercial), the two major vehicles are capital investment with internal funds, and project financing

(sometimes called “third party financing”). Capital investment by a corporation usually involves

the use of retained earnings, equity, or debt issues to finance a generation project. Project

financing, on the other hand, looks to the cash

flow and assets associated with the project as the

basis for financing. Private investors often invest

in technology projects through tax shelter synSOURCE Off Ice of Technology Assessment.

Nonutility Investment

Decisionmaking

Investment in power generation equipment in

a nonutility environment is generally not very

different than other long-term investment decisions. Investors, either individuals or corporations, are primarily interested in maximizing their

risk-adjusted return on their invested capital.

on the size and financial strength of the industrial firm, the rationale for investment, and the

riskiness of the technology. A large corporation

will be more willing and able to finance a project

with retained earnings than a small industrial firm.

A large firm usually has more retained earnings

available for discretionary investment. If a corporation has a stake in the development of a technology, e.g., the corporation is a vendor of the

technology, successful ownership of a project

such as a photovoltaic array or wind farm may

attract future investment by third parties and lead

to increased profits for the corporation. A project

directly related to a firm’s manufacturing process—e. g., providing process steam or electric

power directly to an industrial operation–is also

more likely to be financed internally. But a project

operated strictly as a small power producer is less
232 . New Electric Power Technologies: Problems and Prospects for the 1990s

likely to be owned solely by a corporation. investments in projects that are more associated

with a firm’s principal line of business (e.g., sales

expenditures or plant expansion) are more likely

to receive higher priority. In addition, if the technology under consideration is perceived as risky,

an industrial firm may seek partners or guarantees from vendors to share the project risk.

The methods of project finance are particularly

appropriate to the financing of distributed electricity generation. As mentioned earlier, project

financing looks to the cash flow associated with

the project as a source of funds with which to

repay the loan, and to the assets of the project

as collateral. For successful project financing, a

project should be structured with as little recourse

as possible to the sponsor, yet with sufficient

credit support (through guarantees or undertakings of the sponsor or third party) to satisfy

lenders. In addition, a market for the energy

output—electrical or thermal—must be assured,

preferably through contractual agreements; the

property financed must be valuable as collateral;

the project must be insured; and all government

approvals must be available.z’ There are four major forms of project finance applicable to new

technology projects: leasing, joint ventures,

limited partnership, or small power producer (see

box 8C for definitions).

Another ownership structure often used in

wind turbine farms is an organized system of

individual turbine sales, also known as sole

ownership (or “chattel”). Under this structure the

private investor owns only one turbine.28 The

project developer organizes the wind farm, sells

the wind turbines to prospective investors, and

provides maintenance services.

Required Project Characteristics

Every non utility generation technology project,

whether it is structured through traditional project

financing techniques or third-party entrepreneurs,

must meet several requirements before it will be

acceptable to investors. These requirements fall

into three key areas: risk reduction, firm fuel and

lzp. K. Nevitt, project F;rxincing (London: Euromoney Publications

Limited, 1979).

Z8R. Ceci, “Investing in Windpower: Ownership or Partnership, ”

Alternative Sources of Energy, No. 71, January/February 1985,

power sales contracts, and sufficiently high profitability (before or after taxes depending on the

investor),

There are several forms of risk involved in new

electric generation technology projects.29 They

include among others:

1.

2.

3.

4.

In

Machine Risk: Will the technology perform

as predicted, i.e., produce the estimated

power, meet availability targets, and not suffer catastrophic failure, all within appropriate installation and operational budgets?

Resource Risk: Will the site actually have

sufficient fuelstocks (e.g., low-cost coal or

geothermal brine) or quality resource (e.g.,

wind speeds and distribution) for the duration of the project? Will year-to-year fluctuations be great?

Politica/ Risk: Will the “rules of the game”

regarding tax credits and deductions, sales

prices to utilities (or others), zoning ordinances, or other permitting regulations

change for the worse during the course of

operation?

Energy Price Risk: Will the oil market soften

further? Will the utility be allowed to convert to coal or other low-energy cost options?

order to finance a new nonutility project,

these risks must be either mitigated or incorporated in contingency plans. Common risk reduction techniques include vendor guarantees, takeor-pay contracts with utilities, and guarantees on

project profitability from the project sponsors.

Nevertheless, not all of the risks in projects utilizing new technologies can be eliminated. The

higher the level of risk, the higher is the return

on investment demanded by investors.

The most critical requirement for nonutility

generation projects is the guarantee of stable fuel

supply and power sales contracts. Fuel supply,

whether it be natural gas, coal, or geothermal

brine, must be assured for the duration of the

project at reasonable, predictable prices. Even

more important than fuel supply contracts are

power sales contracts with electric utilities. Without long-term, power sales contracts, project de-

—.———

29M. LOtker, “lvlaklrlg the Most of Federal Tax Laws: A New Way

to Look at WECS Development, ” Alternative Sources of Energy,

No. 63, September/October 1983, p. 38.
Ch. 8—Conventional v. Alternative Technologies: Utility and Nonutility Decisions ● 233

‘Merrill Lynch Capital Markets, F?oject Financing (New York: Merrill Lynch Capital Markets, 1984).

zAlliance to Save Energy, Tbird-l?wtyF inancing: #ncm”ng h@tment in Energy-E ficient Industrid Projects (Washington, DC: US.

Department of Energy, November 1982), DOEKW24448-T1.

kilowatt-hour sold, will allow investors to calcuual, partnership or corporation, owns the

genw+ation project but is not the ultimate

Liset of the power. The SPP may sell the

electricity produced to the local utility or

other users, or may lease the generating

equipment itself to a user. The SPP should

be able to sell its electricity at high prices

and have sufficient tax liability (usually due

A “major reason that limi&i partnerships are

attractive ownership options is that tax benefits are distributed to partners who can

—.

~“lbld,
234 . New Electric Power Technologies: Problems and Prospects for the 1990s

Another requirement for the financing of new

technology projects is a sufficiently high rate of

return to attract capital. Generally, the nominal

internal rate of return (l RR) for a project must be

between 20 and 30 percent. 31 For example, as

can be seen in figure 8-11, windmills fall between

real estate and venture capital on the investment

risk continuum. Since the IRR is sensitive to tax

and financing, an equally important determinant

of profitability is cash return on the capital asset.

Cash return on capital assets is obtained by removing tax benefits and debt and concentrating

on the straight cash-on-cash return. A minimum

required cash-on-cash return of 5 percent after

operating expenses is typical. 32 If debt financing

is used, the project must show a favorable debt

service coverage ratio to obtain debt at reasonable terms. Most suppliers of debt capital require

at least a 1 .2:1 coverage ratio.33

31Thi~ nominalrange translates roughly into a real IRR range of

15 to 25 percent if a 5 percent inflation rate is assumed. Thus, 15

percent will be used as the required rate of return or “hurdle” rate

in the following analysis.

32R. A. Lyons, “Raising Equity: A Broker-Dealer Guide For the

Project Developer, ” Alternative Sources of Energy, No. 69, September/October 1984, p. 20.

JJEdward Blum, Merrill Lynch Capital Markets, personal communication with OTA staff, Aug. 28, 1984.

Figure 8-11 .—Investment Risk Continuum

Certificates Real Windmills Venture

of deposit estate capital

Degree of risk

SOURCE: American Wind Energy Association, briefing for congressional committee staff, Washington, DC, Jan. 18, 1985,

Comparative Profitability

The primary basis for cross-technology comparisons that follow will be the profitability of new

technology projects to both institutional and individual investors. The source for the technology

cost and performance estimates are the detailed

tables included in appendix 8A to this chapter.

Cross-technology comparisons based on projected costs and performance will be presented

first, followed by a discussion of the sensitivity

to these results to key parameters. Alternative

Federal policy scenarios, e.g., tax policy, will also

be examined.

The technologies examined in this section will

be geothermal power, wind power, solar photovoltaics (concentratorsJa), solar thermal electric,

fuel cells, and atmospheric fluidized-bed combustion (AFBC). (Integrated coal gasification/combined-cycle (lCCC) plants addressed elsewhere

in this assessment will not be included in this analysis because the technology is currently geared

toward the utility market, and cogeneration-sized

IGCC plants are not expected to be deployed in

the 1990s.) All the technologies listed above are

assumed to produce just electricity, except fuel

cells and AFBC for which cogeneration applications are examined. Neither of these latter two

technologies currently qualify as small-power producers under PURPA, and, hence, were configured as cogenerators for the analysis, Combustion turbine-based cogeneration, currently the

primary technology used in new cogeneration applications, is used as the conventional alternative

against which the new technologies are compared,

Basic Assumptions

Comparisons among technologies will be made

primarily by assessing their breakeven cost and

performance. Breakeven analysis determines the

capital cost and electricity production parameters necessary for a project to cover both costs

and required return on investment. A standard

discounted cash flow methodology was also used

to compare technologies, and check the results

jATracki ng concentrator systems were chosen for the base case

nonutility comparison because initial results indicated that they will

penetrate the grid-connected power generation market first with

the highest profit.
Ch. 8—Conventiona/ v. Alternative Technologies: Utility and Nonutility Decisions ● 235

of the breakeven analysis. This methodology calculates profitability measures and is based on

methods used by the financial community. The

discounted cash flow methodology is described

fully in appendix 8A.

In order to compare the different technologies

on a consistent basis in both of these methodologies, several assumptions were made. As discussed earlier, the comparisons are made on a

constant dollar (1 983) basis. This allows the comparison of technologies with different reference

years, lead-times, and lifetimes. The technologies

were examined for three scenarios: worst case,

most likely case, and best case. These scenarios

were derived from the parameter ranges in the

cost and performance projections developed in

chapter 4 and listed in appendix A.

Breakeven Analysis

As discussed in chapter 4, each new technology has a unique set of cost and performance parameters, such as capital cost, capacity factor, and

expenses. These parameters can be compared to

an assumed revenue stream (from electricity sale

to utilities or thermal revenues from cogeneration) and required rate of return to determine

technology cost effectiveness. The basic concept

is to match initial cost and annual electricity production (measured as the capital cost per annual

kilowatt-hour) to the sum of net revenues and tax

benefits (see box 8D). if a technology’s capital

cost per annual kilowatt-hour is lower than revenues and benefits, the technology is cost effective. This comparison is called breakeven analysis and is used in financial analysis to provide a

relatively simple quide to the profitability of a

project.35 If a technology appears profitable, more

detailed analysis and structuring of the project

is undertaken.

Figure 8-12 shows breakeven graphs for three

groups of technologies: a) wind power, solar photovoltaics, and AFBC; b) geothermal and solar

thermal electric (parabolic dish); and c) fuel cells

and combustion turbines. Each group represents

a different level of annual expenses .36 For exam-

“Edward Blum, Merrill Lynch Capital Markets, personal communicationw Ith [)TA $taft, Mar. 19, 1985 .

qh~ ~xpcn~e groups ~vere derived by ~rou PI ng the tech nok)gle$

ac co rci I ng to the pe r[ e ntage of totaI I I(ecyc Ie reie n ue accou ntec f

pie, technologies with high fuel expenses, such

as fuel cells, have much higher expenses than

wind turbines and solar photovoltaics, which

have no fuel expenses. The three lines in each

graph represent breakeven capital cost per

kilowatt-hour as a function of the avoided cost

buy-back rate. Each line is associated with a particular set of required real rate of return (1 O, 15,

and 20 percent) .37 Along side each breakeven

graph are the capital cost per kilowatt-hour

ranges associated with the new technologies. The

high end represents the worse case, the low end

represents the best case, and the mark in the middle is associated with the most likely case.

This graph can be used in two ways: 1) to determine the breakeven capital cost per kilowatthour associated with a specific avoided cost, and

2) to calculate the required avoided cost rate that

each technology needs in order to break even.

The top graph in figure 8-12 provides an example of the first type of analysis. The dotted lines

trace an avoided cost buy-back rate of 5 cents/

kWh38 and a 15 percent required real rate of return. As can be seen in this figure, wind power

could be profitable at this buy-back rate if capacity factors can be increased and initial capital cost

can be reduced. While wind power could be cost

effective under these conditions, at costs and/or

capacity factors associated with the upper portion

of wind’s capital cost per kilowatt-hour range,

profitability will likely be marginal. These graphs

also indicate that AFBC, geothermal, and combustion turbines are economic at a wide range

of buy-back rates. Conversely, solar thermal, and

to a lesser extent, photovoltaics and fuel cells require significantly higher buy-back rates. Both

photovoltaics and fuel cells become more economic in the lower portions of their cost ranges.

for by the sum of operating, tuel, Insurance, and land rental costs.

These percentages were estimated with the discounted cash flo)t

model discussed i n this sect 10 n. The percenta~et are 20 percent

for wind, phototoltaics, and AFBC; 25 percent tor \olar thermal

electric and geothermal; and 60 percent for fuel c el 1< a nci combustion turbines.

JTThe base set of assumptions are 10 percent I n \fest ment Tax

Credit (no Renewable Tax Credit), 5 year ACRS depreciation, 50

percent Federal tax rate, 100 percent equity ttnanc trig, and J [mrcent real fuel escalation. The fuel escalation rate serves as the proxy

for the rate of Increase In aiolded cost rates.

lflTh IS buy-back rate was chosen because It approximates a~ Olcfecf

costs for Pac it’lc Gas & Elect rlc and Southern Ca I Itorn Ia Ed I ton I n

1984 .
236 ● New E/ectric Power Technologies: Prob/ems and Prospects for the 1990s

The second analysis approach, calculation of

the required avoided cost revenue rate, provides

a good basis for comparison of cost effectiveness

across the technologies. in addition, the analysis can determine whether a new technology

project will be economic with a particular utility

or statewide buy-back rate. Figure 8-13 shows the

results of this analysis with a 15 percent real required rate of return (or approximately 20 percent nominal) and no Renewable Tax Credit.

These results mirror the results listed above.

AFBC, geothermal, and combustion turbines are

clearly economic throughout their cost ranges at

buy-back rates above 4 cents/kWh. At its expected cost and performance levels, wind could

be profitable at buy-back rates above 6 cents/

kWh. If wind power achieves its most optimistic

capital cost and capacity factor ranges, wind
Ch. 8—Conventiona/ v. Alternative Technologies: Utility and Nonutility Decisions ● 237

Figure 8-12.—Breakeven Analysis

180

160

180

160

140

120

100

80

60

40

20

— - .

are associated with real rate of return

SOURCE” Office of Technology Assessment
238 ● New Electric Power Technologies: Problems and Prospects for the 1990s

24

22

20

18

16

14

12

1

10

8

6

Solar

4

2

0

Fuel

parabolic cell

Combustion

turbine

dish

Technology

NOTE: Assumes 2°/0 real fuel escalation, 1OO/. Investment Tax Credit, 5-year ACRS depreciation, a 50V0 tax bracket, and 150/. real rate of return

SOURCE: Office of Technology Assessment.

could require only a 4 cents/kWh rate. The breakeven buy-back rate for solar photovoltaics and

fuel cells drops below 10 cents/kWh only at their

most optimistic cost and performance values. For

solar thermal electric, the breakeven rate is above

10 cents/kWh throughout its cost and performance range.

Rate of Return Analysis

In addition to breakeven analysis, a standard

discounted cash flow methodology was used to

derive profitability, i.e., real internal rate of return. Internal rate of return (l RR) can easily be

compared to rates realized by investors, although

its calculation and interpretation are not without

problems. The most serious problem is the sensitivity of IRR to changes in the debt structure,

and other financial parameters (e.g., repayment

schedules, leasing, etc. ).39 Since no attempt was

made by OTA to structure the financing of a given

new technology project in order to gain the best

rate of return—the basic cross-technology cash

flow model assumes established debt and equity

portions for the project, no leasing, and a set Federal tax rate40—the calculated rates of return in

this analysis will be different from and typically

below the rates of return actually achievable.

The results of the comparative profitability analysis are included in figure 8-14. Also listed in are

the base case assumptions regarding tax rates,

Jglndeed, many analysts place more weight on payback periods

and net present value.

@For the basi c comparisons, the tax rate is set at the average Federal tax percentage.
Ch. 8—Conventiona/ v. Alternative Technologies: Uti/ity and fVonuti/ity Decisions • 239

c

Figure 8-14.—Technology Profitability Range: Nonutility Ownership—West

K

“Best case”

“Most likely”

t i

$ Worstcas e)

I I

the near future are expected to be developed in

the State. ) The regional fuel prices were derived This figure shows the attractiveness of AFBCfrom utility-reported data compiled by the Energy based cogeneration. Throughout its expected rate

Information Administration .41 The regional as- of return range, AFBC is clearly the most profitable new technology. These profitability ranges

QITheSe data Were compiled by EIA for OTA on NOV. 27, 1984. also show the potential for solar photovoltaics
240 . New Electric Power Technologies: Problems and Prospects for the 1990s

and fuel cells to achieve high rates of return42 under the best case scenario. The capacity contribution and deployment of these “clean” technologies could be sizable if capital costs are

reduced and reliability increased for these two

technologies. On the other hand, if they do not

occur, these technologies do not compare as

favorably with the other technologies and may

not be deployed in significant numbers.

Wind power is currently the major source of

non utility generation, other than cogeneration.

The results shown in figure 8-12 seem to explain

this market dominance—wind power compares

favorably with the other technologies. Geothermal power is also expected to achieve favorable

rates of return.

Sensitivity to Uncertainty

The nonutility profitability values listed above

and shown in figure 8-14 were subjected to the

same sensitivity analysis framework that was conducted on utility Ievelized costs presented earlier.

The primary purpose of this sensitivity analysis

is to examine the cause of the wide rate of return ranges shown in figure 8-14 for each technology.

In general, the results of sensitivity analyses of

the key factors—capital cost, O&M cost, capacity factor, heat rates, and electric-thermal

ratio43—affecting the profitability of the technologies indicate that the most critical are: capital

cost, capacity factor, and heat rate. If the nonutility project cogenerates, then the electricthermal ratio becomes very important. The relative importance of each of these parameters

varies according to duty cycle, relative heat rate,

and capital intensiveness.

General economic conditions and Federal policies can also significantly affect the profitability

of non utility projects. The sensitivity of these economic factors—avoided costs, fuel costs, fuel cost

escalations, tax credits, Federal tax rate, debt por4ZA 1‘favorable” or “sufficiently high” rate of return is assumed

to be above a 15 percent real (20 percent nominal) “hurdle rate. ”

qJThe electric-thermal ratio measures the relative production of

electricity and steam from a cogeneration unit. A high ratio indicates that the unit produces relatively more electrical energy than

thermal energy.

tion, and debt interest rate–were subjected to

sensitivity analysis. The most critical factor was

the avoided energy cost rate. This is not surprising since the energy credit is the major source

of revenue for nonutility technology projects.

Next in importance are the Federal tax credit

(both investment and energy credits), the Federal

tax rate, and avoided capacity credits. As was indicated by the relatively high sensitivity to heat

rates, relative fuel costs are also important for fuelintensive technologies such as combustion turbines. Sensitivity to tax credits is examined further below.

These results highlight three main factors that

affect the development of new generation technologies. First, policies geared toward increasing

reliability and availability, lowering initial capital costs, and increasing efficiency (e.g., heat rate)

will have the greatest impact on the future market potential in the nonutility sector. Second, locating a project in a region or State with high

avoided costs is crucial to project profitability. Finally, Federal tax policy can significantly affect

changes in the profitability of non utility projects.

Sensitivity to Federal Tax Policy

The existence of Federal tax benefits for renewable energy projects has been instrumental in the

development of the current nonutility industry.

Both the nonutility IRRC survey and the previous

sensitivity analysis resuIts emphasize the importance of Federal tax credits. Not too surprisingly,

the respondents to the IRRC survey advocated

their continued existence. AA

Federal tax treatment of non utility investment

is currently in flux. The current business energy

credits are due to expire on December 31, 1985.

Failure to extend these credits will markedly reduce project profitability and probably cause an

industry shake-out. In addition, the Treasury Department has proposed a massive “tax simplificat ion .“ This proposal, among other things,

would, if enacted, repeal the 10 percent investment Tax Credit.

wThe 1 RRC survey was discussed i n greater detail earlier in this

section.
Ch. 8—Conventiona/ v. Alternative Technologies: Utility and Nonutility Decisions • 241

These tax policies were analyzed with the OTA

cash flow model. Cross-technology profitability

was

1.

2.

3.

4.

5.

calculated for five tax policy alternatives:

No Tax Incentives–No tax credits, and 15

year SOYD45 depreciation

ACRS Depreciation–No tax credits, 5-year

ACRS depreciation

Investment Tax Crec/it-Same as (2), with 10

percent ITC

10 percent Renewable Tax Credit—Same as

(3), with 10 percent RTC

15 percent Renewable Tax Credit—Same as

(3), with 15 percent RTC.

Case 5 represents current policy. Table 8-1

presents the results of this analysis. Figure 8-15

graphically shows the change in profitability

(cumulative) upon stepping through the five

cases. As can be seen, profitability changes dramatically among the five policy cases. Under the

most likely case scenario, if a 15 percent real rate

of return (20 percent nominal) is assumed to be

the hurdle rate, AFBC and combustion turbine

units are likely to be economic under the No Tax

Incentive case. Inclusion of a 5-year ACRS allows

wind power to become barely profitable. The

Renewable Tax Credits cause a dramatic increase

in profitability. For example, wind power

achieves a real rate of return in excess of 25 percent with a 15 percent tax credit. Geothermal

power also is economic with its 10 percent

Renewable Tax Credit. The other new renewable

technologies–photovoltaics and solar thermal–

also benefit from the Renewable Tax Credits, but

remain the technologies with the lowest IRR.

q5sUm of years Dlglts.

Summary

Generation of electric power by nonutility entities has become an important alternative to electric utility power generation. The existence of a

wide variety of markets and interested investors

outside electric utilities increases the likelihood

that many of the new technologies considered

in this study will be deployed. OTA analysis of

technology profitability indicates that wind power

and AFBC-based cogeneration compete favorably with conventional technology–combustion

turbines—under expected conditions. Because of

current and expected profitability, the commercialization of wind power technology has gone

forward. And investor interest in AFBC should

speed its commercialization as well.

Our analysis shows that the renewable energy

tax credit coupled with recovery of full utility

avoided costs by non utility power producers have

been crucial in both the initial commercial development and the deployment of the new generating technologies. Should avoided cost rates

be low or uncertain, their development and application will be retarded. Conversely, high

avoided costs, stimulated perhaps by rising oil

and gas prices or shrinking reserve margins, might

substantially accelerate their deployment. In addition, without continued favorable tax treatment,

development of much of the domestic renewable

power technology industry will probably be delayed significantly. In particular, without existing

tax incentives, many of the small firms involved

in development projects will lose access to existing sources of capital. Even large, adequately

capitalized firms may lose their distribution networks, leaving the industry struggling to survive.

CROSS-TECHNOLOGY COMPARISON

Overview cannot be addressed in a cost or profitability analysis. The primary issues covered in this section

This section overviews the critical cross-tech- will be the environmental impacts and the ease

nology issues involved in the deployment of the of deploying the technologies. Much of the comtechnologies covered in this assessment. The em- parisons in this section are based on information

phasis in here will be on the nonquantifiable contained in chapters 4, 5, 6, and 7, along with

characteristics of the technologies, i.e., those that previous sections in this chapter.
242 . New Electric Power Technologies: Problems and Prospects for the 1990s

Table 8-2.—Alternative Tax Incentives: Cumulative Effect on Real Internal Rate of Return

Real internal rate of return (percent)

Photo- Wind Solar Fuel Combustion Atmospheric

Tax incentive Geothermal voltaics turbines thermal cells turbine fluidized-bed
Ch. 8—Conventional v. Alternative Technologies: Utility and Nonutility Decisions ● 243

Figure 8-15.—Tax Incentives for New Electric Generating Technologies:

Cumulative Effect on Real Internal Rate of Return*

Renewable energy tax credit or cogeneration tax credit {15°/0)

.

No

.

tax incentives

‘In cogeneratlon appllcatfons

SOURCE Off Ice of Technology Assessment U S Congress

Cross-Technology Issues

The previous sections in this chapter focused

on the relative costs and profitability of the developing technologies. Usually, most utilities and

investors place the greatest emphasis on these

monetary values when making investment decisions. Nevertheless, a host of additional issues can

affect and, in some cases, determine the choice

of electric power technology. These issues include environmental impacts, fuel availability,

and modularity, among others. Table 8-3 displays

a variety of quantitative and nonquantitative characteristics of the technologies under considerateion.

The most striking aspect of this table is the wide

variation in the cost, performance, resource, and

environmental attributes evidenced by the different technologies. The new technologies vary from

small, short lead-time technologies such as wind

power to large, longer lead-time technologies

such as IGCC; from capital-intensive, less mature

technologies like fuel cells to low cost per unit

power, commercial technologies such as geothermal; and from site-specific technologies such as

geothermal to more easily sited technologies such

as photovoltaics. This variation among the technologies makes easy classification of the technologies difficult. Trade-offs between important characteristics such as cost, environmental impacts,

and lead-time must be made prior to selection

of a particular technology. Nevertheless, a few

insights concerning these cross-technology issues

can be made.

First, although the clean coal technologies, i.e.,

AFBC and IGCC, are low in cost per unit power,

and can use a variety of fuels and fuel types, the

potential environmental impacts from these technologies are significant. AFBCS and IGCCS require

sizable quantities of water and land, produce sig-
Table 8-3.-Cross-Technology Comparison: OTA Reference Systems

Solar

parabolic

Technology chacteristics Geothermal Wind power Photovoltaics dish a

Battery

AFBC IGCC Fuel cells CAES storage

General:

Geographic location . .Western U.S. Entire U.S.

Plant sizeb

. . . . . . . . . . . . . . .Small-medium Small

Development status. . . . . . . . Demo- Commercial

commercial

Lead timec

. . . . . . . . . . . . . . Short-medium Short

Siting fiexibilityd . . . . . . . . . . Low Medium

Intermittent? e . . . . . . . . . . . . . No Yes

cost:

Costf

. . . . . . . . . . . . . . . . . . . . . Medium Medium

Profitable? g . . . . . . . . . . . . . . . No Yes

Resoume reoukements and envhvnmental Inmacts:fl

Entire U. S., SW & SE

South better

Entire U.S. Entire U.S. Entire U.S. Entire U.S. Entire U.S.

Small

Democommercial

Medium

High

Yes

High

No

Solar

insolation

Region

specific

Low

Low

Low

Low

Low

Low

High

Low

Small

Demo

Medium

Medium

Yes

High

No

Solar

insolation

Region

specific

Low

Low

Low

Low

Low

Low

High

Low

Large

Commercia l

under

construction

Long

Medium

N o

Large

Demo

Small

Demo planned

Medium-large

No Demo

Small

Pilot

Long

Medium

No

Medium

High

No

Medium-long

Medium

No

Medium

High

No

Low

Yes

Low

N/A

High

No

Medium

N/A

Low

N/A

Primary fuel Source . . . . . . . .Geothermal

brine

Fuel availability . . . . . . . . . . . Limited

Noise . . . . . . . . . . . . . . . . . . . . Medium

Solid wastei

. . . . . . . . . . . . . . . Medium

Alr quality . . . . . . . . . . . . . . . . Medium to

high

Water qualityj . . . . . . . . . . . . .Medium

Water consumption:1

Daily amountm . . . . . . . . . . Low to high

Amount per MWe(net) n Hig h

Land use:

Aereal extento

. . . . . . . . . . . Low

Power densityp . . . . . . . . . . Medium to

high

Wind Coal/solid

fuels

Coal/natural

gas

Natural gas Base load

electricity

plus natural

gas or oil

Not

constrained

Base load

electricity

Limited

number of

quality sites

Medium to

high

Low

Low

Low to

mediumk

Low

Low

High

Low

Not

constrained

Not

constrained

Not

constrained

Not

constrained

Medium Medium Low Medium Low

Medium to

high

Medium to

high

Medium to

high

Medium to

high

Medium

Low Low Low

Low Low

Low Low Low

Medium

Medium

Medium

Medium to

high

Medium

Low Low Low

Low Low Low

Medium

Medium

Low

High

Low

High

Low

High

aEng!ne-mounted solar parabolic cllsh

bslze~ of OTA reference systems, Small = <25 MW, Medwm = 25 to 100 Mw, Large = >100

MW For size ranges expected In the 1990s, see table 4-2 (Alternate Generating Technologies and Storage Technologies: Typical Sizes and Applications).

cShort - <2 years, Medium = 2 to 5 years, Long = >5 years

dRefers to the general ease of siting a powerplant. Ranking IS based on combination Of geographical Iocatlon, fuel availability, and environmental characteristics Low = plant can be sited only

at specific Iocatlons; Medmm = plant can be sited at many locations, but IS constrained by local

resource availability, etc ; High = plant can be sited at most sites with relative aase.

‘Refers to the overall reliability of the powerplant, primarily datly resource variability

fLevellzed cost (1~$) under most likely case scenario Low = <7 Cemkwh; Medium = 7-14

cents/kWh, H!gh = > 14 cents/kWh

gwhether technology can achieve a real rate of return over 15 perCent In nOnutllity applications

under most likely case scenano Assumes no Federal Renewable Tax Credit.

hThese Potential environmental Impacts are based on the reference Plant sizes liat~ above and

focus on direct Impacts from onsite operation Impwts assomated with production of facillty components, or disposal of worn components, are not considered

Unless otherwde noted, the following rating system applles’

. filgh mdtcates substantial likelihood of large Impacts requiring special measures to bring

the facdlty Into compliance with local, State, or Federal enwronmental protection statutes

“High” IS also used to Identify a strong potential for conflicting land use objectives and

problems resulting from compatltion for scarce resources (e g., for water m irngatlondependent

areas) In all of these cases, the result!ng impacts could be serious enough to constrain full

development of a site-specific energy resource

Where awemwsions are concerned, a high rating maybe more reflective of local air quality

cond!tlons than actual emlsslon rates. For example, Iocatlon In a nonattamment area can affect development of any combustion umt large enough to fall under Federal standards

SOURCE: Office of Technology Assessment.

● Medmm indicates that aome special measures may be requred to bring the facility into corn.

pliance with environmental protection atatutes, but these conditions are not likely to serl.

ously limit development.

● Low meana that environmental Impacts are expected to be negligible

● Combination ratings (I.e., low-high) indicate that 1) impacts are likely to vary according to

site-specific charactenstlcs, and/or 2) Impacts vary substantially w!th plant size

IFrom daily plant operation on/y. Weetea associated with production and/or periodic replacement

of plant components are not conaldered.

JThjs Includes any effluent discharge to surface water (e.g., lakes and streams); impacts on ground.

water are not considered

kln~equate eroalon Control in steep terrain COUId lead to increased eedmentation in netiy streems

IAs explain~ in the followlng two footnotes, these ratings reflect the amOUnt Of water used rather

than the consequent environmental impacts of water use. In areas with limited water reaources

and/or heavy competition for exlatmg supplies. technologies wtth a moderate rating under this

catego~ may face siting constraints.

‘Low = <1 million gallons per day; Medium = 1 to 3 gallons per day, High = >3 million gallons

per day

‘Low = < 3,000 gallons par day per MWa(net); High = 3,000 to 20,0C0 gallons par day per MWa(net),

Ff!gh = >20,000 gallons per day per MWe(net)

‘These ratings are based on the land requirements for a 25 MWqnet) plant They suggest where

potential problems may arise regarding visual Impacts, competing land uses, or habitat dlsrup.

tlon Low = s 10 acres; Medium = 11 to 100 acres; High >100 acres Wh!le extensive habitat dls.

rupt!on could occur on a small site (I e , s 10 acres), we have assumed that the affected area would

be Small enough that overall Impacts on the resource In question would not be Ilkely to constrain

development

pRefers to the amount of power produced per acre LOW = <(1 5 MW per acre, Medium = 05 to

5 MW per acre, and H,gh = > 5 MW oer acre

I
Ch. 8—Conventional v. Alternative Technologies: Utility and Nonutility Decisions ● 245

nificant amounts of solid waste, and emit air pollutants. The latter, however, can be controlled

below competing, solid fuel technologies. These

environmental characteristics will likely limit the

deployment of these technologies to remote applications outside of urban areas, possibly to

nonattainment areas (u n less emission offsets are

available). While these technologies have greater

environmental consequences than the other new

technologies, the IGCC and AFBC represent two

of the most promising ‘‘clean coal” technologies.

Therefore, when compared to conventional coal

combustion, the IGCC and AFBC offer substantial environmental benefits.

Second, in general, the renewable technologies—geothermal, wind power, solar photovoltaics, and solar thermal electric—have less severe

environmental impacts than conventional generation alternatives. This attractive environmental

characteristic in combination with the small, modular nature of most of the renewable technologies, should ease siting of these technologies and

aid deployment. There are important differences

among these technologies, though, in terms of

their environmental impacts. Geothermal and, to

a lesser extent, wind power create more environment impacts than solar photovoltaics and solar

thermal electric. For example, wind power installations are highly visible, noisy, require large

amounts of acreage, and can cause erosion problems in environmentally sensitive areas.

Finally, the two technologies which appear to

be the most desirable according to the characteristics listed in table 8-3 are fuel cells and solar

photovoltaics. These two technologies are small,

modular technologies which can be sited in a variety of locations without major environmental

impact in relatively short periods of time. Photovoltaic powerplants use a fuel that is inexhaustible (solar insolation), while fuel cells can use a

variety of fuel types (natural gas, methanol, synthetic natural gas). In the case of these two technologies, therefore, cost and performance will

almost completely determine their market penetration.

Summary

Choice among the new technologies involves

more than just comparison of costs or profitability. At the micro level, this decision is based on

very detailed analysis of engineering, and cost

analyses, site-specific characteristics, and environmental impacts, among others. At the more

general level, the approach taken here, the technologies must be compared with each other, both

in relation to their quantifiable and their nonquantifiable values.

This section has highlighted the complex issues

associated with deployment of the new technologies. Complicated variations exist among the

technologies in terms of their cost, lead-time, and

environmental impacts. On one hand, AFBC and

IGCC are very cost competitive, but their long

lead-times and their relatively large impacts on

the environment could make AFBC and IGCC

hard to site. On the other hand, flexible, relatively

benign technologies like fuel cells and photovoltaics are currently too costly to be deployed in

large numbers. Actual technology choice will depend on specific utility concerns and circumstances.

CONCLUSIONS

New electricity-generating technologies have AFBC and wind power, are in later stages of comthe potential of being competitive with traditional mercialization, and could provide lower cost or

technologies, e.g., pulverized coal, combined cy- more profitable power in the early 1990s. The

cle, combustion turbines, in the 1990s. Several status and costs of other new technologies such

of the new technologies, specifically, small-scale as fuel cells and photovoltaics are uncertain. Al-
246 ● New Electric Power Technologies: Problems and Prospects for the 1990s

though these technologies are potentially competitive, uncertainties surrounding their cost and

performance will slow deployment.

A wide variety of cost-effective strategic options

are also available to electric utilities. These options include plant betterment and life extension,

load management, and interregional power purchases. OTA analysis indicates that these options

are extremely competitive with the traditional

generating technologies, and are less costly than

the new technologies. Consequently, utilities will

probably concentrate on these options prior to

extensive deployment of the new, developing

technologies.

Investment decisions concerning the new technologies will reflect more than just cost comparisons. A variety of nonquantitative characteristics,

particularly modularity and the level and type of

environmental impact, will influence investment

decisions.

APPENDIX 8A: INVESTMENT DECISION CASH FLOW MODELS

FOR CROSS-TECHNOLOGY COMPARISONS

Introduction

This appendix describes the analysis methodologies adopted in this assessment for: 1 ) utility

Ievelized busbar cost calculations, and 2) nonutility profitability measurement. These methodologies are the basis for the cost and profitability estimates provided in chapter 8. The analysis

approach in these models is a modified version

of the Alternative Generation Technologies model

developed by Battelle Columbus Laboratories.1

The modifications generally allow the model to

more accurately calculate electric utility revenue

requirements and nonutility profitability measures. The estimates produced by these calculations can be compared with utility-reported costs

and nonutility-reported rates of return.

Electric Utility Levelized Busbar Cost

Since electric utilities are regulated, utility

shareholders receive a set return on their investment. The revenue necessary to produce this set

income, often termed the revenue requirement,

includes three major components: capital cost

carrying charges, interest charges, and fuel and

operating expenses.

‘ Battel Ie Columbus Division, Fina/ Report on Alternative Generation Technologies, Nov. 18, 1983 (Columbus, OH: Battelle, 1983).

Capital Cost Carrying Charges2

The charges associated with a capital investment can be split into three basic categories: 1 )

depreciation, 2) return, and 3) income taxes associated with the investment.

An annual revenue stream is required to recover the initial capital cost of a new electric generation facility. Book depreciation is the mechanism used to generate the funds needed for this

carrying charge component. Book depreciation

in year i (Dbi) is defined as

[1]

where I is the total capital cost of the facility (includes Allowance for Funds Used During Construction) and nb is the book life in years. Accumulated book depreciation in year i (Cbi) is the

sum of all the previous years’ depreciation, i.e.

(–1 C b

, = ,~, D b, [2]

The electric utility also earns a return on the

invested capital. The return on capital in year i

(Rl

) can be found by multiplying the required

rate of return k by the remaining undepreciated

book value of the facility. (The required rate of

2 This section draws heavily on Peter D. Blair, Thomas A.V. Cassel, and Robert H. Edelstein, Geotherrna/ Energy: /nvestrnent Decisions and Commercial Development (New York: John Wiley &

Sons, 1982) and Philadelphia Electric Co., Engineering Economics

Course (Philadelphia, PA: Philadelphia Electric Co., January 1980).
Ch. 8—Conventional v. Alternative Technologies: Utility and Nonutility Decisions ● 247

Figure 8A-1 .—Calculation of Capital Cost per

Kilowatt-Houd

180

160 - ? 5 %

140 “

120 -

100 -

80 -

60 —

40 -

20

0

0 2 4

The third component of capital cost carrying

charge is the income tax liability associated with

the project. The total tax liability in year i can be

determined by multiplying taxable income by the

composite tax rate t. The composite tax rate (t)

is a weighted combination of the State tax rate

(ts and Federal tax rate (t,):

t = t, + tt

(l – t,)

Total taxable income is found by deducting

debt interest (Kl

) and tax depreciation (Dti) calculated from the accelerated depreciation schedules,3 from the revenues received4

:

T, = t(Db, + R, + T, – Kdl – Dt,) [4]

The calculation of tax liability is complicated,

however, by the use of accelerated depreciation.

The use of accelerated depreciation procedures

[8]
248 . New Electric Power Technologies: Problems and Prospects for the 1990s

ment of an electric utility, which often computes

FCRs for internal planning purposes. While there

is no fundamental difference between Ievelized

busbar costs calculated by either method, the

methodology presented herein more easily captures significant revenue requirement differences

on a year-by-year basis. Moreover, this method

is more flexible in handling different equipment

lifetimes, ACRS categories, and levels of capital

intensiveness associated with alternative technologies.

Nonutility Profitability

Consistent cross-technology financial comparison for non utility electricity producers is best

achieved with profitability measures. Although

Ievelized cost values are perhaps convenient for

comparative purposes, the financial community

generally uses profitability measures (rate of return, payback period, and net present value) for

investment decision making purposes. Measurements of nonutility profitability can be derived

in a more straightforward fashion than utility revenue requirement estimation—since nonutility income and taxation calculations are not complicated by tax normalization and regulated return

adjustments.

The analysis technique adopted for the project is the standard discounted cash flow methodology accounting for the three major components of nonutility cash flows: revenue, operating

costs, and after tax income. The various profitability measures are calculated based on after tax

cash flow.

Revenue

The revenue achievable from a new technology project is assumed to be based primarily on

prevailing utility avoided cost rates. Avoided cost

revenue in year i (AR,) is based on both avoided

energy and avoided capacity credits:

AR, = 8760AEiCFIC + ACIIC [15]

where AEI ($/kWh) and AC, ($/kW) are the

avoided energy value and avoided capacity

values, respectively, in year i (determined by applying an assumed escalation to the base year

value), CF is the capacity factor, and IC is the in-
Ch. 8—Conventional v. Alternative Technologies: Utility and Nonutility Decisions Ž 249
250 ● New Electric Power Technologies: Problems and Prospects for the 1990s

meet when making new investment decisions. positive returns after discounting for the time

The length of the project’s payback period, the value of money, and 2) the relative level of innumber of years necessary for project revenues come provided by the project. All of these tools

to payback the initial outlay, is also used as a can be used to compare alternative investment

screening tool. Net present value provides infor- projects.

mation on: 1 ) whether the project will provide
Chapter 9

The Commercial Transition for

Developing Electric Technologies
CONTENTS

Page

Overview . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ....285

GoalA: Reduce Capital Cost Improve Performance, and Resolve Uncertainty. . ......286

Goal B: Encourage Nonutihty Role in Commercializing Developing Technologies .. ...290

GoalC: Encourage Increased Utility Involvement in Developing Technologies. . ......295

Goal D: Resolve Concerns Regarding lmpact of Decentralized Generating

Sources on Power System Operation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ... ... ...299

List of Tables

Table No. Page

10-1. Policy Goals and Options . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..................285

10-2. Alternative Tax Incentives: Cumulative Effect on Real Internal Rate of Return ....293

List of Figures

Figure No, Page

10-1. Tax incentives for New Electric Generating Technologies: Cumulative Effect

on Real Internal Rate of Return. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..291

IO-2. Breakeven Utility Buy-Back Rates . . . . . . . . . . . . . . . . . . . . . ...................292
Chapter 9

The Commercial Transition for

Developing Electric Technologies

INTRODUCTION

This chapter discusses past development of the

electric generating and storage tech nologies examined in this assessment, and discusses their

commercial outlooks. Factors which constitute

serious impediments to widespread commercial

deployment in the 1990s–assuming a demand

for additional generating or storage capacity’ –

are identified. Deployment levels will depend on

a combination of changes in cost, performance,

uncertainty, and other changes i n the com mercial environment within which the technologies

are developing.

‘This assumption IS an important one, as a general lack of demand for additional generating capacity could itself constitute the

major impediment to the deployment of the technologies in the

1990s.

STATUS AND OUTLOOK FOR THE DEVELOPING TECHNOLOGIES

Solar Photovoltaics

History and Description of the Industry

Photovoltaic cells (PVs) first were developed in

the 19th century. In the 1950s and 1960s, a combination of technical breakthroughs and the need

to power spacecraft stimulated substantial cost

reductions, performance improvements and wider

applications. During this period, Federal support,

channeled primarily through the space program,

was the dominant stimulus to the technology’s

progress.

In the 1970s PVs entered larger terrestrial markets, the most important of which was power generation in remote locations. A notable trend during the 1970s was the growing support for PVs

by large petroleum-based companies and the

Federal Government. In 1978, Federal support

was solidified by the passage of several key laws

which provide for a program of research, development, and demonstration and for direct Government purchase of large numbers of solar cells.2

‘The most important laws were: 1 ) the Federal Photovoltaic Utl -

Iization Act of 1978 (Public Law 95-619, Part 4); 2) the Solar Photovoltalc Energy Research, Development, and Demonstration Act of

1978 (Public Law 95-590); and 3) the Department of Energy Act

of 1978 (Publtc Law 95-238, Section 208).

From 1980 to 1985, about 30 laboratories across

the country were conducting PV research.3 By

1985, the price of PV modules decreased 80 percent (in constant dollars) from $35,400/kWe in

1976 to $7,000/kWe in 1984; performance also

improved markedly. The volume of sales increased

rapidly as world PV shipments increased over a

hundredfold from 240 kWe in 1976 to 25,000

kWe in 1984. Total revenues increased twentyfold, from $6.8 million to $174 million during the

same period. Q

In the 1980s the PV industry changed considerably. By 1985, the industry consisted mainly of

companies which were affiliated with large mu 1-

tinational petroleum-based corporations. By the

early 1980s, many companies sought to concentrate their operations towards the raw material

3

Larry N. Stoiaken, “A New Generation of Photovoltaics. Commercialization Efforts Gain Momentum, ’ Alternative sources of

Energy, vol. 67, May/June 1984, pp. 6-15.

4See: 1 ) Strategies U n I i m ited, Arta/ysls of Equipment A4anufacturers and Vendors In the Electric Power Industry for the 1990s.

Wind Turb/nes, Solar Thermal Electric, Photovoltaics (Mountain

View, CA: Strategies Unllmited, December 1984), OTA contractor

report. 2) Pau I D. Maycock and Vic S. Sherlekar, Photovo/taic Technology, Performance, Cost and Market Forecast to 1995. A Strategic Technology & Market Ana/ysis (Alexandria, VA: Photovoltalc

Energy Systems, Inc., 1984).

253
254 ● New Electric Power Technologies: Problems and Prospects for the 1990s

end of the production process, emphasizing cell

or module production. At the other end of the

production chain, however, decentralization occurred, i.e., companies sold off or closed down

operations involving other system components

than the PV arrays themselves. As the technologies developed and market prospects changed,

businesses also shifted emphasis among the different PV systems.

The market during the first half of the 1980s

is depicted schematically in figure 9-1. During this

period the United States dominated world production, with Japan ranking a distant second. The

end-use markets for 1984 are broken down in

table 9-1. The table highlights the importance of

the U.S. central station market both as a fraction

of the U.S. market and of the world market. The

application of the Public Utility Regulatory PolFigure 9.1 .–1984 World Photovoltaics Supply

I United States I

I Europe I I Japan I Other

I

World production

1

18.5 MWp

SOURCE: Strategies Unlimited, “Analysis of Equipment Manufacturers and Vendors in the Electric Power Industry for the 1990s, ” contractor repotl prepared for the

Office of Technology Assessment, U.S. Congress (Mountain View, CA: Strategies Unlimited, Dec. 7, 1984).
Ch. 9—The Commercial Transition for Developing Electric Technologies ● 255

Table 9.1 .—Estimated Magnitude of End”Use Markets

for Photovoltaics, 1984

MWe(p) shipped

Market sector worldwide

World consumer products. . . . . . . . . . . . 5

U.S. off-the-grid residential . . . . . . . . . . . 2

World off-the-grid rural. . . . . . . . . . . . . . . 0.2

Worldwide communications . . . . . . . . . . 5

Worldwide PV/diesel . . . . . . . . . . . . . . . . 2

U.S. grid-connected residential . . . . . . . 0.1

U.S. central station and third-party

financed projects . . . . . . . . . . . . . . . . . 10

Total MW . . . . . . . . . . . . . . . . . . . . . . 24.3

Japanese grid-connected. . . . . . . . . . . —

Total MW . . . . . . . . . . . . . . . . . . . . . . 25

Price ($/Wp) . . . . . . . . . . . . . . . . . . . .

Revenues ($ M) . . . . . . . . . . . . . . . . . $175

SOURCE Paul D Maycock and Vic S. Sherlekar, Photovo/faic Technology, Performance Cost and Market forecast to 1995 A Strategic Technology

and Market Analysis (Alexandria, VA Photovoltaic Energy Systems,

Inc , 1984)

icies Act of 1978 (PURPA) and favorable Federal

and State (especially California) tax policies was

very important in encouraging the deployment

of photovoltaics in these facilities.

Federal support for photovoltaics during the

first half of the 1980s shifted considerably in emphasis. Direct expenditures in support of photovoltaics declined in importance after peaking in

1980-81, but they continued to have a substantial effect on the development oft he technology

(see table 9-2). While the Federal Government

has concentrated on high risk research and deTable 9-2.—Federal Program Funds in Support

velopment (R&D) with potentially high payoffs,

some direct support was provided elsewhere. Export promotion was recognized as an important

element in any program to encourage photovoltaics and assumed a more prominent position

among Federal efforts in the 1980s. The Federal

Government also continued to support a major

demonstration project in California. As direct Federal support declined, indirect support for photovoltaics through tax incentives increased during

this period and strongly influenced the rate of

progress in the industry.

Industry Outlook and Major Impediments

The 1990s likely will witness rapid growth in

the application of hybrid photovoltaics/diesel

power systems in remote areas, primarily overseas. Indeed, this market could dominate world

PV deployment during the period. Also very important will be grid-connected PV plants in the

United States and in Japan. At the same time, the

worldwide communications and consumer-products markets wiII continue to be of major significance to the industry. The magnitude and relative importance of different market segments, and

the character of the industry itself, will depend

heavily on whether or not the Federal Renewable Energy Tax Credit (RTC) is extended beyond

1985. The exact effect of either action, however,

is difficult to accurately predict.

of Developing Technologies (millions of dollars)

Year

1986

Technology 1975 1976 1977 1978 1979 1980 1981 1982 1983 1984 1985 (requested)

Wind . . . . . . . . . . . . . . . . . . . . . . . . . 7.9 14.4 27.6 35.5 59,6 63.4 54.6 34.4 31.4 26.5 29.1

Photovoltaics . . . . . . . . . . . . . . . . . . 5.2 21.6 59.7 76.2 104.0 150.0 152.0 74.0 58.0 50.4 57.0

Solar thermal . . . . . . . . . . . . . . . . . . 13.2 20.6 79.1 114.7 109.3 135.0 120.0 56.0 50.0 43.9 35.5

Geothermal. . . . . . . . . . . . . . . . . . . . 28.0 78.3 76.7 132.9 188.4 171.0 156.3 86.6 73.6 30.5 32.1

AFBC . . . . . . . . . . . . . . . . . . . . . . . . . 2.0

a

7.0 21.2 24.5 23.6 25.9 11.4 0.3 4.9 1.4 18.7

Surface coal gasification

(includes IGCC) . . . . . . . . . . . . . . 116.3 117.7 143.2 208.2 122.4 123.3 70.0 54.2 39.0 36.5 32.0

Fuel cells c . . . . . . . . . . . . . . . . . . . . n/a 3.0 17.8 33.0 41.0 26.0 32.0 34.5 29.9 42.3 40.8

Batteries d . . . . . . . . . . . . . . . . . . . . . 2.9 6.8 9.7 11.2 15.3 20.3 13.9 12.9 12.8 12.8 8.4

CAES . . . . . . . . . . . . . . . . . . . . . . . . . 0.0 0.6 1.2 4.5 4.5 3.2 2.1 2.0 0.0 0.0 0.0

20.8

44.8

28.4

12.0

17.3

15.0

9.3

6.3

0.0

Total . . . . . . . . . . . . . . . . . . . . . . . 175.5 270.0 436.2 640.7 668.1 718.1 612.3 354.9 299.6 244.3 253.6 153.9

%TA estimate.

bDoes not include support from the Synthetic FIJ@lS CorP.

clncludes funding for all fuel cells R&D and is not restricted to phosphoric acid fuel cells

dThe funding levels listed are the estimated levels of suppo~ for all stationary batteries, including but not restricted to Iead-acid batteries and zinc-chlorlde batteries.

The estimates assume that roughly 50 percent of the funding for DOE’s Electrochemical Program IS applicable to stationary batteries

SOURCE U S Department of Energy, Congressional/ 8udgef Request” H’ 7986 (Washington, DC” U S. Government Printing Office, 1985) and the corresponding documents for prevelous years
256 ● New Electric Power Technologies: Problems and Prospects for the 1990s

if the RTC is not extended in any form, the

overall level of deployment is likely to be greatly

diminished and it is likely that the largest markets would be the worldwide PV diesel markets

and grid-connected applications in Japan. important, but considerably smaller markets would be

world consumer products, remote communications systems, and, finally, grid-connected power

systems in the United States.

Termination of the tax credits would have especially severe effects on grid-connected central station applications involving third-party ownership.

According to one analysis, this sector by the end

of 1986 would shrink by 35 to 85 percent of what

it would be with a continuation of the tax credit;

by 1990, it would be 5 to 10 times smaller (see

table 9-3).5

The character of the industry might change as

well, with the larger companies in the business

withdrawing or greatly reducing their involvement. As a result of depressed oil prices, the oil

companies are already cutting back their involvement outside of the petroleum industry. b Less

favorable tax treatment of PV investments could

cause these firms to scrutinize their commitment

to photovoltaics even more closely.

Smaller firms, particularly those heavily devoted to the central station market, may be hit

hardest. Of special importance is the small segsJet propulsion Laboratory, Effects of Expiration of the Federal

Energy Tax Credit on the National Photovoltaics Program (Pasadena,

CA: jet Propulsion Laboratory, 1984), DOE/ET-20356-l 5.

‘Winston Williams, “Big Oil Starts Thinking Smaller, ” New York

Times, Mar. 17, 1985, sec. 3 (Business), pp. lff.

ment of the industry dedicated to the concentrator technologies. Several of these companies

are quite small. Expiration of the RTCs is likely

to severely affect these businesses, greatly limiting the deployment of this promising PV option

in the 1990s.7 Industry dominance could then

pass swiftly to the Japanese and the Europeans,

whose aggressive and effective PV programs

could enable them to dominate overseas markets,

and, perhaps, even to capture a large portion of

U.S. central station markets by the end of the

century.

If, however, the tax credits are extended in

some form, the results could be quite different.

First, and most directly, for a given photovoltaic

system, the level of demand in the United States

could be higher than it otherwise would be. Second, the actual cost and performance of PV systems would improve, as the higher demand stimulated innovation and high volume production.

This in turn could encourage growth in demand

both in the United States and overseas. Finally,

larger deployments in the near term would in

many other ways accelerate subsequent deployment of photovoltaics. The infrastructure necessary to produce, deploy, and operate PV systems

would develop more rapidly, overall experience

with the technology wouId be greater, and institutions—e.g., utilities, public utility commissions,

local permitting authorities, and others–could

adapt sooner to the technology.

Zjet propulsion Laboratory, Effects of Expiration of the Federal

Energy Tax Credit on the National Photovoltaics Program, op. cit.,

1984.

Table 9-3.—Projected 1986 Photovoltaic Shipments by Domestic Manufacturers

With tax credit expiration With extended tax credits

Shipments Share of market Shipments Share of market

Market sector (MW) (percent) (MW) (percent)

Residential, non-grid-connected . . . . . . . . . . . . 5 12.5-7.7 8-10 10.0-8.3

Residential, grid-connected . . . . . . . . . . . . . . . . 1 2.5-1.5 2-5 2.5-4.2

Electric utility (third party) . . . . . . . . . . . . . . . . . 10-25 25.0-38.5 40-60 50.0

Water pumping. . . . . . . . . . . . . . . . . . . . . . . . . . . 2-3 5.0-4.6 3-7 3.8-5.8

Communications . . . . . . . . . . . . . . . . . . . . . . . . . 7-9 17.5 -13.8 9-11 11.2-9.2

Other industrial (includes government

experiments) . . . . . . . . . . . . . . . . . . . . . . . . . . . 5-7 12.5-10.8 8-12 10.0

International . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-15 25.0-23.1 10-15 12.5

Totals. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 40-65 100.0-100.0 80-120 100.0-100.0

SOURCE” Jet Propulsion Laboratory, .Effects of Ex@ration of the Federal Errer9y Tax Credt on the tVatlona/ Hrotovoltaics Program (Pasadena, CA: Jet Propulsion Lalmratory,

1984), DOE/ET-20356-15.
Ch. 9—The Commercial Transition for Developing Electric Technologies ● 257

The cumulative .effect of extension of the RTC

on market size and distribution could be considerable. Virtually all market segments would be

larger, some considerably more important than

they otherwise might be. Dramatic growth could

occur in the volume of sales of photovoltaics for

use in PV/diesel hybrid systems in remote overseas applications. This market qlJickly could

come to dominate the international PV market,

The U.S. central station market would also be

much larger.

Extension of the RTCs also will affect the relative importance of different PV designs. Rapid

growth in the deployment of concentrate systems could be stimulated, along with other systems that are favored in central station applications.

Continuation of Federal tax support also could

strengthen the position of U.S. manufacturers

over foreign competitors—both here and overseas. Overseas competitors, especially the Japanese, are moving rapidly ahead in PV—often with

the support of their governments. Tax credit support could serve to slow the erosion of the U.S.

position in the industry and perhaps even reverse

the trend.

While the issue of the RTC dominates current

discussion of the outlook for the photovoltaics

industry, a broad range of other factors will affect the prospects for photovoltaics during the

1990s. These are discussed below.

Equipment Cost and Performance. -If PV systems in the 1990s were identical to those available today, they probably could not compete extensively and successfully with the alternatives in

U.S. grid-connected applications. Current levels

of cost and performance are too high. Investments in both R&D and in industrial capacity to

mass produce the technology will be required.

The present status of the technology and the

changes necessary for extensive commercial application in the 1990s are discusred in chapter 4.

The Risk of Obsolescence.–The technologies

of photovoltaics are evolving rapidly. This rapid

rate of change may discourage would-be investors from investing in production lines out of fear

that their investments could quickly become outdated in the event of technological breakthroughs,

Some industry observers think that this is the reason the U.S. industry has been reluctant to invest

in the facilities necessary to mass produce crystalline silicon modules. Instead, it largely has

opted for the longer term payoff which might be

obtained from the less mature amorphous silicon

technology. Should progress in the amorphous

technology prove slower than expected, the relative lack of emphasis in the U.S. industry on commercial production of crystalline silicon may delay commercial deployment of photovokaics, and

foreign competitors, most likely the Japanese,

may seize the opportunity to increase their market share by selling crystalline silicon modules in

the United States and abroad.8

Solar Resource Assessment.—The current

knowledge of the solar resource in the United

States is insufficient for the optimum design and

siting of PV plants. The best available information is the SOLMET data, based on several years

of readings at 26 sites.9 The SOLMET data gives

monthly averages of solar insolation for each hour

at typical geographic locations.

While such figures are useful for calculating

generic capacity factors and peak system outputs

for a particular region, the characteristics of a particular site may be significantly different than the

average. Before utilities can integrate photovoltaics into their operations, they must have a

detailed understanding of PV operating dynamics,

based on a minute-by-minute understanding of

the insolation patterns at a site.10

Also, to optimize the design of PV modules, it

will be necessary to understand much more

about the detailed spectral and directional distributions of light energy as a function of timeof-day and day-of-the-year. Such information not

only influences the decision of whether or not

tracking systems are cost effective, but it also affects the detailed design of the cells, since the

‘Roger G. Little, President, Spire Corp., testimony presented in

hearings held by the Subcommittee on Energy Development and

Applications, House Committee on Science and Technology, U.S.

Congress, The Status of Synthetic Fuels and Cost-Shared Energy R&D

Facilities (Washington, DC: U.S. Government Printing Office, 1984),

No. 106, june 6, 7, and 13, 1984, pp. 386-389.

9Roger Taylor, Photo~’o/talc Systems Assessment: An /ntegrated

Perspective (Palo Alto, CA: Electric Power Research Institute, September 1983), EPRI AP-3176-SR.

IOlbid.
258 ● New Electric Power Technologies: Problems and Prospects for the 1990s

light absorption and current carrying capacity of

these cells must be carefully matched to the solar spectrum.11

Cost and Performance Data.–A serious obstacle to timely deployment of photovoltaics in

any application is the lack of accurate and useful information about the technology and its economics. What are the specific capital costs of a

specific PV system? How will it perform at a specific locality? What kinds of operating and maintenance expenses might be incurred? This problem already has been an obstacle in overseas

applications where investors often do not know

enough about PV cost and performance or lack

the analytical means to adequately compare photovoltaics to conventional alternatives .12

Standards.–The lack of standard definitions,

testing methods, and other criteria relating both

to PV modules and balance of system equipment

reportedly has hindered development and deployment. it is thought by some that the application of standards ultimately will expedite the

commercial application of the technology. Several groups are working on such standards,

though who should set and enforce them is a

matter of considerable controversy within the industry.

Warranties.–The extent to which warranties

are avaiIable, and the nature of such warranties,

will strongly affect the commercial success of PV

systems in the 1990s. It was not until late 1984

that anyone in the industry offered even a limited

warranty and an Underwriters Laboratories listing for a PV module. 13 Vendors wiII be reluctant

to provide strong extended warranties until the

technology has been adequately proven in real

conditions. This requirement likely will put relative newcomers such as amorphous-silicon moduIes at a disadvantage until sufficient experience

—.—

110TA staff interview with Charles Gay, Vice President, Research

and Development, ARCO Solar, Inc., Aug. 10, 1984.

12 For example, see: Clyde Ragsdale, manager of Marketing for

Solavolt International, testimony presented to the Subcommittee

on Energy Development and Applications, House Committee on

Science and Technology, U.S. Congress, Hearing on the Current

State and Future Prospects of the U.S. Photovoltaics Industry, Sept.

19, 1984,

‘

3

’’ Slants and Trends, ” Solar Energy /nte//igence Repofi, vol. 10,

No. 43, oct. 29, 1984, p. 339.

is built up.14 The ability to provide extended warranties will be influenced greatly by the amount

of capital available to the industry, which in turn

will depend on market size and profit margins.

Utility Energy and Capacity Credits, and interconnection Requirements.—Grid-connected

PV plants can be owned by utilities or by others.

As discussed earlier with wind systems, low energy

credits, low capacity payments, and stringent interconnection requirements discourage deployment by nonutilities. Even where the possibility

exists that credits couId drop during the lifetime

of a project, investment is discouraged. Also, any

difficulties (such as delays) encountered in seeking to obtain favorable credits or interconnection

requirements discourages nonutility deployment.

Overseas Markets.–Overseas markets will

serve to encourage mass production of PV systems and hence lower costs. The larger market

also will serve to indirectly stimulate technical development which could lead to further reduced

costs or improved performance. As a result of

such improvements the exploitation of overseas

markets could help ensure that U.S.-made systems remain competitive in the domestic market.

Current evidence suggests that the U.S. photovoltaics industry is not as successful as it could

be in overseas markets; as mentioned earlier, the

situation will be exacerbated with the scheduled

termination of the renewable energy tax credits.

Meanwhile, competitors–especially the Europeans and the Japanese–are more actively and

successfully developing these markets, often supported by favorable government programs. Failure to fully exploit export markets could slow the

development of U.S. photovoltaics, extend the

period required before extensive grid-connected

applications will occur, and increase the likelihood that large segments of the U.S. market will

eventually be served by foreign vendors.

1

4

’’lntense Competition Among Five Silicon Technologies Seen

for PV: Maycock, ” Solar Energy Intelligence Repoti, Apr. 2, 1984,

p. 110.
Ch. 9—The Commercial Transition for Developing Electric Technologies ● 259

Solar Thermal Electric Plants

History and Description of the Industry

By 1879, the French had converted solar radiation into thermal energy and produced small

quantities of electric power. Though this work led

to the operation of several demonstration units,

the devices proved to be prohibitively expensive

to build and operate, and the idea of producing

electric power from solar thermal energy was

largely abandoned. Not until nearly 100 years

later was heat derived from the Sun widely considered as a means of producing electric power.

A variety of solar thermal electric technologies

are now being developed. But as discussed in

chapter 4, their current status and prospects differ substantially. The solar pond technology faces

many limitations that make widespread commercial application within this century unlikely. The

prospects for three other technologies–central

receivers, parabolic troughs, and parabolic dishes

—are brighter. The histories of these technologies

in the United States have been shaped by the

Federal role in their development. Their prospects

in the 1990s likewise probably will also depend

heavily on Federal activity between now and the

end of the century.

Direct Federal sponsorship of the technologies

rose rapidly in the 1970s, spurred by the desire

to develop technologies which were less vulnerable to fuel disruptions and price increases, and

which had less severe environmental impacts

than many conventional technologies. But direct

Federal support has declined from $135 million

in 1980 to less than $36 million in 1985 (see table 9-2). The impact of the decline was offset in

part by an increase in indirect support in the form

of tax incentives during the first half of the 1980s.

The effects of conservation, which moderated

conventional fuel prices, also dampened the

prospects for near term-commercial success.

During the latter half of the 1970s and the early

1980s, the central receiver technology progressed

rapidly, culminating in 1982 with the operation

of a 10 MWe pilot plant, the Solar One pilot faI Jl(en Butti and John Perlin, A Go/den Thread (New York: van

Nostrand Reinhold Co., 1980).

cility. Eighty percent of that project’s costs were

paid by the Department of Energy (DOE). The

plant, while not of commercial scale, has operated quite successfully.

Private sector involvement in the central receiver technology has primarily involved electric

utilities as well as equipment developers and vendors. These and other private investors, however,

have been unwilling to invest in a commercial

plant without Government subsidy, until they had

evidence of a successfully operating close-tocommercial unit. Yet neither the private nor public sector participants, alone or in cooperation

with each other, have been willing to finance a

commercial demonstration unit. Various parties

have sought ways around this impasse; others

have disbanded and moved away from the technology, assuming that the combined effects of

Federal spending cutbacks, the impending expiration of the renewable energy tax credits, and

other factors preclude extensive commercial deployment in the near term.lb By mid-l 985, work

on the central receiver technology was confined

primarily to federally supported research and development at DOE’s Central Receiver Test Facility and on federally funded efforts at the Solar

Energy Research Institute to develop low cost and

durable heliostats.

The parabolic troughs, meanwhile, progressed

much further into the market place. By the early

1980s, the Federal Government had funded nearly

a dozen experiments and demonstrations. The

technology had reached the point where it was

nearly ready for commercial applications.

The relatively short lead-time of the technology allowed the Luz Engineering Corp. to initiate two projects which could be completed soon

enough to exploit the Federal renewable energy

tax credits even if they expired as planned at the

end of 1985. Because the projects were in CalilbThe central receiver teams at Martin Marietta, Boeing, Rockwell, and to a large extent McDonnell Douglas are being disbanded.

In addition, the government and utility support teams at Sandia

Livermore, Sandia Albuquerque, Jet Propulsion Laboratory and Electric Power Research Institute also are being disbanded and the personnel being transferred to other positions. See Strategies Unlimited,

Analysis of Equipment Manufacturers and Vendors in the Electric

Power Industry for the 1990s. Wind Turbines, Solar Thermal Electric, Photovo/taics, op. cit., 1984).
260 ● New Electric Power Technologies: Problerns and prospects for the 1990s

fornia, they could also enjoy State tax incentives,

favorable solar insolation levels, and high utility

avoided cost energy payments. I n December

1984, the first of the two plants, known as Solar

Electric Generating System-1 (SEGS-1) and capable of producing 13.8 MWe, had begun operating. By February 1985 construction of a second

33 MWe pIant (SEGS-11) was initiated and was expected to begin operating by late 1985 or early

1986. Luz designed these systems, coordinated

the projects and was an investment partner in

them. The remainder of the investment was provided mostly by large institutional investors

through a limited partnership. The system’s performance was guaranteed for 20 years by Luz industries (Israel) Ltd., the parent firm, which also

provided an insurance policy for the project.

Southern California Edison agreed to purchase

the power for 30 years. C)ther than the Luz

projects, private sector involvement in the trough

technology is limited.

Federal support for parabolic dishes developed

somewhat later than for the central receiver and

troughs. As a result, their development has lagged

behind that of the other solar thermal electric

technologies. However, the efforts of over half

a dozen firms, coupled with direct Federal support and other favorable conditions (including

Federal and State tax incentives and the provisions of PURPA) fostered rapid development of

the technology, especially during the first half of

the 1980s. Notable was the fact that among the

firms whose support of parabolic dishes increased

during the period were several who previously

concentrated on either the central receiver or

parabolic troughs.17

By mid-l985, a privately financed commercial

dish facility had been installed by the LaJet Energy

Co. in southern California. It was financed by the

parent company, La Jet, Inc.–a privately held

petroleum exploration, drilling, and refining company–and through limited partnerships. Mean1 zMcDonnellDouglas, now a major supporter of the dish tecl-rnology, previously was heavily involved with the central receiver.

Acurex Solar Corp. presently is emphasizing dish technologies too,

after having focused its solar thermal electric efforts on trough technology. Acurex still is working on trough technology, but it is emphasizing the use of the technology for industrial process heat or

cogeneration.

while, other commercialization efforts were proceeding, the most important of which appeared

to be the joint venture of McDonnell Douglas,

an aerospace corporation active in the energy

field since the early 197os, and United Stirling,

AB, a Swedish manufacturer of Stirling engines.

Industry Outlook and Major Impediments

As discussed in chapter 4, widespread commercial deployment of solar thermal electric technologies is unlikely unless costs are reduced, and

performance improved. Moreover, investor interest is not likely to be forthcoming until performance is demonstrated.

As with photovoltaics, wind, and geothermal

technologies, the Federal Government’s policies

strongly influence the outlook for the solar thermal electric industries. Without either an increase

in direct Federal support or an extension of the

renewable energy tax credits beyond 1985, none

of the solar thermal technologies is likely to be

used much commercially in the 1990s.18 After

1985, the limited solar thermal electric industry

which exists today is likely to shrink rapidly. The

commercial activities of Luz in solar troughs and

La Jet in parabolic dishes probably would be cut

back substantially, as would the efforts of other

smaller, entrepreneurial companies in the industry. Only the largest companies may be able to

sustain the involvement required to successfully

deploy the technology in the 1990s.l9

Even with increased direct Federal support and

favorable tax policies, with the necessary cost and

performance improvements, and with commer-

-—.—- —.——

laThiS was reflected in the testimony of Frank F. Duquette before the U.S. Congress on Mar. 1, 1984. He stated that:

The nearer term technology at this stage of development, still requtres Federal support to reduce technical risk and valldate commercial or near commercial applications, Prtvate industry is unable

to assume the entire burden of completing the R&D tasks remalnlng

for this current generation of technologies.

(Frank F. Duquette, Chairman, Solar Thermal Division, Solar Energy

Industries Association, testimony presented to the Subcommittee

on Energy Development and Applications, Committee on Science

and Technology, U.S. Congress, Mar. 1, 1984. )

Igsee: I ) Strategies Unlimited, Arta/ysis of Equipment MarrUfacturers and Vendors in the Electric Power Industry for the 1990s.

Wind Turbines, Solar Thermal Electric, Photovoltaics, op. cit., 1984;

2) Peter B. Bos and Jerome M. Weingart, /mpact of Tax /ncentives

on the Commercialization of Solar Thermal Electric Technologies

(LiVermore, CA: Sandia National Laboratories, August 1983), SAND

83-8178.
Ch. 9—The Commercial Transition for Developing Electric Technologies ● 261

cial demonstrations, success is still by no means

guaranteed for these technologies in the 1990s.

There are other potential impediments to their

deployment. Among these might be problems relating to energy credits, capacity payments, and

interconnection requirements. Problematic too

could be the lack of widespread experience with

the technology; and licensing and permitting delays (among which extensive land impacts and

access to water might figure importantly).

In some cases, problems also may develop with

regards to the Fuel Use Act. The leading trough

technology, that employed at the SEGS-I and II

plants in California, requires natural gas to supplement the solar energy in producing steam for

the steam turbines. Currently, the Fuel Use Act

prohibits the use of gas and oil in many new generating facilities except u rider special conditions.

While exemptions to the law may be obtained,

the law could delay or even prohibit construction of oil- or gas-using facilities.

The following sections discuss for each technology some of these impediments as well as

problems which are crucial to the individual technologies,

Central Receivers.—For the central receiver

technology, one impediment stands out among

all others—the lack of a commercial-scale demonstration plant, Unless such a plant is initiated

very soon and begins operating before the end

of the decade, the prospects for this technology

in the 1990s are very limited. Should a demonstration plant be initiated later than this, it will

be extremely difficult in the time remaining to

overcome the many other obstacles blocking significant contribution by this technology to power

production in the 199os. In particular, the lack

of a commercial demonstration project in the

near future is likely to lead to the continued disbanding of organizations originally established to

deploy both a demonstration plant and subsequent commercial units.

Several attempts to finance demonstration units

by private sources have been initiated but have

failed. Hence, it appears unlikely that such plants

wiII be buiIt without Government support .*0

IOThe need for further government support repeated Iy su rface$

both in the literature and in conversations with knowledgeable inWithout timely Government action, this technology’s prospects are likely to be severely Iimited

during. the 1990s. Other major impediments

which could limit deployment, even if there is

prompt construction of a demonstration plant,

are: 1 ) the high cost of heliostats, 2) technical

problems with the central receiver and other

components, and 3) various nontechnical problems relating to such things as licensing and permitting.

Parabolic Troughs and Dishes.–Unlike the

ponds and central receivers, parabolic dishes and

parabolic troughs, financed by private investors

assisted by State and Federal renewable energy

tax credits, already have been deployed and operated in commercial-scale units. Both for dishes

and troughs, the combination of cost and performance characteristics and numerous uncertainties at present mitigate against private sector

investment that is not in some manner accompanied by Government support. How these conditions will change over the next 5 to 10 years

will depend on the interaction of a complex of

variables. Estimates and opinions of what will

happen range widely; each technology and each

particular subvariety of technology has its proponents and detractors.

Generally speaking, capital costs must be reduced and performance improved if the technologies are to be deployed widely. To some extent,

this can be fostered by research oriented towards

incremental improvements of the commercialscale systems now operating. Also necessary will

be adequate information on the solar resources.

And if the technologies are to be extensively deployed in the 199os, perhaps the most pressing

divlduals. See for examp’-: 1 ) L.K. Ives and W.W, Willcox, “Economic Requirements for Central Receiver Commercial ization, ”

Proceedings of STTF (Solar Thermal Test Facility) Testing for Long

Term Systems–Performance Workshop, Jan. 7-9, 1984 (Albuquerque, NM: National Technical Information Service, july 1984), PC

Al 5/MF AO1, pp 61-67; 2) Edgar A. DeMeo, “Molten Salt SolarThermal Systems, ” EPR/ )ourna/, vol. 8, No. 12, December 1983,

pp. 38-41; 3) McDonnell Douglas, “Response by McDonnell

Douglas to General Workshop Discussion Questions, ” submitted

to OTA in response to written questions submitted in connection

with OTA Workshop on Solar Thermal Electric Technologies, 1984;

4) Arizona Public Service Co., et al., So/ar Therma/ Centra/ Receiver

Development P/an for Me/ten Sa/t Technology, mimeo, prepared

for U.S. Department of Energy, jan, 31, 1984; and 5) C.j. Weinberg (Pacific Gas & Electric), letter to Howard S. Coleman (Department of Energy), dated Dec. 21, 1984.
262 ● New Electric Power Technologies: Problems and Prospects for the 1990s

need is to reduce uncertainty and to increase demand to the point where economies of scale can

drive costs down.

The extent to which uncertainty will be reduced by the 1990s depends heavily on the

amount of additional capacity instaIled for each

of the systems during the next 5 years. Should

the tax credits be extended, additional trough and

dish systems probably will be installed, serving

to reduce considerably the importance of uncertainty as an impediment to commercial deployment. The mounted-engine dishes in particular—

where uncertainty now is especially great—could

benefit from greater deployment of commercialscale units, and improved commercial prospects

might result. Under such conditions, the mountedengine parabolic dishes could eliminate the current lead enjoyed by parabolic troughs among

the solar thermal technologies. If the engines perform well, the parabolic dish technology could

provide serious competition to the troughs and

to other generating alternatives in the 1990s.

Without either sizable tax credits or greater direct Government support, however, fewer and

perhaps no additional trough or parabolic dish

units may be installed. Indeed, the private enterprises which are presently pursuing the technologies may completely cease activities in support

of the technologies altogether. Our market analysis suggests that only one of the parabolic dish

developers is likely to maintain a significant effort to support the technology if the renewable

energy tax credits cease to be available at the end

of 1985.21

Wind Turbines

History and Description of the Industry

Wind turbines first were used to generate electricity in Denmark nearly 100 years ago. Later,

in the early 1930s through the late 1950s the technology was deployed in the United States, predominantly in rural areas. As transmission lines

21 strategies unlimited, Arra/ysis of Equipment Manufacturers and

Vendors in the Electric Power Industry for the 1990s. Wind Turbines, Solar Thermal Electric, Photovoitaics, op. cit., 1984; Peter

B. Bos and Jerome M. Weingart, /mpact of Tax /ncentives on the

Commercialization of Solar Thermal Electric Technologies, op. cit.,

August 1983.

were extended to these areas and cheap electricity provided, the wind turbines ceased to be an

attractive option. By the 1960s and early 1970s,

technical progress slowed to a crawl and deployment continued at only a very low level.

Interest in wind turbines resurfaced in the

1970s when energy costs skyrocketed, fuel supplies became uncertain, and environmental concerns grew. The resurgence was strongest in the

United States and in Europe, especially in Denmark. During the early 1970s, major government

programs both in the United States and abroad

emphasized the development of large, multimegawatt wind turbines, though important work

applicable to smaller machines also was supported. Outside of government-subsidized programs, smaller units with ratings less than 100

kWe were favored, as these offered the most immediate commercial applications.

By mid-May 1985, wind turbines–mostly small

units—with a total rated capacity of over 650

MWe were installed nationwide. Most–about

550 MWe—were in California’s wind-farms,

which became the focus of the worldwide wind

turbine industry. Several basic interrelated elements appear to have shaped development during this period.

First, developers of the large multi-megawatt

wind turbines encountered serious technical

difficulties. In the United States, the Federal Government cut back its direct support of wind research and development (see table 9-2). The industry, heavily dependent on Federal support,

shifted away from the large machines when the

Federal aid receded and concentrated on small

wind turbines which afforded a more immediate

commercial promise.

Second, a combination of favorable circumstances in California prompted rapid growth in

the deployment of grid-connected wind turbines.

Among these circumstances were the adoption

of PURPA Section 210, high electric-utility

avoided costs, availability of an excellent and

accessible wind resource which had been carefully assessed, favorable Federal and State tax

treatment; and favorable treatment by the California Energy Commission and public Utility

Commission.
Ch. 9—The Commercial Transition for Developing Electric Technologies • 263

Finally, technical development of smaller sized

wind turbines proceeded very rapidly as costs declined and performance improved. The extremely

favorable conditions in California encouraged the

initial commercial deployment of equipment

which was new and not fully proven. The processes of research, development, and commercialization came together into one step as California’s wind farms became de facto open-air

laboratories. While this greatly accelerated the

development of the technology, it also led to

inevitable mechanical faiIures and inadequacies

associated with an emerging and immature technology.

In 1984, there were about 100 wind turbine

manufacturers worldwide. They were mostly

small, independent businesses dedicated exclusively to the wind industry, and owned and

operated by risk-taking entrepreneurrs without extensive business experience, 22 Most of the companies had limited financial reserves, and depended on company growth to cover their past

debts and provide working capital. Approximately 70 of the companies in 1984 provided

mostly turbines of sizes less than 50 kWe. About

30 companies were active in wind farms and of

these, six accounted for 95 percent of the world

wind-turbine sales in 1983.23

I n other words, the world wind-turbine industry presently consists of many small firms, but it

is dominated by a few manufacturers who possess an advantageous combination of adequate

equipment and financial resources. However,

even these six companies are relatively small. For

example, Energy Sciences, Inc., the third ranking U.S. supplier in 1983, sold $17.5 million

worth of wind equipment in 1983. By comparison, the smallest company on the Fortune 1000

list had sales of over $122 million in 1983.24

Companies based in the United States dominated the world market for wind power equipment in 1983, accounting for an estimated 72 percent of world sales. But this position is being

eroded by foreign competition. By 1984, U.S.

manufacturers accounted for 69 percent of world

sales of approximately $405 million. The decline

of the U.S. position in world markets has been

paralleled by its decline in the domestic market

as well. The erosion of the U.S. industry’s market share is expected to continue. European vendors may achieve parity with U.S. producers in

U.S. markets by the end of 1986 and surpass them

by 1988. This appears possible due to a superior

combination of equipment quality and cost, the

latter being greatly affected by the strength of the

U.S. dollar. I n addition, European vendors have

been very aggressive in exploiting foreign markets. 25

During the 1980s, the industry has been highly

competitive; many companies have entered the

business and many others have withdrawn. Currently, the number of firms is declining.

The great bulk of wind turbine capacity deployed in the United States is financed by investors other than the electric utilities and orchestrated by wind farm developers. While some

developers are independent of the turbine manufacturers (the open “merchant” market), a large

and growing share of the wind farms is directly

affiliated with the turbine manufacturers themselves.2b This “captive” wind farm market allows

vendors to: 1 ) capture the developer’s profits,

which generally exceed their own; 2) regulate turbine demand over the span of each year so that

demand is not overly concentrated at year-end;

and 3) gain better control over adverse publicity

relating to turbine performance.

To date, capital for wind farm investment has

rarely come from public stock offerings or from

venture capitalists. Most investment has been in

the form of limited partnerships, either sold

directly by the developer or through brokerage

firms. Since 1982, major brokerage houses have

been involved and their importance in the industry has increased. Some developers, however,

Zlseefor example comments of 6ror Iiansonin Alternativ e

Sources of Energy, vol. 50, July/August 1981, p. 5.

IJStrategies Un]imited, Analysis d[quipment Manufacturers and

Vendori In the Electric Power Industry for the 1990s. Wind Turbines, Solar Therma/ E/ectric, Photovo/taics, op. cit., 1984.

241 bid.

l*lbid.

ZbTh is Veflical Integration typically takes several forms: the manufacturer may itself obtain the land, utility contracts and capital required for the wind farm; or 2) it may simply acquire a developer,

or form exclusive relationships with a developer or an equipment

distributor.
264 ● New Electric Power Technologies: Problems and Prospects for the 1990s

use so-called “chattel” sales to avoid dependence

on brokerage houses. Each of these financing arrangements has its advantages and problems, and

affects wind turbine deployment in a different

way. The manner in which financing is obtained

therefore will continue to be of critical importance to the industry. (See chapter 8 for more details on financing arrangements. )

Industry Outlook and Major Impediments

As mentioned earlier, wind turbines during the

first half of this decade have benefitted from

favorable tax treatment; chapter 8 discusses the

effects of specific Federal tax provisions on wind

turbine economics and highlights their importance. Potential tax changes, therefore, are of

concern to the industry. The tax change of most

immediate concern is the scheduled expiration

of the Federal renewable energy tax credit (RTC)

at the end of 1985.

Expiration of the RTC is likely to result in a major shake-out in the U.S. wind industry. Barring

unexpected increase in electric utility involvement, demand for wind turbines probably will

drop sharply, and many small firms are likely to

collapse. Only larger firms with sufficient capital

to further develop medium-sized turbines and

weather a period of intense competition and relatively low sales will survive. Though the size of

the industry and the variety of firms could be

greatly diminished, and though technical progress

is likely to be slowed considerably, many industry observers believe that the industry could survive, and perhaps even benefit, from a termination or phase-down of the RTC.

Though the RTC has stimulated technical development and commercial deployment, which

otherwise could not have occurred in the early

1980s, they also have been abused by some investors as short-term tax shelters.27 Such abuse

has prompted Federal tax fraud investigations and

hurt the reputation of the industry.28

Zzsee statement of Bill Adams, San Gorgonio Farms, as quoted

in “San Gorgonio Farms (SGF) Will Install 53 Carter Wind System

Model 225’s, ” Wind /ndustry News Digest, vol. 4, No. 4, Feb. 15,

1984, p. 3.

28Largely in response to tax-shelter abuses, the American Wind

Energy Association established an ethics committee to monitor the

industry and discourage behavior which harms the long-term interests of the business. See: Burt Solomon, “Windmillers Clean Up

Act, ” Energy Dai/y, vol. 13, No. 12, Jan. 17, 1985, pp. 1 and 3.

Alternatives to a simple extension of the current Federal credits have been suggested. One

would gradually phase-out the tax credits over

several years; this might help the industry complete the commercial transition from small taxsubsidized turbines to unsubsidized and economic medium-sized units. Another would establish a system of credits based on energy production rather than capital investment; 29 these are

discussed in greater detail in chapter 10.

Aside from the immediate issue of the RTC,

other possible circumstances could also slow the

development and deployment of competitive,

medium-sized turbines in the 1990s. Problems relating to the following could arise.

Equipment Quality.—Technical improvements

are necessary if wind turbines are to compete

without subsidy. While improvements are being

made, cessation of the RTC at the end of 1985

and of the California tax credit several years later

is likely to severely reduce the capital available

to finance development and production of new

wind turbine designs. Moreover, the likelihood

of smaller markets will reduce the opportunity

to actually deploy the units and thereby generate the data necessary for further improvement.

The difficulty in financing the redesign and manufacture of new equipment probably will be particularly severe among the small wind turbine

manufacturers.

Wind Resource Information.–Detailed wind

resource information is crucial to the growth of

wind-farms around the country. While current

meteorological data allows identification of potential sites,30 detailed site-specific information

must still be gathered for at least 1 to 3 years to

adequately assess the potential of specific sites.

While site-specific information is being generated

at a rapid pace, the lack of such information still

could hinder deployment in the 1990s.3’ The

z~strategies unlimited, Ana/ysis of Equipment Manufacturers and

Vendors in the Electric Power Industry for the 1990s. Wind Turbines, Solar Thermal Electric, Photovohaics, op. cit., 1984.

~OBattelle, pacific Northwest Laboratories, Application ~Xarqdes

for Wind Turbine Siting Guidelines (Palo Alto, CA: Electric Power

Research Institute, March 1983), AP-2906.

31 See: 1 ) j BF Scientific Corp., Ear/y Uti/ity Experience With Wind

Power Generation: Goodnoe Hi//s Project (Palo Alto, CA: Electric

Power Research Institute, January 1984), vol. 3, EPRI AP-3233; 2)

Dean W. Boyd, et al., Commercialization Analysis ot_Large Wind

Energy Conversion Systems (Palo Alto, CA: Decision Focus Inc.,

June 1980).
Ch. 9—The Commercial Transition for Developing Electric Technologies ● 265

need for wind assessment extends to prospective

export markets as well, where data are especially

inadequate.32

Land Access and Cost of Access.—Access to

wind-swept land has in some instances been a

problem. 33 Furthermore, costs of access have increased substantially. Development of the wind

resource presupposes access at an acceptable

cost. These potential problems may slow deployment in the next 15 years.

Cost and Performance Data.–Current cost

and performance data are very important to prospective wind turbine investors as well as to utilities, public utility commissions, and the turbine

manufacturers themselves. At present such data

are difficult to obtain, precluding accurate prediction of wind turbine cost and performance prior

to deployment. Efforts are being made in some

States to increase the information available on

current machines. 34 Where performance data are

available, use is often limited by inconsistencies

and other problems.

Standard Definitions and Performance Leveis.–

The effective use of performance data often is

limited by inconsistencies; standard definitions

might assist investors and others in comparing wind

turbines with each other as well as with competing generating technologies. The value of such

standards is enhanced when they are provided by

an independent and trustworthy source. Of even

greater value might be the establishment of minimum standard performance levels which turbine

performance must meet in order to receive certification. Many industry observers believe standards

should be applied to the industry, though there is

disagreement over who should impose the standards and what the standards should be.

—— . . .—

3zs ,.K G rlfflth, et al., Fore/gn App/icatlons and Export POtentia/

for Wind Energy Systems (Golden, CO: Solar Energy Research institute, 1982J, subcontractor report, SE R1/STR-21 1-1827.

IIR. ), Noun, et al., ut;l;ty Siting of WECS: A Preliminary LegallRegu/atory Assessment (Golden, CO: Solar Energy Research Institute,

May 1981 ).

3qThe State of California, for example, requires that production

and other data (Including cost data) be provided on a quarterly basis

by all wind project operators in the State, The American Wind

Energy Association is developing a voluntary national reporting program similar to California’s mandatory program,

Warranties.–Investors, in view of the past poor

performance of some wind turbines, are reluctant

to invest in hardware unless it is accompanied by

a strong warranty. This essentially shifts part of the

risk of owning and operating a wind turbine back

to the vendor. Because current technology is immature, however, such warranties are in themselves

risky and could lead to high costs for vendors. indeed, some manufacturers have been driven out

of business because of these costs.35 While vendors

can purchase “warranty insurance, ” this insurance

has become progressively expensive as insurers

have become more cautious with wind turbines.3b

Should the industry be short of capital during the

next 15 years, the warranty issue could constitute

an important impediment to industry expansion.

Government Permits and Licenses.–Wind farm

promoters are expected to encounter problems as

they seek approval for their projects from Federal,

State, and local regulatory agencies. The most serious problems are likely to be at the local level,

where wind farms have already encountered public opposition because of visual and environmental

impactso

37

Transmission Facilities.—Without access to

transmission facilities, even the most attractive site

cannot be 1 inked to the grid. Major transmission

facilities often require lead-times of 3 to 10 years.

Clearly, if candidate wind sites do not already

have easy access to transmission lines, serious

delays may be encountered. Widespread wind

turbine deployment in the 1990s will either be

limited to areas which already have access to

transmission lines, or if currently remote areas are

to be developed, efforts to extend transmission

‘35 For example, see: 1 ) “How Wind Power Cracks Up, ” New

Scientist, Apr. 12, p. 31; 2) Arthur D. Little, Inc., Wind Turbine Performance Assessment (Palo Alto, CA: Electric Power Research institute, 1984), Technology Status Report No. 7, EPRI AP-3447; 3)

Larry Stoiaken, “The Small Wind Energy Conversion System Market: Will 1984 Be ‘The Year of the SWECS’?” Alternative Sources

of Energy, vol. 63, September/October 1983, pp. 10-23; and 4) Strategies Unlimited, Ana/ysis of Equipment Manufacturers and Vendors in the Electric Power Industry for the 1990s. Wind Turbines,

Solar Thermal Electric, Photovoltaics, op. cit., 1984.

3GRonald L. Drew, “Wind Energy: The Present Status of Relevant

Insurances, ” Alternative Sources of Energy, vol. 72, March/April

1985, pp. 56-59.

~TSee Chs, 4 and 7 for further details.
266 . New Electric Power Technologies: Problems and Prospects for the 1990s

facilities to those areas must be initiated within

the next decade.38

Utility Energy and Capacity Credits, and interconnection Requirements.– Low energy

credits, low capacity payments,39 and stringent

interconnection requirements discourage deployment by nonutilities. Even where the possibility

exists that credits could drop during the lifetime

of a project, investment is discouraged. Also, any

difficulties (such as delays) encountered in seeking to obtain favorable credits or interconnection

requirements discourages non utility deployment.

Overseas Markets.–Over the next decade, foreign markets are likely to be important outlets

for wind turbines, especially small machines for

remote applications;40 under some conditions

they could be crucial to the survival of major

manufacturers. Already, exports account for a sizable share of turbine sales by U.S. manufacturers,

and current evidence indicates that many are actively developing overseas markets.41 The promotion by the companies themselves and by others

of overseas sales appears to constitute a major

opportunity to nurture the industry and to indirectly foster further refinement of the technology. Difficulties in exploiting these markets (including problems relating to foreign competition)

therefore could severely damage the industry, reducing its capacity to supply the domestic mar-

— . . . —

lsFOr example, the lack of transmission capacity in California

reportedly prevented development of some prime wind sites.

Source: OTA staff conversation with Mike Batham, California Energy

Commission, November 1984.

JgFor a discussion of capacity credits in the wind industry, see

Fred Sissine, Wind Power and Capacity Credits: Research and implementation Issues Arising From Aggregation With Other Renewable Power Sources and Utility Demand Management Measures

(Washington, DC: Congressional Research Service, 1984).

qosee: I ) Birger T. Madsen, “Danish Windmills: A View From the

Inside, ” Alternative Sources of Energy, vol. 69, September/October

1984, pp. 24-26; 2) S.K. Griffith, et al., Foreign Applications and

Export Potentia/ for Wind Energy Systems (Golden, CO: Solar Energy

Research Institute, 1982), subcontractor report, SER1/STR-21 1-1827;

3) Les Garden, “The Overseas Market: Does the Post-Tax-Credit

Transition Start Now?” Alternative Sources of Energy, vol. 69, September/October 1984, pp. 28-30; 4) Larry Stoiaken, “International

Marketing: U.S. Wind Firms Make Their Move,” Alternative Sources

of Energy, vol. 72, March/April 1985, pp. 21-23.

41 See, for example: 1 ) “FloWind Signs ‘Document of Mutual interest’ With Chinese for 40 Darrieus Turbines, ” 50/ar Energy /nte/-

/igence Report, Jan. 21, 1985, p. 24; 2) Larry Stoiaken, “The Small

Wind Energy Conversion System Market: Will 1984 Be ‘The Year

of the SWECS’ ?“ op. cit., 1983; 3) Larry Stoiaken, “Going international, ” Alternative Sources of Energy, vol. 63, September/October

1983, pp. 24-25.

kets with turbines of acceptable quality and in

the quantities demanded for the 1990s.

Geothermal Power

History and Description of the Industry

In 1904, Italy became the first country in the

world to use geothermal energy to produce electricity. In 1923 geothermal resources were tapped

in the united States to produce electric power.

At that time, a small, remote 250 kWe unit began generating power for a California hotel at The

Geysers. Over 35 years elapsed, however, before

further capacity was installed in the United States

when, in early 1960, the first grid-connected geothermal unit began to generate power at The

Geysers. During the following 20 years, further

development occurred and by the end of 1983,

1,300 MWe of geothermal capacity were on-line

in the United States—more capacity than in any

other country. Worldwide, about 3,400 MWe

were operating.42

Most U.S. geothermal development, located at

The Geysers in California, employed direct steam

conversion technology. As discussed in chapter

4, however, most U.S. geothermal resources are

of lower quality than those found there and cannot be exploited with the conventional technology used at The Geysers. As development activity progressed in the 1960s, the need for different

technologies for lower quality resources became

evident. Further geothermal development increasingly would require other equipment such

as the developing technologies considered in this

assessment—dual flash and binary systems.

While the need for technological progress was

apparent in the 1960s, it was not until recently

that these new technologies began to be deployed in the United States. Several factors, including problems regarding Federal leasing policies and technological questions, served to

impede the development of the lower quality

geothermal resources. Progress in these matters,

along with the passage of PURPA, favorable Fed42 Ronald DiPippo, “Development of Geothermal Electric Power

Production Overseasr ” Energy Technology Xl, Applications& Economics: Proceedings of the Eleventh Energy Technology Conference, Mar. 79-21, 1984, Richard F. Hill (cd.) (Rockville, MD: Government Institutes, Inc., August 1984), pp. 1219-1227.
Ch. 9—The Commercial Transition for Developing Electric Technologies ● 267

eral and State taxes, and high avoided costs,

brought commitments to the technologies during the first half of the 1980s. By the end of 1985,

a single 47 MWe (net) dual-flash geothermal unit

will be in place. One large (45 MWe, net) binary

plant will have been installed and at least 30

MWe of small binary plants will be operating. Together these will account for about 122 MWe,

or about 7 percent of total U.S. installed geothermal capacity at the end of 1985 (about 1,780

MWe43).

Important to these technological developments

has been the Federal Government’s support of

the industry since the mid-1970s. The first major

Federal assistance came in the form of the Geothermal Loan Guarantee Program. This soon was

coupled to stepped-up support for research and

development (see table 9-2). From 1973 through

1983, approximately $1 billion was spent on geothermal power by the Federal Government, roughly

matching industry’s expenditures. Direct Federal

expenditures in support of the technology, concentrated in DOE and its predecessor agencies,

grew from $3.8 million to $171 million in 1980;

however, as of fiscal year 1985 this had dropped

to $32.1 million. The recent decline in direct Federal expenditures was partially offset by increases

in indirect Federal support of the industry through

various tax incentives, including the Renewable

Energy Tax Credit.

Discovery of geothermal resources has long

been associated with oil exploration and development in this country, When geothermal activity

picked-up in the 1960s, several oil companies entered the geothermal business. Since then, the

oil industry has continued to be deeply involved

with geothermal development, and indeed heavily dominates the industry. At the same time, a

group of smaller, independent enterprises has

sought to develop geothermal power, usually by

pursuing the relatively marginal resources.

Among the businesses in the geothermal industry is a core of about two dozen companies capable of sustaining the full effort required to bring

geothermal projects to fruition. In addition, there

‘

3 Vasel Roberts, “Utility Preface, ” Proceedings: Eighth Annua/

Geotherrna/ Conference and Workshop, Altas Corp. (cd.) (Palo Alto,

CA: Electric Power Research Institute, 1984), EPRI AP-3686, p. v.

are many other companies and organizations,

such as electric utilities, drilling companies, architectural and engineering firms, and the Electric Power Research Institute (EPRI), which support the development and deployment of the

technology. 44

Until the late 1970s, geothermal development

was carried out through cooperative ventures between field developers and electric utilities. The

field developers located the resource and then

worked with the electric utility and architectengineering firms to design and construct a powerplant. The field developer then would tap the

geothermal resource and deliver the hot water

or steam “over the fence” to the electric utility.

Since 1978, though, PURPA, favorable tax treatment, and high avoided costs have stimulated

nonutility investment in power generation projects, and purely nonutility projects have become

prevalent in Oregon, California, and Nevada.

Industry Outlook and Major Impediments

By the year 2000, a total U.S. geothermal capacity from 2,600 to about 6,800 MWe may be

in place. A sizable portion of this could consist

of the developing technologies discussed in chapter 4. Most will be located in California, Hawaii,

Arizona, New Mexico, Nevada, and Utah.qs The

degree to which the potential will be realized depends on a variety of circumstances.

As with the other renewable energy technologies, the status of various State and Federal tax

incentives will strongly influence deployment

levels. As mentioned in chapters 4 and 8, the tax

incentives make geothermal investments much

more attractive and have been especially important in advancing the technologies during the

44Vane E. Suter, “Who Will Develop the Governmental Resources?” Proceedings: Seventh Annual Geothermal Conference

and Workshop, Altas Corp. (cd. ) (Palo Alto, CA: Electric Power Research Institute, 1983), EPRI AP-3271, pp. 7-10 through 7- 13; and

Vasel W. Roberts, “EPRI Geothermal Power Systems Research Program, ” Proceedings: Eighth Annua/ Geotherma/ Conference and

Workshop, Altas Corp. (cd.) (Palo Alto, CA: Electric Power Research

Institute, 1984), EPRI AP-3686, pp. 4-1 through 4-3.

qsvasel Roberts and Paul Kruger, “Utility Industry Estimates of

Geothermal Energy,” Proceedings: Eighth Annual Geothermal Conference and Workshop, Altas Corp. (cd.) (Palo Alto, CA: Electric

Power Research Institute, 1984), EPRI AP-3686, p. 4-27 through 4-31.
268 . New Electric Power Technologies: Problems and Prospects for the 1990s

early 1980s.46 Elimination or reduction in the size

of the tax incentives—or even the possibility of

such changes—is likely to slow deployment.

Important too will be other government activities at the Federal, State, and local levels. The

level of direct support for R&D will continue to

be a key determinant of technical progress in the

industry. Also influential will be the many forms

of reguIatory control government agencies exert

over the activities required to deploy geothermal

technologies. Because of the importance of government, and the number and diversity of relevant agencies, the degree to which their activities are coordinated will be equally important .4’

Other factors that may impede the deployment

of geothermal technologies in the 1990s include:

Equipment Cost and Performance.–As discussed in chapter 4, dual-flash and binary-cycle

technologies are relatively immature. Cost reductions and performance improvements in some

cases may be necessary, not only with the equipment used in actually producing the electric

power, but in some cases also in the technology

required to deliver brine to the surface. The rate

at which progress occurs depends strongly on the

amount of capital devoted to R&D.

Three factors may retard R&D investment. First,

the members of the geothermal industry most capable of shouldering R&D investments–those affiliated with the petroleum companies–may not

invest the necessary capital,48 partly because of

the current soft petroleum market, Second, activity in the geothermal industry is affected heavily

by nonutilities, whose investment levels are in-

—. ..—

dGSubcommittee on Energy and Mineral Resources, Senate Committee on Energy and Natural Resources, U.S. Congress, Geothermal Energy Development in Nevada’s Great Basin: Hearing to Examine the Current Status and Future Needs of Nevada Geothermal

Energy /ndustry (Washington, DC: U.S. Government Printing Office, 1984) Sparks, Nevada, April 17, 1984, S.Hrg. 98-801,

dTAlex Sifford, Background Geotherma/ /formation for the 1985

Energy P/an (Salem, OR: Oregon Department of Energy, February

1985), mimeo, and James Ward, “Geothermal Electricity in California, ” Transitions to Alternative Energy Systems–Entrepreneurs,

New Technologies, and Social Change, Thomas Baumgartner and

Tom R. Burns (eds.) (Boulder, CO: Westview Press, 1984), pp.

167-186.

‘See, for example, Chris B. Amundsen, et al., A Summary of U.S.

Department of Energy Geothermal Research and Development Program Accomplishments, Industry Response, and Projected Impact

on Resource Development (Philadelphia, PA: Tech necon Analytic

Research, Inc., 1983).

.

fluenced strongly by State and Federal tax policies. possible changes in the policies, the most

immediate of which is the expiration of the Federal renewable energy tax credit, will greatly

diminish geothermal investment. Third, the Federal Government, which historically has been the

major source of R&D funds, has sharply cut its

support (see table 9-2).

Technology Demonstration.–Beyond the geothermal demonstration plants already being built

or operating, very little additional capacity is

planned with the developing geothermal technologies. Should few additional plants be deployed in the next 5 to 10 years, the lack of extensive commercial experience is likely to impede

rapid expansion of capacity in the 1990s, since

the associated risks may be perceived as too high.

Difficulties in gaining access to adequate information on cost and performance could also slow

timely deployment of developing geothermal

technologies in the 1990s.49

Geothermal Exploration, Resource Identification and Assessment.–Once a geothermal resource is discovered, more precise information

on the quality of the resource is needed in order

to assess the economics of site development and

to optimize plant design. This requires that resource qualities be measured further and the information analyzed. The lack of site measurements and adequate analytical capabilities are

considered major impediments to the development of geothermal power.

Federal Leasing Requirements.–A considerable portion of the geothermal resource in the

United States lies under Federal lands. The leasing of this land, administered by the Bureau of

Land Management, is characterized by two requirements which may impede deployment of

geothermal technologies. First, no single leaseholder may hold leases covering more than

20,480 acres in any specific State. SO This report4W .s. Department of Energy, Geotherma/ Progress Monitor

(Washington, DC: DOE, 1983), Report No. 8; and testimony of Jon

Wellinghoff (Consumer Advocate, State of Nevada), p. 5 in Subcommittee on Energy and Mineral Resources, Geofherma/ Energy

Development in Nevada Great Basin: Hearing to Examine the Current Status and Future Needs of Nevada’s Geothermal Energy industry, op. cit., 1984.

SOThe 197o Geothermal Steam Act, however, does allow the Secretary of Interior to raise the statewide acreage limitation after Dec.

24, 1985. Indeed, in April 1985, the Department of the Interior proposed that the limitation be raised to 51,200 acres.
Ch. 9—The Commercial Transition for Developing Electric Technologies ● 269

edly has slowed the rate at which resources can

be assessed and at which development can occur. Second, primary lease terms are for 10 years;

a leaseholder must develop the land within that

period or lose the lease. This may inhibit commitments to develop particular geothermal resources. 5

1

Utility Energy and Capacity Credits, and interconnection Requirements.—As with the other

technologies discussed so far in this chapter low

energy credits, low capacity payments, and stringent interconnection requirements discourage

deployment by nonutilities. Even where the possibility exists that credits cou Id drop during the

lifetime of a project, investment is discouraged.

Also, any difficulties (such as delays) encountered

in seeking to obtain favorable credits or interconnection requirements discourages non utility deployment. 52

Transmission Capacity .—Like wind resources,

geothermal resources often are located in areas

which are not readily accessible or located near

transmission facilities. Moreover, in some cases,

the geothermal resources are far from the markets offering the highest avoided costs. The lack

of adequate transmission facilities connecting the

resources with markets and/or institutional mechanisms for wheeling power to these markets is

considered a major impediment to the further de-

—.—

s]See: 1) J. Laszlo, “Findings of U.S. Senate Hearings on Geothermal Development in Nevada, ” Proceedings: Eighth Annual Geotherrna/ Conference and Workshop, Altas Corp. (cd. ) (Palo Alto,

CA: Electric Power Research Institute, 1984), EPRI AP-3686, p. 6-

16 through 6-20; 2) Vane E, Suter, “Who Will Develop the Governmental Resources?” Proceedings: Seventh Annual Geothermal

Conference and Workshop, op. cit., 1983; 3) Subcommittee on

Energy and Mineral Resources, Geothermal Energy Development

in Nevada Great Basin: Hearing to Examine the Current Status

and Future Needs of Nevada Geothermal Energy Industry, op.

cit., 1984; 4) Subcommittee on Energy and Mineral Resources, Senate Committee on Energy and Natural Resources, U.S. Congress,

Geotherma/ Steam Act Amendments of 7983 (Washington, DC: U.S.

Government Printing Office, 1983), Hearing, May 2, 1983, S.Hrg.

98-392; and 5) James Ward, “Geothermal Electricity in California, ”

Transitions to Alternative Energy Systems–Entrepreneurs, New

Technologies, and Social Change, op. cit., 1984).

S’See j. Laszlo, “Findings of U.S. Senate Hearings on Geothermal Development in Nevada, ” op. cit., 1984, and Subcommittee

on Energy and Mineral Resources, Geothermal Energy Development in Nevada’s Great Basin: Hearing to Examine the Current Status and Future Needs of Nevada’s Geothermal Energy Industry, op.

cit., 1984 .

ployment of geothermal technologies of any kind,

especially in Oregon and Nevada. 53

Leasing, Permitting, and Licensing Delays.–

Where geothermal development is planned on

Federal property, considerable delays may be occasioned in securing the necessary lease. Further

delays also may result as the requisite licenses

and permits are obtained from various public

agencies. 54 Problems regarding water consumption and subsidence in particular may occasion

delays, particularly in agricultural areas.55 Together, these time-consuming steps may limit the

amount of capacity which could be deployed in

the 1990s.

Fuel Cells

History and Description of the Industry

The current major efforts to develop the fuel

cell for grid-connected applications in the United

States are split between natural gas and electric

utilities. The electric utilities are pursuing the use

of fuel cells in central station applications, while

gas utilities have concentrated on relatively small,

“onsite” fuel cells which would increase markets

for natural gas.

As with photovoltaics, the initial commercial

impetus behind fuel cell development in the

United States was the space program in the 1950s

and 1960s. Efforts to develop fuel cells for ter-

.———

53 See:, 1 ) J. Laszlo, “Findings of U.S. Senate Hearings on Geothermal Development in Nevada, ” op. cit., 1984; 2) C.j. Weinberg,

“Role of Utilities, Resource Companies, and Government: Discussion Group Report, ” Proceedings: Seventh Annual Geothermal

Conference and Workshop, Altas Corp. (cd. ) (Palo Alto, CA: Electric Power Research Institute, 1983), EPRI AP-3271, pp. 7-26 through

7-27; and 3) Subcommittee on Energy and Mineral Resources, Geothermal Energy Development in Ne~ada’s Great Basin: Hearing to

Examine the Current Status and future Needs of Nevada Geotherma/ Energy /ndustry, op. cit., 1984.

Sdlncluded in the information required for facility licensing and

permitting is baseline data on the environmental conditions at a

site. For more information, see Alex Sifford, Background Geotherma/ /formation for the 1985 Energy Plan, op. cit., 1985.

JSFor a discussion of the water issue in the Imperial Valley, Where

considerable deployment of dual-flash and binary systems may occur in the 1990s, and where agriculture is very important, see: Department of public Works, Imperial County, Water for Geothermal Development in Imperial County: A Summarizing Report (El

Centro, CA: Imperial County, June 1984), special report, DOE Cooperative Agreement DE-FC03-79ET271 96.
270 ● New Electric Power Technologies: Problems and Prospects for the 1990s

restrial applications multiplied during the mid1960s, but by the end of the decade most had

ceased with one notable exception. In 1967 a

group of gas utilities formed an organizations to

develop equipment that somehow could counter

the electric power industry’s capture of the gas

industry’s markets. This and subsequent programs

culminated in the current effort in which the Gas

Research Institute (GRI), funded by the gas industry, and DOE are deploying and testing fortysix 40 kwe fuel cell cogeneration units. Several

units of this size also were installed in Japan. Concurrently, GRI and DOE are funding a coordinated multi-year research project expected to

yield an “early entry” onsite fuel cell system with

an expected output of about 200 to 400 kWe.

Meanwhile, since 1971, fuel cell manufacturers, electric utilities, 57 the Electric Power Research

Institute, the Federal Government and others

have sought to develop and deploy multi-megawatt fuel cell power facilities. By 1978, a 4,5 MWe

project was initiated in New York City. The New

York unit suffered from delays in gaining local

regulatory approval. These delays exceeded the

storage life of the power section so that the unit

could not be operated without refurbishment. As

a result, the project was abandoned in 1984.

Another similar, but improved unit was installed

in Japan. That unit, made by the same manufacturer which produced the New York installation,

has operated very successfully since April 1983.

Currently, plans are being laid both in the United

States and in Japan to first develop and deploy

commercial demonstration units, and then to initiate commercial production of fuel cells late in

the 1980s or early 1990s.

In the recent years a number of cooperative

agreements between Japanese and U.S. firms

have evolved, perhaps the most important of

which is the joint venture between United Technologies and Toshiba. The two companies have

JbThe Team to AcfVar-rCe Research on Gas Energy Transformation

(TARGET).

JTElectric Utility effotis in support of the fuel cell have been mediated in part through the Electric Utility Fuel Cell Users Group, an

association established about 5 years ago. The group, now consisting of over 60 members, works closely with EPRI, fuel cell vendors and others to promote the use of fuel cells among electric utilities. For more information, see “Fuel Cell Users Group, ” EPR/

)ourna/, vol. 10, No. 1, january/February 1985, pp. 62-63.

agreed to cooperative electric utility commercial

powerplant design and development activity. This

alliance may lead to an agreement to construct

a fuel cell production faciIity in the United States

sometime in the near future. 58 The substantial

capital and technological capabilities of these corporations enhance the prospects that the hurdles

faced in early commercialization may be successfully and readily overcome.

Government involvement on both sides of the

Pacific has been extensive. In the United States,

Federal funding has been divided between military/space applications and support of civilian

commercial uses. The support for civilian applications has emphasized the use of fuel cells in

transportation and in electric power generation;

this support has emanated from DOE and its

predecessor agencies. The DOE program of greatest importance to the near-term commercial prospects of the fuel cell is the Phosphoric Acid Fuel

Cell Program. The National Aeronautics and

Space Administration (NASA) -Lewis Research

Center has been designated by DOE as the lead

center for the program.

DOE’s funding for fuel cells is summarized in

table 9-2. DOE’s support peaked in 1984, when

$42.3 million were spent on the technology. A

very substantial portion of the funds has been

dedicated to the phosphoric acid technology–

which is the most promising technology for initial commercial penetration. While DOE spending on fuel cells dropped only slightly in fiscal year

1985, a substantial reduction to $9.3 million has

been proposed for 1986. Under the latter proposal, support for the phosphoric acid technology is eliminated altogether. 59

Although some fuel cell research and development took place in Japan during the 1960s and

1970s, the current Japanese fuel cell program did

——.— ~13p. J, Farris, Business Planning Staff, International Fuel Cells (u npublished memorandum for OTA staff), June 18, 1985. For more

information on these U.S.-Japanese efforts, see: Peter H u nt Associates, Analysis of Equipment Manufacturers and Vendors in the

Electric Power Industry for the 1990s as Related to Fuel Cells (Alexandria, VA: Peter Hunt Associates, 1984), OTA contractor report.

Jgsee Herbert Lundblad and Ronald R. Cavagrotti, Assessment

of the Environmental Aspects of DOE Phosphoric Acid Fuel-Cell

Program (Cleveland, OH: Lewis Research Center, 1983),

DOEINASA–2703-3, pp. 7-20; and Fred Sissine, Fuel Cells for Electric Power Production: Future Potential, Federal Role and Policy

Options (Washington, DC: Congressional Research Service, 1985).
Ch. 9—The Commercial Transition for Developing Electric Technologies • 271

not materialize until 1981. At that time, under the

aegis of the Ministry of International Trade and

Industry (MITI), the agency’s “Moonlight Project”

initiated a coordinated program directed towards

the development of fuel cell technologies for various applications. Al I of the Japanese equipment

manufacturers are working u rider this program,

as are several Japanese utilities.

While the Japanese have in the past lagged behind the U.S. program, it appears that the current Japanese program has narrowed the gap.

This results in part from the attentive observation

of and participation i n U,S. efforts. The Japanese

have learned from U.S. successes and mistakes,

while providing their own refinements and modifications.

Industry Outlook and Major Impediments

The fuel cell industries in both the United States

and Japan are positioning themselves for substantial commercial deployment of fuel cells in the

1990s. At the cost and performance levels which

the fuel cells may achieve, extensive markets for

both central station and dispersed applications

could develop.

Deployment in Japan, fostered by the government (MITI), could be quite rapid. Particularly important in this regard is the close working relationship the Japanese fuel cell developers have

with the country’s electric power companies. This

will ease the difficulties the manufacturers might

encounter in the early stages of commercial transition. Over the next 15 years the well-coordinated

Japanese effort probably will place that country’s

fuel cell manufacturers in a position comparable

or perhaps superior to their U.S. counterparts barring significant increases in this country’s efforts.60

In Japan, fuel cells using primarily imported natural gas are expected to provide a few percentage points of total generating capacity by 1995,

and could provide 7 to 8 percent of generating

capacity at the beginning of the 21 st century. 61

‘“Ernest Raia, “Fuel Cells spark Utilities’ Interest, ” ll;gh Technology, vol. 4, No. 12, December 1984, pp. 52-57.

G! N, Floriuchi et al., “Applications of Fuel Cell Power Plants in

Japanese Utillty Use, ” 1983 National Fuel Cell Seminar: Program

and Abstracts (Washington, DC: Courtesy Associates, Inc., 1984),

Orlando, FL, Nov. 13-16, 1983, pp. 173-176.

The rate at which fuel cells are deployed in the

United States probably will be slow at first, until

confidence among potential investors is built up.

The length of this transitional period is a matter

of speculation. It is likely that the first commercial units will not be erected until investors are

convinced these early commercial systems will

operate well, Since both the small (200 to 400

kWe) and large (multi-megawatt) demonstration

units will not be installed until the latter part of

the 1980s, operating experience sufficient to

justify initial commercial orders probably will not

develop until the beginning of the next decade.

It is likely that the proposed termination of Federal funding of phosphoric acid fuel cell development will slow this process and perhaps weaken

the industry’s competitive status with the Japanese; but it is not clear how serious the effect will

b ee

6 2

The potential market in the United States is very

large. An EPRI study of the potential utility market suggests that fuel cells could provide as much

as 65,000 MWe of generating capacity by 2005.63

At the same time, circumstances favor non utility

development too. Substantial advantages are

associated with dispersed cogeneration applications under nonutility ownership. Investors, led

by the gas utilities and perhaps the fuel cell manufacturers themselves, could stimulate rapid

growth in nonutility applications in the 1990s. 64

By the mid-l990s, total experience around the

country and in Japan could be sufficient to trigger rapid growth in the technology in the late

1990s. With very favorable conditions, this

growth could occur even sooner. Various impedi-

—

GzROhert L. civlak, et al., /mpacts o(’ Proposed Budget c’utS in

Selected Energy Research and Development Programs (Washington, DC: Congressional Research Service, 1985).

GjElectric power Research Institute (E PRI), Application of Fue/ Cc//s

on Utility Systems: Study Resu/ts (Palo Alto, CA: EPRI, 1983), vol.

1, EPRI EM-3205.

Gqpeter Hunt Associates, Ana/ysis of Equipment Manufacturers

and Vendors in the Electric Power Industry for the 1990s as Re-

/ated to Fue/ Cc//s, op. cit., 1984.; Peter B. Bos and ]erome M. Weingart, “integrated Commercialization Analysis for New Power Generation Technologies, ” Energy Technology X/, Applications and

Economics: Proceedings of the E/eventh Energy Technology Conference, Mar. 19-21, 1984, Richard F. Hill (cd.) (Rockville, MD: Government Institutes, Inc., August 1984), pp 188-205; and “Industrial,

Commercial Sites Eye Fuel Cells, ” Coa/ Technology Report, Jan.

23, 1984, p. 2.
272 . New Electric Power Technologies: Problems and Prospects for the 1990s

ments, however, could delay extensive commercial deployment until after the close of the century. These impediments are listed below.

Equipment Cost and Performance. -As was

discussed in chapter 4, current evidence suggests

that it is possible to mass produce fuel cells, to

sell them at acceptable prices, and to operate

them without excessive problems. However, this

is by no means certain. Demonstration plants are

necessary to reduce the uncertainty to a level

more acceptable to investors. Further research

and development, aimed at incremental improvements in the equipment, would increase the possibility that cost and performance will fall within

the necessary ranges in the 1990s.

Perhaps the most important impediment facing the fuel cell is the lack of an initial market

sufficient to justify mass-production. Without a

sizable initial market, only small numbers of relatively expensive fuel cells can be manufactured.

These must be sold at high prices–thereby inhibiting demand—or the manufacturer must, in the

short term, operate at a loss. The time it takes

to overcome this problem will, perhaps more

than any other factor, determine the rate of commercial application of fuel cells in the 1990s.

Technology Demonstration.–The successful

demonstration of both small and large fuel cells

will be of critical importance to stimulating investment in the technology. Demonstration units

will be needed to encourage the initial round of

orders,

Utility Energy and Capacity Credits, and interconnection Requirements.–As mentioned

above, a major market for fuel cells lies outside

the electric utilities. Like other grid-connected,

nonutility applications initiated under PURPA,

low energy credits, low capacity payments, and

stringent interconnection requirements discourage deployment by nonutilities. Even where the

possibilityty exists that credits could drop during

the lifetime of a project, investment is discouraged. Also, any difficulties (such as delays) encountered in seeking to obtain favorable credits

or interconnection requirements discourages

nonutility deployment.

Licensing and Permitting De[ays.–ln the long

term, licensing and permitting delays are likely

to be minimized by virtue of the technology’s

relatively low environmental impacts. However,

other circumstances might lengthen delays. The

technology will in many instances be installed in

areas where powerplants have not been traditionally sited and in highly populated areas where

safety considerations are likely to be heavily emphasized. Moreover, the technology is new and

regulatory officials are not well acquainted with

it. The 4.5 MWe facility which was installed in

New York was the subject of many unexpected

delays; similar problems could develop with future plants.

Integrated Gasification/Combined=

Cycle Plants

History and Description of the Industry

The integrated gasification/combined-cycle

plant (IGCC) is a relatively new combination of

components—gasif iers, gas turbines, and steam

turbines—which themselves have been around

in some form for a long time. Steam turbines have

been used to generate electrical power since

1930 in the United States, and now are used to

generate more electrical power worldwide than

any other technology.65 

Gas turbines were not used for commercial

generation of electric power in the United States

until 1961. Spurred by the need for fast-starting

generating capacity and encouraged by the short

lead-times typical of gas turbines, utilities in the

1960s and early 1970s deployed many of these

units. 66

Coal gasifiers were being used commercially

by the early 1800s. By 1930, there were about

11,000 coal gasifiers in the United States. These

were used to produce gas for both light and heat

in cities as well as for industrial uses. From the

1930s through the mid-l950s, development conbsBased on telephone conversation between Bruce w. Morrison,

V.P. Atlantic Region, Westinghouse Electric Corp., and OTA staff,

May 16, 1985.

661 bid .
Ch. 9—The Commercial Transition for Developing Electric Technologies ● 273

tinued, especially in Germany and the United

States. The basic design of large commercial gasifiers which today form the basis for IGCC developments originated during this period. b7

With the availability in the United States of low

cost, reliable supplies of natural gas in the late

1950s and the 1960s, activity involving coal gasification in the United States was maintained at only

a very low level, though it continued to be important in the steel industry. Greater interest continued overseas, however, where circumstances

favored the technology’s development.

The 1970s brought renewed interest in gasification for various applications, including electricity

generation. The use of coal gasifiers in electricity

generation offered some important advantages.

It allowed for greater reliance on domestic coal

resources, less dependence on oil or gas, and its

environmental impacts were less severe than

those of more conventional coal-fired equipment.

In addition, coupling a coal gasifier to a combined-cycle system appeared to meet the growing demand for highly efficient generation.

But the economic use of gasifiers in electricity

production required technical improvements

over earlier commercial technologies, In response

to this need, advanced gasifiers have been developed. Several prime candidates for application in IGCC systems for the 1990s have emerged;

these gasifiers have either been used commercially in some application, or are in advanced

stages of development. Each has specific advantages and disadvantages. The principal corporations developing gasifiers included Texaco, Inc.,

Shell, the Allis Chalmers Corp., Dow Chemical,

the British Gas Corp. (BGC), Kellog Rust (the KRW

gasifier), and Lurgi Gesellschaften. The latter two

corporations have cooperated in the development of a single gasifier design known as the

BGC/Lurgi gasifier.

The current status of gasification systems being developed by these corporations is summarized in table 9-4. Activities directed towards

the development and commercial deployment of

G7synthetic Fuels Associates, Inc., Coa/ Gasification SyStemS.’ A

Guide to Status, Applications, and Economics (Palo Alto, CA: Electric

Power Research Institute, 1983), EPRI AP-3109.

the gasifiers have not been directed just to IGCCs

but to a considerably broader range of applications.

Among the major gasifier systems which had

operated in nonelectric applications in the United

States by mid-l985 were the Illinois Power Co. ’s

Wood River facility, which used a KILnGAS gasifier

developed by the Allis Chalmers Corp. primarily for IGCC applications; and Tennessee Eastman

Co. ’s gasification plant in Kingsport, Tennessee,

which used Texaco gasifiers. Other important

gasification plants have been operated by the

Tennessee Valley Authority; and by the Great

Plains Gasification Associates in Beulah, North

Dakota. Many of these projects have received

Federal support through DOE or the Synthetic

Fuels Corp. Coal gasification meanwhi!e has been

pursued overseas as well.

Only one type of gasifier, developed by Texaco, had by mid-1985 been deployed in an IGCC

installation i n the United States—the Cool Water

Project, the world’s first demonstration of an

IGCC using commercial-scale components. Conceptual studies and other activities concerning

this plant began in the mid-l970s and in 1979

Southern California Edison and Texaco signed an

agreement which formally initiated the project.

The effort later was joined by EPRI, Bechtel

Power Corp., the Japan Cool Water Program Partnership, the Empire State Electric Energy Research

Corp. (a group of New York State utilities), SOHIO,

and General Electric. Sizable loans were provided

by banks in the United States and Japan. EPRI has

made the greatest funding contribution to the

program.

As the project progressed, oil prices dropped.

Avoided costs, the basis for the purchase price

of power produced by the plant, consequently

would not be as high as was originally anticipated

by the project sponsors. They were compelled

to obtain price support guarantees from the Synthetic Fuels Corp. These amounted to a maximum of $120 million, to be provided during the

plant’s demonstration period, running through

June 1989.68

bapaul Rothberg, Synthet/c Fuels Corp. and National Synfue/s policy (Washington, DC: Congressional Research Service, 1984), Issue

Brief Number IB81 139.
274 . New Electric Power Technologies: Problems and Prospects for the 1990s

Table 9-4.—Status of Developing Gasification Technologies

Shell

Dow

●

●

●

●

• 1

❑

● Keystone (Johnston, PA) China

(2 gaslflers) (1 gasifier)

❑

KILnGAS (Wood River)

(1 gasifier)

SOURCE M Gluckman, Electric Power Research Institute personal communication, June 1985

Another IGCC unit soon will be under construction in Plaquemine, Louisiana. Designed by

Dow Chemical, the plant is expected to begin

operating in 1987 with a substantial contribution

from the Synthetic Fuels Corp.–$62O million in

price guarantees. Most recently, three U. S.

utilities—the Potomac Electric Power Co., the Virginia Electric Power Co., and the Detroit Edison

Co.–have initiated the steps which could lead

to the deployment of three IGCC units during the

1990s.69

As suggested above, the development of gasification technologies has generally depended

heavily on Federal support through the Synthetic

Fuels Corp. In addition the Federal Government

b9FOr details on potornac Electric Power co. ’s (PEPCO) Plans, see:

Steven M. Scherer, “PEPCO’S Early Planning for a Phased Coal

Gasification Combined Cycle Power Plant,” paper presented at the

EPRI and Kernforschungsanlage julich Conference on Coal Gasification and Synthetic Fuels for Power Generation, San Francisco,

CA, April 1985.

has supported the development of gasification

through DOE and its predecessor agencies. Most

of this DOE support has been for research, development; and demonstration of surface coal

gasification .70 As indicated in table 9-2, this support peaked in 1978 at $208 million and has declined since to a proposed $15 million for fiscal

year 1986.

Efforts in the private sector on behalf of the

IGCC have emanated mainly from the equipment

developers in the private sector, interested utilities and EPRI. The vendors of both the turbines

and the gasifiers are large corporations which

have funneled considerable capital into the research, development, and demonstration of their

products, While the investments sometimes are

TOsu~ace coal gasification is distinct from underground coal gasification. The latter involves technologies which are very different

from those considered here and are not candidates for IGCC systems in the 199os.
Ch. 9—The Commercial Transition for Developing Electric Technologies ● 275

directed primarily toward the application of the

equipment to the IGCC (as was the case at the

Cool Water Plant), they usually are intended to

advance the technologies over a wider variety of

applications.

EPRI has devoted a large portion of its budget

towards the development of the IGCC, both

through numerous studies and through its funding of the Cool Water Plant. EPRI also parented

the Utility Coal Gasification Association (UCGA),

a group of utilities interested in the IGCC. Formed

by early 1983, the association collected and dissemi nated information on the technology and its

applications, and otherwise encouraged its deployment. The early commercial users of the

IGCC probably will be among the association’s

members.

In addition to participation in the UCGA, some

utilities have been considerably more involved

in the technology. Southern California Edison, for

example, invested heavily in the Cool Water

project and has been very active in promoting

the IGCC.

Industry Outlook and Major Impediments

Three primary criteria must be met if the IGCC

is to make a sizable contribution to generating

capacity in the 1990s. First, a number of utilities

must be convinced the technology will perform

as required over its entire 30-year lifetime. Second, the combination of cost, performance, and

risk will have to be superior to that of both conventional and other developing technologies—

including atmospheric flu idized-bed combustion

(AFBC), Third, projects probably must be initiated

no later than late 1993 if they are to come online within the 1990s.

Taken together, these elements suggest that additional utilities indeed may step forward over the

next 3 to 8 years and initiate IGCC plants. However, the current evidence suggests other factors--the most important of which are discussed

below–may weigh against initiation of many

projects during the short time available. Consequently, there is a possibility that only a few–

perhaps a half-dozen or less–lGCCs will be operating in the United States by the end of the

century.

Equipment Cost and Performance.–Many of

the individual components of the IGCC have

been commercially applied for many years.

Among available components is equipment

which either already is adequate for IGCC applications or probably will be in the near future.

Other components, though, are relatively new

and in fact may be unique to the IGCC. Evidence

from the Cool Water plant experience to date and

from other sources indicates that these components will perform adequately and will not involve excessive cost, However, experience with

IGCCS is still limited, and while the Cool Water

performance has been very good, many utility

investors may still lack sufficient confidence i n

component cost and performance estimates.

Consequently, even if cost reductions or performance improvements are not in fact necessary, uncertainty about equipment cost and performance

may be a serious impediment to timely investment.

Cost and Performance Data/Technology Demonstration.—An important concern about the

IGCC in the eyes of investors over the next 5 to

7 years will be the lack of demonstrated experience with the entire system, and hence the lack

of proven integrated cost and performance data.

The Cool Water plant and the Dow facility probably will be the only IGCCS to which investors

may turn for a reference point, It is perhaps for 

this reason an EPRI in mid-1984 told

a congressional subcommittee that the deployment of at least one or two additional IGCC demonstrations in the United States, using perhaps

the BGC or Shell gasifiers, was a very high priority in promoting clean coal utilization in the

1990s, 71 others too have cited the need for further demonstrations. 72

T] DWain spencer, Electric Power Research Institute, testl mony

presented in hearings held by the Subcommittee on Energy Development and Applications, House Committee on Science and

Technology, U.S. Congress, The Status of Syrrthetic Fue/s and CostShared Energy R&D Facilities (Washington, DC: U.S. Government

Printing Office), No. 106, June 6, 7, and 13, 1984, p. 203.

Tzsee: 1 ) ‘‘Firms plan CGCC Plant i n Michigan, Syrrfue/s Week,

vol. 6, No. 13, Apr. 1, 1985, p. 1. 2) “Va. Power Plans 400 MW

CGCC Plant, ” Synfue/s Week, vol. 6, No. 12, Mar. 25, 1985, pp.

1-2. This article discusses the plans of Virginia Power Corp. to

“repower’ an existing powerplant with a gasification system, and

a combined-cycle system to form a “coal gasificatiordcom bined

cycle” unit or CGCC. The utility has proposed that the Federal Government subsidize the project. It reported that even without Fed-
276 • New Electric Power Technologies: Problems and Prospects for the 1990s

Utilities, of course, will examine their own experiences and those of others with gas turbines,

steam turbines, and combined-cycles, and will

scrutinize gasifiers operating both here and

abroad in nonelectric applications. The favorable experience with those components certainly

will help to reduce the risks perceived by investors, but they are unlikely to fully offset the lack

of experience with the IGCC itself.

Note that as experience with the Cool Water

plant accumulates, experience with AFBCs will

be accumulating much more rapidly as both

demonstration and commercial plants come online under both utility and nonutility ownership

and under different operating conditions. It is

likely that the AFBC, with its larger number of

operating plants and its favorable cost and performance, will pose a formidable challenge to the

IGCC for initial utility commitments.

Licensing and Permitting Delays.–A major

source of delay for IGCCs couId lie in the licensing and permitting process. Though the environmental impacts of the IGCC will be less severe

than those of its conventional competitors, it

nevertheless does have significant impacts on the

environment. Concern over the impacts could result in delays, particularly if the potential environmental impacts are not precisely known by

eguIators, or where important reguIatory issues

regarding the technology have not been satisfactorily resolved,

For example, very little data are available on

the long-term leaching characteristics of gasification ash/sIag. Furthermore, the analytical tools

necessary to adequately determine the possible

eral support, it would install the combined-cycle portion of the plant

and operate it beginning in 1993. But the gasification portion of

the project would be delayed without Government support; the

system would employ natural gas instead of gas produced from coal.

Referring to the gasification portion of the system, officials of the

utility reportedly stated that “the technology is unproven and the

utility decided that privately financing its early introduction in the

marketplace would be ‘an unreasonable risk to (Virginia Power)

ratepayers and stockholders. ’ “ A company official was quoted as

saying: “We are a risk averse industry. Without some Government

help to defray the risk, our implementation of the gasification technology would just have to wait. ” According to the utility, without

Government assistance, the “conversion to coal gasification could

be subsequently pursued when the technology and economics become favorable about ten years later or 2003. ”

impacts of the solid waste in a specific environment, and to properly develop or assess measures to mitigate those impacts, are lacking. Yet

such data and methods are required to properly

determine whether or not the solid waste should

be treated as hazardous or nonhazardous, and

in evaluating specific plant proposals .73

Certainly measures can be taken by government authorities to expedite the IGCC’s progress

through regulatory channels. ’d Regulatory bodies may provide an IGCC technology with special treatment, as was the case in California with

the Cool Water project, Under such circumstances,

delays may be reduced substantially. More importantly, constructors of initial plants can work

closely with regulatory bodies to ensure efficient

resolution of potential concerns. If either of these

paths are followed, the amount of IGCC capacity

by the year 2000 could be substantially higher

than would otherwise be the case. If such is not

the rule, however, delays could result because

of the newness of the technology that could seriously impede the ability of project promoters to

bring IGCCs on-line before the end of the century.

Stringency of Environmental Regulations.–

A major advantage of the IGCC over its conventional competitors is its potential to operate with

lower nitrogen oxide and sulfur oxide emissions,

at incremental costs lower than those associated

with equivalent emission reductions in a conventional coal plant. Where emissions are severely

limited, the IGCC is able to capitalize on this

advantage. Where such limitations are lacking,

however, the IGCC is less able to successfully

compete with the more conventional alternatives.

The lack of stricter regulations which require

lower emissions consequently may reduce incenTJMasood Ghassemi and George Richard, “Regulatory Requirements for Land Disposal of Coal Gasification Waste and Their implications for Disposal Site Design, ” Energy Sources, vol. 7, No.

4, 1984, pp. 357-376. The authors state that “. . . environmental

issues involving disposal of these wastes may constrain the commercial development of gas supply technologies” (p. 358).

Zdsee: 1 ) Masood Ghassemi and George Richard, “Regulatory Requirements for Land Disposal of Coal Gasification Waste and Their

Implications for Disposal Site Design, ” op. cit., 1984. 2) Arturo

Gandara, “Environmental Considerations in Siting Alternative Fuel

Generating Facilities, ” California Energy Commission News and

Comment, No. 13, spring 1984, pp. 4-18 (reprint of testimony presented to the Advisory Committee on Federal Assistance on Alternative Fuels, Oct. 31, 1983).
Ch. 9—The Commercial Transition for Developing Electric Technologies ● 277

tives to more extensive deployment of IGCCs in

the 1990s.

Fuel Use Restrictions.–An IGCC plant typically will require access to natural gas. If the installation is built in stages, the gas turbines can

be installed first and can use natural gas as an

interim fuel until the gasifiers are completed. Also,

natural gas can be used during the lifetime of the

plant to replace or supplement the synthetic gas

produced by the gasifiers. As explained earlier,

the Fuel Use Act prohibits the use of natural gas

under certain conditions. An exemption would

be required from the Federal Government which

would permit the use of natural gas in an IGCC.

This could cause delays in a project, and denial

of an exemption may even lead to project abandonment.

Atmospheric Fluidized-Bed

Combustors

History and Description of the Industry

In the early 1920s, fluidized beds were applied

for the first time in Germany to produce combustible gases from coal. Subsequent development led to their use in “cracking” the heavy

fractions of petroleum, first in 1942 and extensively thereafter. Further efforts led to their application to other industrial uses and eventually

to produce steam. The first commercial fluid izedbed boiler began operation in France in 1955.

Serious development of fluidized-bed boilers did

not begin in the United States until 1965.75

By 1976, DOE was funding the construction of

the first industrial-sized AFBC boiler in the United

States–a 30 MWe pilot plant in Rivesville, West

Virginia. Several more small industrial AFBCs

were built in the late 1970s and early 1980s as

the technology progressed rapidly and small

AFBCs became competitive with conventional

options in the marketplace. Coincident with the

emergence of small AFBCs during this period was

the implementation of PURPA, which set the

stage for a rapid increase in the deployment of

AFBCs in cogeneration applications.

By early 1985, over 2,200 AFBCs were operating in China, and between 200 and 300 were

operating or under construction elsewhere in the

world, mostly in Western Europe, Japan, and the

United States. Most of those outside China were

small industrial units. Over 40 small AFBCs were

operating or under construction in the United

States by early 1985, and by mid-1985, over a

dozen privately financed commercial AFBC cogenerators were being built in the United States.

Unit sizes of these U.S. plants range from 15 to

125 MWe; none of these fully commercial units

is owned by an electric utility. ’G

The electric utilities are, however, showing a

growing interest in the technology. The thrust of

utility-sponsored R&D has been the development

of AFBCs with capacities in excess of 100 MWe

for retrofit to existing powerplants or for entirely

new plants. Toward this end, three demonstration projects are currently under construction.

Two are retrofit units being incorporated into existing plants .77 The third is a 160 MWe demonstration unit at the Tennessee Valley Authority’s

(TVA) Shawnee Steam Plant in Paducah, Kentucky. The retrofit units will begin operating in

1 to 2 years; the TVA unit is expected to be fired

first in 1989.

Central to the utility efforts has been the Electric Power Research Institute. By 1977, EPRI had

built a 2 MWe pilot plant. This was followed by

a 20 MWe plant which began operation in 1982.

EPRI now is partly funding all three of the above

mentioned demonstration projects.

75heltonEhrlich, “History of the Development of the FluidizedBed Boiler, ” Proceedings of’ the 4th International Conference on

Fluidized-8ed Combustion, Dec. 9-11, 1975 (McLean, VA: MITRE

Corp., May 19761,Publlcatlon M76-36, pp. 15-20; and A.M. Squires,

“Contrlbutlons Toward a History of Fluldlzatlon, ” Proceedirrgs of

the Jo/nt Meeting ot’ the Amer/can Institute of Chemical Engineers

and the Chemical Industry and Engineering Society of Ch\na, Sept.

20-22, 1982 (New York: American Institute of Chemical Engineers,

1983), pp. 322-353.

TbFor a comprehensive review of the current status of AFBC’S,

see: Bob Schwieger, “Fluidized-Bed Boilers Achieve Commercial

Status Worldwide, ” Power, vol. 129, No. 2, February 1985, pp.

S-1 through S-16.

‘These are the Colorado Ute 100 MWe Nucla unit, scheduled

to begin operating In 1987; and the Northern States Power Co. ’s

125 MWe Black Dog Unit 2, expected to be In operations in 1986.

Note that one small retrofit unit already has operated. This is the

Northern States Power Co.’s French Island Plant, Unit #2. The 15

MWe retrofit began operation In 1981.
278 . New Electric Power Technologies: Problems and Prospects for the 1990s

The Federal Government too has supported the

technology with a program which first led to the

construction of the Rivesville plant in 1976 and

subsequently to a series of pilot and demonstration facilities. Federal support peaked in 1980 at

almost $30 million and has dropped sharply

since. By far the largest portion of Federal funding for the AFBC now is channeled into the TVA

160 MWe demonstration plant–$30 million of

the $22o million required for that project.

The industry which supplies AFBCs is large and

well established. About 50 companies sell the

industrial-sized boilers worldwide. Often, these

are the same companies which sell conventional

technologies. The adoption of the AFBC by these

firms is likely to facilitate its deployment in the

United States.

Industry Outlook and Major Impediments

Four applications of the AFBC may be important over the next 15 years: grass-roots electriconly plants, retrofit electric-only plants, cogeneration installations, and nonelectric systems. The

electric-only units are likely to be deployed by

utilities, whereas the cogeneration and nonelectric units probably would be built and operated

by nonutility investors.

Current evidence suggests that the electric-only

retrofit units, and cogeneration plants and nonelectric facilities financed by non utilities may very

well dominate the AFBC market in the 1990s. The

rapid accumulation of operating experience with

these units and their short lead-times—substantially shorter than those which wou Id characterize large 100 to 160 MWe grass-roots, electriconly units’ B—makes their near-term prospects

very bright.

The small AFBCs are being deployed extensively and many are expected to be initiated over

the next decade. The market appears to be vigorous and growing, and suppliers abound. No

barriers unique to these small units are expected

to impede deployment, though some problems

zsRetrofit u nits i n many cases involve very little regulatory delay,

as they are deployed at preexisting plants. Cogeneration units and

nonelectric units commonly are very small, are not owned by utilities, and are not subject to the same extensive regulatory delays

which characterize large utility owned projects.

common to nonutility technologies—such as the

adequacy of PURPA avoided cost payments—

may develop.

A substantial utility retrofit market has also been

identified; strong evidence indicates that numerous powerplants in the United States are candidates for AFBC retrofits. Most are small (less than

200 MWe), old units which are configured so as

to allow a retrofit. Retrofit units probably will

dominate early utility involvement with the AFBC.

By the 1990s there will be more operating experience with retrofit units than with large grass-root

units. Such retrofits appear to offer utilities a low

cost option for improving existing capacity; they

also require less time to deploy than the grassroots plants. Commercial retrofits therefore could

begin coming on-line before 1995, and large

numbers may commence operating before the

close of the century.

By the early 1990s, experience with the large

utility demonstration units, expected to begin

operating in the Iate 1980s, as well as experience

with the smaller AFBCs outside the utility industry, may foster both technical improvements and

utility confidence. The prospects appear to be

good that extensive utility orders of large, commercial, grass-roots plants could begin at that

time; 79 these plants could provide substantial

amounts of electricity by the late 1990s. Delays

of any kind, however, may limit the potential of

AFBC grass-roots plants within this century. Such

delays could be occasioned by problems or uncertainties associated with the performance of the

larger AFBC units, or by difficulties in the licensing or permitting process.

Compressed Air Energy Storage

Industry Description, History, and Outlook

Major efforts in the United States on behalf of

compressed air energy storage (CAES) began in

the latter half of the 1970s, stimulated by the Federal Government, the Electric Power Research institute, interested utilities, and others. Most

79see Robert Smock, “Utilities Look to Fluid Bed as Next Step

in Boiler Design, ” Electric Light and Power, vol. 62, No. 7, July

1984, pp. 27-29; and Taylor Moore, “Achieving the Promise of

FBC,” EPR/journa/, vol. 10, No. 1, January/February 1985, pp. 6-15.
Ch. 9—The Commercial Transition for Developing Electric Technologies “ 279

i m portant to these early efforts were three preliminary engineering-design studies, completed

in 1981, which investigated the utility-specific application of CAES to the three major storage

media (hard rock, salt, and aquifer CAES). Shortly

before these studies were finished, in November

1980, the Soyland Power Cooperative, Inc., in

Decatur, Illinois, formally committed itself to

building the first U.S. CAES plant.

As these events unfolded in the United States,

the world’s first CAES plant was built in Huntorf,

West Germany; it began operating in December

of 1978. Since that time, the 290 MWe Huntorf

unit has operated nearly 7 years without serious

problems. Furthermore, a smaller 25 MWe CAES

unit recently was completed in Italy. Despite the

successful operation of the German plant, the

construction of the Italian plant, and efforts in the

United States to deploy CAES plants here, this

country still is without even a demonstration

plant. The Soylands plant was canceled, and

since then no U.S. utility has initiated construction of a CAES plant.

Federal support rapidly declined after peaking

in 1978-79. Beginning with fiscal year 1983, DOE

has provided no support to the technology (see

table 9-2). Others, however, have continued promotional efforts. Although no CAES plants are

now being constructed, EPRI and a private firm

are currently performing an initial screening analysis of CAES on 10 utility systems. EPRI also is

planning to provide funds in support of initial

plant siting studies with interested utilities and in

support of the installation of two or more so

MWe “mini-CAES” plants.80 Additionally, four

consortia of architect/engineering firms, turbomachinery suppliers and cavern builders have

been formed to supply initial plants.81

These developments suggest that several miniCAES units could be initiated and built by the

early 1990s. There are, however, no strong indications that a maxi-CAES plant (with a capacity

of several hundred megawatts) will be initiated

in the next several years and will be on-line within

the first few years of the 1990s. Since a maxi-CAES

plant will require a lead-time (including licensing and permitting) of approximately 5 to 8 years,

plans to build any commercial maxi-CAES units

must be underway no later than the end of 1994

for contribution to generating capacity within this

century. Current evidence suggests that utility

orders wou Id be unlikely without a U.S. demonstration plant.

The prospects for mini-CAES plants in the United

States appear to be much brighter. A mini-CAES

plant requires a lead-time of approximately 4.5

to 6.5 years. If several are initiated by the end

of 1986, they could be on-line by mid-l 990. If

extensive mini-CAES capacity is to be on-line by

the year 2000, however, plans to build such

plants should be initiated no later than mid-l990.

This would allow approximately 5 years for the

demonstration units to operate and for a substantial market demand to develop.

Such rapid growth in demand is possible, given

the favorable Ievelized cost which might characterize CAES units (see chapter 8), and given the

fact that many of the components are conventional and commercially available. Furthermore,

the appropriate geology underlies 75 percent of

the United States, so the market is potentially

large and varied. EPRI estimates that CAES technology has the potential of supplying 4 to 8 percent of peak demand by the year 2000.

82

To accomplish this will require that lead-times

be kept short, and that other impediments be successfully cleared. The major impediments are discussed below. Unless these are effectively and

speediIy eliminated, demand is more likely to increase gradually, with large numbers of orders

unlikely before the latter half of the 1990s.

Major Impediments to the Commercial

Deployment of CAES Systems

The major impediments to high deployment

levels for CAES by the end of the century are outlined below.

BODa\,ld Rigney, Electric Power Research I nstltute, ‘‘Notes on

Compressed Air Energy Storage, ” provided to Brian E. Curry, Northeast Utilitles, March 1985.

~’ Ibid.

82Robert 6. Schai n ker, Executive OL(erviek$t: CO f77pKS6’d Air

Energy Storage (CAES) Power P/anrs (Palo Alto, CA: Electric Power

Research Institute, August 1983), mimeo.

38-743 0 - 85 - ]()
280 ● New Electric Power Technologies: Problems and Prospects for the 1990s

Uncertainty Regarding Plant Cost and Performance.–As discussed above and in chapter

4, while all of the individual above-ground components with the exception of the recuperative

heat exchanger have been employed in other

commercial applications, the performance of integrated assemblies coupled to specific geologic

reservoirs is still unproven in the United States.

A principal area of concern is the impact of

daily variations in pressure, humidity, and temperature on the reservoirs; these at present are

not precisely known.ss The prime concern is leakage of the air from the reservoir. Until one or

more units have been installed and operated for

at least several years, uncertainty will still trouble investors and is likely to strongly inhibit investment in CAES.

Licensing and Permitting Delay s.–As discussed in chapter 4, several regulatory problems

cou Id delay deployment of a CAES plant. These

plants employ a gas- or oil-fired combustion turbine. The operator of the plant must obtain an

exemption from the Powerplant and Industrial

Fuel Use Act of 1978. Other delays might result

from environmental impacts; regulatory problems

might arise regarding atmospheric emissions, well

drilling and construction, water consumption and

contamination, and cavern excavation. The relative inexperience of all concerned parties with

CAES could further complicate the licensing and

permitting process.

Batteries

Industry Description, History, and Outlook

Batteries first appeared in the 19th century and

were quickly applied to railroads, telephones,

and lights, Near the beginning of this century, the

all-electric automobile appeared using batteries,

but it was not until 50 years later that utilities used

batteries to level loads in urban areas. For example, batteries were used in Chicago to compensate for the effects on the direct-current (DC) electric system of elevators and lights in large

downtown build ings.84 As the use of DC power

~~DeCISiOn FOCUS Inc., Compressed-Air Energy Storage: Commercialization Potential and EPRI Roles in the Commercialization Process (Palo Alto, CA: Electric Power Research Institute, 1982), EPRI

EM-2780.

8~Jen ny Hopkinson, “The New Batteries, ” EPR/ journa/, vol. 6,

No. 8, October 1981, pp. 6-13.

systems declined in the 1930s, the use of batteries by utilities declined as well.85

Over the past dozen years, however, batteries

for stationary applications have been the subject

of renewed interest and development. Rapid

technical progress has been made and batteries

may eventually be used extensively in gridconnected applications to enhance peak load capacity.

At the forefront of battery development have

been manufacturers in Western Europe, Japan,

and the United States. Often closely affiliated with

these R&D programs have been parallel efforts

to develop batteries for mobile applications. Efforts directed towards stationary applications in

the United States have been led by DOE, EPRI,

and interested utilities, as well as by battery manufacturers themselves.

DOE and EPRI together have funded the construction and operation of the national Battery

Energy Storage Test (BEST) Facility in New Jersey as a national center where prototype battery

modules are tested and evaluated, along with

other related equipment. The facility first began

operating in 1982. By May 1985, both advanced

lead-acid and zinc-chloride batteries had been

tested in the facility. Sodium-sulfur (or beta) and

zinc-bromide batteries are expected to be installed around 1989 or 1990.

The Japanese meanwhile have vigorously developed batteries under the auspices of MITI’s

Moonlight program since fiscal year 1980. The

goal of the program is to demonstrate two 1

MWe, 8 MWh battery installations by 1990. As

is the case in the United States, both utilities and

their customers have been identified as prime

markets. 86 Already the batteries are being used

by utility customers in Japan; the Japanese National

Railways, for example, has installed a JapaneseBspeter A. Lewis, Elernerlfs of Load-Leveling Battery Design for

System Harming, paper presented at the International Symposium

and Workshop on Dynamic Benefits of Energy Storage Plant

Operation.

My Arlga, et al., Central Research Institute of Electric power industry (Japan), “Optimum Capacities of Battery Energy Storage System for Utility Network and their Economics, ” Advanced Energy

Systems–Their Role in Our Future: Proceedings of the 19th /ntersociety Energy Conversion Engineering Conference, Aug. 19-24,

1984 (San Francisco, CA: American Nuclear Society, 1984), paper

849050, pp. 1075-1080.
Ch. 9—The Commercial Transition for Developing Electric Technologies . 281

made lead-acid battery system .87 Western European manufacturers are very active as well. indeed, West Berlin became the location of the

world’s first large, modern, grid-connected battery installation. After operating a small prototype

facility, the city’s utility decided to build a 17

MWe, 14.4 MWh facility. Plant construction began in early 1985.88

The battery technologies favored for widespread deployment in the 1990s are advanced

lead-acid and zinc-chloride batteries. Both types

of batteries have been successfully tested at the

BEST Facility, The EPRI, vendors of both types of

batteries, and others are laying the groundwork

for the subsequent step for commercialization:

multi-megawatt demonstration units within the

next 5 years.

Early markets for the stationary batteries could

reside with both utilities and non utilities. Utilities can use batteries to level loads, shave peaks,

regulate systems, or for spinning reserves. Nonutilities—commuter railways, for example—may

use batteries to avoid the high cost of electricity

during peak periods and to take advantage of

lower prices during base periods. Recent analyses suggest that in some cases batteries could

present very attractive investment opportunities.89

The strongest segment of the battery industry

is concentrating on the lead-acid battery. About

a half-dozen companies, primarily producers of

automotive batteries, consider the large loadIeveling batteries as a technology with considerable promise and have active R&D programs. go

Lead-acid batteries are strong contenders, in

part because the precipitous drop in lead prices

resulting from Government-mandated removal of

lead from paint and gasoline has drastically reduced raw-material costs. In addition, the leadacid battery industry is strong and well-estab-

— —-— —-

’17G ten n Zorpette, “High-Tech Batteries for Power Utilities, ” /EEE

Spectrum, vol. 21, No. 10, October 1984, pp. 40-47.

8% Ien n Zorpette, “High-Tech Batteries for Power Utilities, ” op.

clt,, October 1984.

89Bech(e/ Group, Ir-rc-., l.)pddtd Cost Estimate and Benefit Analysf$ of Customer-Owrwd Battery Energy Storage (Palo Alto, CA: Electrlc Power Research Institute, January 1985), EPRI EM-3872.

qclA~hu r D. Little, Commercia/izatlon Strategy for Lead-Acid Batteries In /Jtl/lty Load Leie//ng Applic-at/ons (Cambridge, MA: A rthur D, Little, Inc., 1980), DOE/ET) 26934-l.

Iished. However, while the industry is considered

capable of financing the construction of a mass

production facility, and though stationary markets have interested all the major battery manufacturers, to date they have been reluctant to

make major investments. Apparently, they perceive the stationary market to be too unpredictable—particularly when compared to the automotive market. A major uncertainty lies with the

effect changing gas and oiI prices wouId have on

the technological choices between batteries and

conventional generating technologies in meeting

the need for peaking capacity. 91

Meanwhile, the development of the zinc-chloride battery has been shouldered mainly by one

firm, Energy Development Associates (EDA) .92

The company has introduced a large, prototype

commercial module, known as the “FLEXPOWER”

commercial load-leveling battery. It is rated at 2

MWe, 8MWh. It plans to deploy the system in

four stages, with the ultimate goal of commercially deploying the technology by the late 1980s

or early 1990s.93 Its design was “heavily influenced by the desire to meet both electric-utility

and customer side-of-the-meter markets with

similar hardware. ”94 The demonstration phase for

the system will include installation and operation

of a system by an industrial customer.

Major Impediments to the Commercial

Deployment of Batteries

The major impediments to the widespread

commercial deployment of batteries in the 1990s

are discussed below.

Technology Demonstration.–The successful

testing of both lead-acid and zinc-chloride battery modules has provided encouraging evidence

in favor of the batteries. Commercial-scale mu kimegawatt installations are required, however,

which will demonstrate the capabilities of the systems on a commercial scale, over extended peri1111 bid.

9ZA Su b5id iary of Gu If+ Western I nd ustnes.

938 D. Bruin met, et al., Zinc-chloricie Battery systems tbr EleCfriCUri/lty Energy Storage, paper presented at the 19th Intersociety

Energy Conversion Engineering Conference, Aug. 19-24, 1984, San

Francisco, CA.

94 B D, Bru m met, et al., zinc-Ch/Ori& Battery SyStemS for E/ectricUti/ity Energy Storage, op. cit., 1984.
282 ● New Electric Power Technologies: Problems and Prospects for the 1990s

ods, and under the variety of conditions expected

of actual commercial plants. Until such demonstrations have taken place, extensive investment

is unlikely.

Equipment Cost and Performance. -Until demonstrations have been completed, and experience has accumulated, it will be difficuIt to precisely identify cost and performance impediments

to commercial applications of batteries. A key

variable affecting the future of lead-acid batteries will be the price of lead; low prices will be

required to maintain acceptable costs.

For zinc-chloride batteries, the major variable

probably will be the level of demand for the large

stationary batteries. Low costs will depend on

mass production; mass production in turn will require a sizable market. Vendors will be reluctant

to invest in manufacturing capacity without strong

indications that the market wiII absorb the quantities produced; yet the market is unlikely to develop until mass production drives prices down.

This “chicken-or-the-egg” dilemma may be the

least tractable of the impediments confronting developers of the zinc-chloride battery in the 1990s.

This problem is considerably less serious with the

lead-acid battery because many of the lead-acid

battery’s components can be produced with existing faciIities dedicated to pre-existing markets.

Lead-acid battery prices therefore are less sensitive to initial demand for the large stationary units.

Utility Rate Structures.—The price customers

pay for the use of utility-generated electric power

during peak periods may differ from the price

paid during off-peak periods, A demand charge

may be imposed based on a customer’s peak demand (cost/kWe). Or, the energy charge (cost/

kWh) may be higher during peak periods than

during other times of the day. Hence, there is an

incentive for the customer to shift consumption

away from peak periods. One way of doing this

is with batteries. With low demand and energy

charges or no incentive pricing, however, a battery may not be justified. Or, even if the charges

are high at present, the possibility that they may

decrease (relative to off-peak rates) discourages

customer investment in batteries. Current evidence indicates that both low charges and uncertainty over charges could be major impediments to customer investments i n batteries. 95

Licensing and Permitting.–Generally, the installation and operation of a battery unit will

cause impacts far less serious than those associated with most competitors. In most cases, few

regulatory delays are likely to result. But for zincchloride batteries, serious licensing and permitting delays might occur as a result of the possibility that large volumes of chlorine or bromine

might be released accidentally from a proposed

battery installation. Consideration of the possible problems is not likely to stop deployment in

any particular instance. But difficuIties, particularly with regulatory officials not well acquainted

with the the technology or where the site is in

a densely popuIated area, couId arise and cause

lengthy delays.

95 Bechtel Group, [ flc., @dS;~i/l~y Assessment of Customer-Sideof-the-Meter Applications for Battery Energy Storage (Palo Alto, CA:

Electric Power Research Institute, 1982), EPRI EM-2769; and Electric Power Research Institute, Uti/ity Battery Operations and Applications (Palo Alto, CA: Electric Power Research Institute, 1983),

EPRI-2946-SR.
Chapter 10

Federal Policy Options
CONTENTS

Page

Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ................253

Status and Outlook for the Developing Technologies . . . . . . . . . . . . . . . . . . . . . .......253

Solar Photovoltaics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ...........253

Solar Thermal Electric Plants .., . . . . . . . . . . . . . . . . , , . . . . . . . . . . . . . . . . . ...259

Wind Turbines . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .............262

Geothermal Power. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..266

Fuel Cefls . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .............269

Integrated Gasification/Combined-Cycle Plants . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 272

Atmospheric Fluidized-Bed Combustors. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 277

Compressed Air Energy Storage . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ......278

Batteries . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. ...280

List of Tables

Table No. Page

9-1. Estimated Magnitude of End-Use Markets for Photovoltaics, 1984..............255

9-2. Federal Program Funds in Support of Developing Technologies . ...........,..255

9-3, Projected 1986 Photovoltaic Shipments by Domestic Manufacturers . ...........256

9-4. Status of Developing Gasification Technologies . . . . . . . . . ....................274

List of Figures

Figure No. Page

9-1. 1984 World Photovoltaics Supply . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .., ..254
Chapter 10

Federal Policy Options

OVERVIEW

Over the last several years, the need to diversify the electricity generation mix has become increasingly clear, part of the strategy for meeting

this policy objective has been sustained development of new electric generating technologies.

With considerable uncertainty in load growth as

well as other major policies affecting utility and

nonutility decisions about new and existing

power generating capacity, the attainment of a

diverse generation mix has taken on added dimensions. Because of this uncertainty, it may be

prudent to accelerate the availability of the technologies discussed in this study so that they could

make a greater contribution in the 1990s than

currently is expected.

Seeking diversity in electricity supply options

is now not only being pursued to reduce dependence on oil but also in anticipation of the variety

of future circumstances as discussed in the chapter 3, such as more stringent control of air pollution emissions or increased availability of natural gas. Developing technologies are of interest

in the short term since they might contribute to

ensuring a reliable and economic supply of electricity over the next two decades under a variety of these future circumstances. Many of these

technologies also offer promise of fuel flexibility,

increased efficiency, and other advantages. An

increased contribution before the turn of the century, however, will require accelerated development of these new generating technologies, including progress in a number of critical areas. This

is because at the current rate of development very

few of the technologies considered in this assessment are likely to be deployed extensively in the

1990s,

This chapter discusses a range of alternative

policy initiatives that could accelerate the commercial deployment of developing generating and

storage technologies in the 1990s, The goals and

options are summarized in table 10-1. The first

three:

Table 10-1 .—Policy Goals and Options

Reduce capital cost, improve peformance, and resolve

uncertainty:

1. Increase Federal support of technology demonstration

2. Shorten project lead times and direct R&D to near-term

commercial potential

3. Increase assistance to vendors marketing developing

technologies in foreign countries

4. Increase resource assessment efforts for renewable

energy and CAES resources (wind, solar, geothermal,

and CAES-geology)

5. Improve collection, distribution, and analysis of

information

Encourage nonutility role in commercializing developing

technologies:

1. Continue favorable tax policy

2. Improve nonutility access to transmission capacity

3, Develop clearly defined avoided energy cost

calculations under PURPA

4. Standardize interconnection requirements

Encourage increased utiiity involvement in developing

technologies:

1. Increase utility and public utility commission support

of research, development, and demonstration activities

2. Strengthen provisions for utility subsidiaries involved

in new technology development

3. Resolve siting and permitting questions for developing

technologies

4. Other legislative initiatives: PIFUA, PURPA, and

deregulation

Resolve concerns regarding impact of decentralized

generating sources on power system operation:

1. Increase research on impacts at varying levels of

penetration

2. Improve procedures for incorporating nonutility

generation and load management in economic

dispatch strategies and system planning

SOURCE Office of Technology Assessment

A. Reduce capital cost, improve performance,

and resolve uncertainty,

B. Encourage nonutility role in commercializing developing technologies, and

C. Encourage increased utility involvement in

developing technologies,

are the primary goals; while the fourth:

D. Resolve concerns regarding the impact of

decentralized generating sources (and load

management) on power system operation,

is less critical although still important.

285
286 . New Electr/c Power Technologies Problems and Prospects for the 1990s

GOAL A: REDUCE CAPITAL COST, IMPROVE PERFORMANCE,

AND RESOLVE UNCERTAINTY

As discussed in chapters 4 and 8, the current

cost and performance characteristics (including

uncertainty) of developing generating and storage technologies considered in this assessment

generally do not yet compare favorably with either conventional generating options or other

strategic options such as load management and

life extension of existing powerplants. Of particular concern is the uncertainty in cost and performance anticipated in early commercial utility applications. Even in the case of load management,

already being pursued aggressively by many utilities, widespread deployment of load management in the 199os will depend on continued experimentation by utilities to resolve operational

uncertainties; the refinement of load management equipment and techniques including adequate demonstration of communications and

load control systems; development of incentive

rate structures; and a better understanding of customer acceptance.

The following are alternative policy options

aimed at reducing cost, improving performance,

and resolving uncertainty in both cost and performance.

Option Al: Increase Federal support of

technology demonstration

A critical milestone in both utility and nonutility power producer acceptance of new technology is completion of a commercial demonstration program. There is considerable debate in the

industry over what constitutes a demonstration

program, but usually two basic categories are distinguished. One is a proof-of-concept phase

which provides the basic operational data for

commercial designs as well as test facilities designed to prove the viability of the technology under non laboratory conditions, and to reduce cost

and performance uncertainties. The other involves multiple applications of a more or less mature technology designed to stimulate commercial adoption of the technology. In theory the

distinction seems clear; in practice, it sometimes

is not. Generally, though, activities in the first category are necessary for demonstrating technical

feasibility, and activities in the second category

are necessary for demonstrating commercial

readiness and for accelerating acceptance by utilities or nonutility power producers.

The length of the appropriate demonstration

period will vary considerably by technology,

However, adequate demonstration periods (perhaps many years for larger scale technologies) are

crucial to promoting investor confidence. Moreover, the nature of the demonstration program—

i.e., who is participating, who is responsible for

managing it, and the applicabiIity of the program

to a wide variety of utility circumstances—is crucial too, if utilities, in particular, are eventually

to buy the technology.

Many utility decision makers argue that the perceived and real obstacles to adoption of developing generating technologies can be removed

by “well-managed federally sponsored incentives

and projects.’” A key ingredient is the nature of

the relationship between government and industry in such ventures. A cooperative research and

development (R&D) partnership has proven to be

a key ingredient in many successful demonstration programs. Demonstration programs should

have the following characteristics:

●

●

●

The private sector should have considerable

influence in the selection of technologies for

demonstration as well as principal responsibility for demonstration program design

and management of the demonstration project itself.

Private sector proprietary rights and ownership should be preserved, provided that such

protection does not inhibit timely development of the technology.

Cost sharing between government and industry has generally proved successful in ensuring both careful selection of the most

‘1. R, Straugh n, Director of Research and Development, Southern Cal iforn la Edison Co., testimony before the House Corn m ittee

on Science and Technology, Subcommittee on Energy Development and Applications, June 13, 1984.
Ch. 10—Federal Policy Options ● 2 8 7

competitive projects and timely completion

of the projects.

• FederaI Government commitments to a

demonstration program should be stable and

predictable–i.e., once made, such commitments shouId be honored for a sufficient

period in order to convince developers that

government is a ‘‘reliable partner. ’

. First-of-a-kind, tuII-seaIe demonstration facilities shouId include support by all partners

involved i n the demonstration program for

not only plant engineering and construction

but also for extended plant operations.2

Smaller modular plant designs, where possible,

are very attractive for demonstration projects

since they normally require a smaller capital commitment than large central station designs. In addition, successful demonstration projects have inCIuded active participation from a wide range of

private sector interests such as architect-engineering firms, equipment manufacturers, as well as

the utilities themselves when appropriate.

Option A2: Shorten project lead-times and

direct R&D to near-term commercial

potential

Virtually all of the technologies considered in

this assessment offer the potential of sizable deployment in electric power generation applications beyond the turn of the century. At the current rate of development, however, few of these

technologies are likely to be extensively put in

place in the 1990s. Under conditions of accelerated load growth in the 1990s, an increase in or

a refocusing of current Federal research, development, and demonstration (RD&D) activities

could accelerate the deployment of early commercial units for most of the technologies considered in this assessment. This includes attention not only to the technologies themselves, but

also to manufacturing techniques and equipment

necessary to produce the technologies.

While the technologies considered here encompass a wide range of sizes, scales, and levels

of technological maturity, for purposes of discussing appropriate policy actions, it is convenient

to divide them into two basic groups:

●

●

A

The first consists of technologies envisioned

primarily for direct electric utility applications, including integrated gasification/combined-cycle (IGCC) plants, large ( >100 MW)

atmospheric fluidized-bed combustors (AFBC),

large (> 100 MW) compressed air energy

storage (CA ES) facilities, large ( >50 MW)

geothermal plants, utility-owned fuel cell powerplants, and solar thermal central receivers.

The second group consists of technologies

suitable either for utiIity or non utility applications, including fuel cells and small ( <100

MW) AFBCs in nonutility cogeneration applications, small (< 100 MW) CAES, wind

turbines, small ( <50 MW) geothermal plants,

batteries, and other solar power generating

technologies such as photovoltaics and parabolic dish solar thermal.

characteristic of the first group of technologies is the Iikelihood of long preconstruction and

construction lead-times—up to 10 years. Although

these technologies have the potential for much

shorter Iead-times---5 to 6 years—problems associated with any new, complex technology may

require construction of a number of plants before that potential is met. If the longer lead-times

are needed, deployment in the 1990s will be

limited because of short time remaining to develop the technologies to a level acceptable to

a broad array of utilities.

The technologies in the second group are likely

to have shorter lead-times and are often smaller in

generating capacity. For increased contribution

in the 1990s, however, most of these technologies

will require stepped up development to reduce

cost and resolve cost and performance uncertainties that concern utility decision makers and nonutility investors.

It is important to note that this division between

these two groups of technologies is not rigid.

Some technologies the first group could also benefit from accelerated R&D and some in the sec-
288 Ž New Electric Power Technologies: Problems and Prospects for the 1990s

ond group could benefit from policies aimed at

shortening lead-times. This overlap should be

considered in applying policy actions to either

group.

Generally, though, the steps necessary to accelerate contribution to electricity supply vary according to the technology. With the first group

of technologies, it is necessary, first, to resolve

cost and performance uncertainties within the

next 5 to 6 years; and second, to take steps to

achieve the short lead-time potential for early

commercial units. Uncertainties in cost and performance stem largely from the lack of sufficient

commercial operating experience to satisfy nonutility investors and utility decision makers. Utility decision makers, in particular, in the wake of

their experience with nuclear power, are now

particularly wary of new technology, especially

large-scale technology, and they impose rigorous

performance tests on technology investment

alternatives. This conservatism confers added importance to advanced commercial demonstration

projects, as mentioned earlier in option Al.

On the other hand, no significant acceleration

of existing RD&D schedules for the basic designs

of the IGCC, large AFBC, and utility-scale geothermal plants is likely to be required for these

technologies to be ready for the 1990s. Their transition from demonstration to early commercial

units, however, will have to be accelerated if the

technologies are to be used in serving demand

growth in the 1990s if it occurs. Variations in basic

designs or more advanced designs, however, will

require additional R&D.

Lead-times being experienced by early commercial projects in both groups of technologies

have been longer than anticipated, partially due

to the time required for regulatory review. As regulatory agencies become more familiar with the

technologies, and their environmental benefits

become clearer, the review process should become smoother and more predictable, although

this is by no means guaranteed as evidenced by

the history of other generating technologies. If

there is accelerated demand growth, however,

it may be necessary to take those actions to ensure lead-times consistent with those possible for

these technologies. Such actions include working closely with regulators, and careful management of construction and early operation. By emphasizing smaller unit size–200 to 300 MW–

these actions would be made easier. The success

of the Cool Water project shows that such actions are possible and effective.

For the technologies in the second group,

where cost and performance are of particular

concern, one approach to accelerating development would be to increase or concentrate Federal R&D efforts on those technologies. This could

be particularly effective for photovoltaics, solar

thermal parabolic dishes, and advanced small

geothermal designs.

Option A3: Increase assistance to vendors

marketing developing technologies in

foreign countries

The new generating technologies that appear

to show the most promise for substantial deployment in the 1990s are those that currently serve

or have the opportunity to serve markets other

than the domestic utility grid. Such markets are

especially important as long as demand growth

for new electric generating capacity is low and

while cost and performance of these technologies

are uncertain in grid-connected applications. For

some of these technologies these markets are foreign. Efforts on the part of the U.S. Government

to assist in establishing access to markets for new

generating technology equipment in foreign

countries could be very important to the nearterm viability of some of these technologies. Such

efforts might include support for formation of

renewable export trading companies, loan guarantees, information dissemination, and help with

joint venture and licensing applications in foreign

countries.

The pressures of competition from foreign vendors, many of which are heawly supported by

their governments, as well as the current lack of

U.S. demand for some of these new technologies

in grid-connected power generation applications

raises the concern over the continued commitment of U.S. firms to developing these technologies. This concern is heightened by pending

changes in favorable tax treatment for renewable

energy sources. For some domestic firms who are
Ch. 10—Federal Policy Options ● 289

working on technologies such as wind, solar thermal electric, and photovoltaics (at least those

focusing on concentrator technologies), the survival of some domestic firms may be at stake.

They may not be able to or willing to compete

in world markets over the next decade. However,

they may need those markets until their technologies can compete in the U.S. grid-connected

power generation market.

Option A4: Increase resource assessment

efforts for renewable energy resources

In those regions where renewable energy

sources show promise for commercial application, a well-defined resource is essential for

assessing the economics of proposed wind, geothermal, and solar power generating projects and

for CAES projects. For example, there can be a

several hundred percent difference in the energy

generated by the same wind machines using

different distributions of the same annual mean

wind speed; an untested site may require up to

3 years of data to confirm the extent and nature

of the wind resource at that site.

Reliable resource data lessens the uncertainty

in energy production and hence the risk of insufficient project revenues. Some industry observers3 feel that, at least in the case of wind, “knowledge of the wind resource—its location and

intensity—is the cornerstone to the development

of wind energy. "4 Lack of a detailed resource

base is also an important factor in geothermal development and, to a lesser extent, in solar thermal electric and photovoltaic development.

‘f/n,?/ Report ot the W/nci Energ)’ Task Force, u npu bllshedre-

~mrt, oregon Alternate Energy Development Commlsslon, June

1980.

“S. 5adler, et al., 11’lndy LJrrd Owner+ Gum’e (S~lem, OR: Oregon Department ot EnerKy, 1984),

Option A5: Improve collection, distribution,

and analysis of information

A serious disadvantage facing all the developing technologies is the lack of adequate i nformation on the technologies and their markets among

those whose decisions are important to their

commercial deployment—investors, regulators,

the general public and others. s

Non utility market information, in particular, is

generally not available because these markets are

not yet well developed.6 The lack of information

increases the general level of uncertainty and risk,

and favors conventional technologies and markets about which more is known.

Programs designed to deliver accurate and useful information in a timely manner to the relevant individuals and groups would be helpful in

accelerating deployment of the technologies.

Also, efforts to increase the capability to use the

information properly could be effective. Such efforts might include the training of individuals, the

development of appropriate analytical methods,

and acquainting people with the technology

through demonstration projects.7

5Th is IS a common I roped I ment encountered by detelopl ng technologies during the commercial transition, See Arthur D. Little, Inc.,

Barrier~ to lnno~ation in lnciustry: 0~]/mrtunitie~ for Public POIIC y

Changes (Washington, DC: Arthur D, Little, Inc., 1973).

bThe inadequacy of information on nonutlllty markets was pointed

out In: “FERC Wants Cogeneration Tally; Results May Question Central Plant Need, ” E/ectrlc Ufi/fty WeeA, Mar. 18, 1985, p. 3, The

art Icle raises the possibility that the t’ai I u re to adequately consider

non uti Iity power producers may se~ erely distort analyses suc h as

those performed by the Department of Energy. The Energy I ntormation Administration, for example, in Its Annual Energy Out/ook-

/984, does not Include any nonuti Ilty capa( ity In Its calculatlon~

of plant construction through the year 1995.

7

For an i nformatwe discussion of the Importance to pu bl i{ uti 1-

ity commissions of the collection, dlstrlbution, and analysis of ln -

formatlon, see: S, Wiel, Commissioner, Public Service Comrnlsslon

of Nevada, Statement before the Subcommittee on Energy De\ elopment and Applications, Committee on Science and Technology,

House of Representatives, U.S. Congress, Mar. 5, 1985.
290 ● New Electric Power Technologies: Problems and Prospects for the 1990s

GOAL B: ENCOURAGE NONUTILITY ROLE IN COMMERCIALIZING

DEVELOPING TECHNOLOGIES

Option B1: Continue favorable tax policy

The Renewable Energy Tax Credits (RTCs) have

been an important contributor to the Federal policy of supporting the infant renewable energy industry. 8 While the RTCs have been in effect since

1978, they have only been utilized to a significant degree since 1981 for electric power projects

and are only applicable to nonutility facilities. For

wind projects, in particular, the credits seemed

to have spurred development significantly for two

reasons:

1. With the tax credits, projects with design

specifications using current cost and performance technology present competitive

rates of return for prospective investors, particularly in California where State tax credits

and high PURPA avoided cost rates are additional incentives. Even if the design specifications for a prospective project are not

realized, as has been the case for a large

number of first generation wind projects, the

tax benefits alone associated with these

projects, many of which were initiated to test

innovative designs, have been sufficient to

attract considerable investment interest. This

has been particularly true for investors with

income from other investments.

For example, using OTA’s cost and performance estimates (appendix A), the cumulative tax benefits–including accelerated

depreciation allowances (ACRS), Investment

Tax Credits (ITCs), and RTCs–shows that

wind turbines as well as geothermal projects

are attractive investment opportunities under all reasonable cost and performance

scenarios. PVs become competitive under

the “best case” scenario. Some of the de-

‘l The Energy Tax Act ot’ 1978; the long-term ‘‘suppofl of an infant industry” motl~ation for the renewable energy credit was quit e

different from the ~ister tax credit for conservation which was motivated by the short-term objectiie tor encouraging energy conservat ton.

2.

tails of this analysis are illustrated in figure

10-1.9

While the first generation wind prolects in

California generally did not perform well,

they served as the “test bed” for small wind

machines (less than 200 kw) that have not

been the focus of the Federal R&D program.

Indeed, the wind industry is currently moving from these first generation small machines to medium-sized machines (200 to

1,000 kW) as the technology matures.

The effect of the RTCs on internal rates of return for solar, geothermal, and wind projects is

shown in figure 10-1, including the “worst case, ”

“most likely, ” and “best case” cost and performance scenarios defined in chapter 4 and appendix A. It should be noted that special investment

structures such as safe harbor leases or other tax

leveraged vehicles can improve the attractiveness

of the investment considerably by limiting risk

and/or offering substantial tax benefits (as discussed in chapter 8). Such mechanisms have become more the rule than the exception in the industry in the last several years. As renewable

technology matures, the quality of investments

will improve regardless of the tax implications,

if avoided cost rates remain sufficient as shown

in the figure. Figure 10-2 shows the breakeven

avoided cost (buy-back) rates necessary to yield

a 15 percent real internal rate of return.

The role of the RTC in accelerating commercial development seems to have changed from

its original design, at least for the technologies

considered in this assessment. The original Federal policy was to provide direct research support to develop the technology and the RTC to

accelerate commercial deployment, With decreased Federal R&D support, the RTC appears

9,41s0 see P. Blair, testimony presented In hearings held by Subcommittee on Energy and Agricultural Taxation, Committee on Finance, U.S. Senate, June 21, 1985,
Ch. 10—Federal Policy Options ● 291

Figure 10-1 .—Tax Incentives for New Electric Generating Technologies:

Cumulative Effect on Real Internal Rate of Returna

No tax incentives

— —

Geotherma l Phot o Win d Sola r Fue l Combustion Atmost)herlc

to be supporting research and development in

the field as well as commercial development. At

the same time, there are instances where the RTC

has prompted installation of inferior technology

that has little possibility of commercial success.

These instances have brought about criticism

of the RTCs, particularly for wind, that has resulted in proposals for an alternative PTC that

would award the credit based on energy generated rather than the initial investment. These

critics have argued that support of innovative designs is not the intent of the credits. Indeed, a

PTC would discourage investment primarily

oriented toward exploiting tax benefits. Moreover, it would ensure that whatever investments

are made would be done so for energy production purposes. A PTC, however, may be difficult

to monitor, particularly in non-grid-connected applications. In addition, while PTCs may ensure

better performance, it may slow technology development and commercialization since investors

would be less likely to test innovative designs.

Another implication of the PTC, compared with

the RTC, is that it favors technologies in base load

cycle applications (with higher capacity factors)

such as geothermal and penalizes those in intermediate and peaking applications such as wind

or solar. The trade-offs between PTCs and RTCS

are illustrated in table 10-2.

The evidence supporting the relative effectiveness of tax incentives for stimulating investment

i n the electric utility industry itself is not as compelling as the nonutility case. For example, the

decrease in the Ievelized per kilowatt-hour busbar cost for the renewable technologies considered in OTA’s assessment, with a 15 percent tax

credit over and above the existing tax benefits

currently afforded to utilities, is less than 10 percent for all cases. The relative lower effectiveness

is mostly explained by utility accounting practices
292 ● New Electric Power Technologies: Problems and Prospects for the 1990s

x

Wind Photovoltaics

Fluid

b e d

b

Solar Geothermal Fuel Combustio n

thermal cell s

b

turbin e

b

which spread the benefits of the tax credit over

the life of the facility rather than offering a substantial front-end incentive. For electric utilities,

other actions than tax preferences (discussed

later) may be more effective in stimulating development of new technology.

Since the early 1970s, the Federal policy for

encouraging the development of a renewable

energy industry centered on an active R&D program to develop the technology (particularly active during the decade of the 1970s) coupled with

the tax credits (since the early 1980s) to spur commercial applications. This analysis shows that with

declining direct support from Federal RD&D programs, the pace of renewable technology development would slow considerably without the

RTC. Indeed, without the credits, only the most

mature renewable technologies at the best resource locations would likely be deployed through

the 1990s. Even with the tax credits, the application of the renewable technologies considered

here will be highly regionally dependent in the

1990s (see chapter 7). In regions where the wind,

solar, and geothermal resources are of high quality, though, the renewable could be important

contributors to both new and replacement generating capacity.

Many industry observers argue that a gradual

phasing out of the RTC rather than their currently

scheduled termination at the end of 1985 would

give the renewable power industry a better

chance to develop technology to the point where

it might compete effectively in the 1990s. in particular, a 3-year phase-out of the credit for wind

and geothermal could benefit those technologies

considerably and increase deployment in the
Ch. 10—Federal Policy Options

Table 10-2.—Alternative Tax Incentives: Cumulative Effect on Real Internal Rate of Return

● 2 9 3

Real internal rate of return (percent)

Wind

turbines

4.1 “/0

19.1

9.9

14.9

16.8

17.9

19,0

11.6

15.5

14.5

19.1

5.9

5.1

11 .70/0

28.4

18.9

24.6

26.8

27.8

28.8

19.7

24.7

22.7

28.4

14.7

13.2

16.6 ”/0

35.5

25.2

31.9

34.2

35.2

36.4

25.6

31.6

28.9

35.5

20.5

18.6

Solar

thermal

0.0 ’70

0.0

0.0

0.0

0.1

0.1

0.2

0.0

0.0

0.0

0.0

0.0

0.0

O.OO/O

9.5

1.8

6.1

7.5

8.2

9.1

2.1

6.2

4.0

9.5

0.0

0.0

1 .7 ”/0

14“.4

6.6

10.2

11.8

12.7

13.8

6.7

11.2

8.7

14.4

3.7

3.3

16.90/o

24.3

24.3

29.8

31.7

32.6

33.7

24.6

29.6

27.3

32.9

20.2

18.6

20.40/o

28.6

28.6

34.9

37.0

37.9

38.8

29.1

34.4

32.2

37.9

24.1

22.3

24.8

33.9

33.9

41.0

43.2

44.3

44.7

34.7

40.2

38.1

43.9

28.9

26.7
294 . New Electric Power Technologies: Problems and Prospects for the 1990s

1990s. For solar thermal and photovoltaics, however, a 5-year or more extension or gradual

phase-out would more likely be required.

Option B2: Improve nonuti[ity access to

transmission capacity

Some non utility power producers argue that if

proposed nonutility generating projects were included more explicitly in utility resource planning

considerations, such projects might be better

aligned with proposed transmission expansion

and reconfiguration plans. Coordination of nonutility generation with utility-owned generation

must be balanced against utility concerns about

control of generating sources for dispatching and

maintenance of system reliability.

Nonutility generating sources might also be

more prevalent if power from projects located in

one utility service territory could be sent to

another utility service territory where, for example, avoided cost payments were higher. Such

“wheeling” of power, however, requires transmission capacity to be committed to the project

in the former service territory. At low penetration levels of nonutility generating sources wheeling is not likely to be a serious problem. Some

State utility commissions have already made

wheeling mandatory. At higher levels of penetration, however, utilities might be forced to reconfigure or upgrade existing transmission capabilities to accommodate wheeling and the question

of allocation of costs for upgrades becomes an

issue.

If the objective is to increase non utility power

projects employing new electric generating technologies, revisions to PURPA to modify the

wheeling provisions originally enacted might be

an effective way to encourage development of

such projects. Such modifications could give

these producers access to utility markets beyond

the service territory in which the project is sited

without negotiating complicated individualized

wheeling agreements with the local utility. Such

modifications might also extend to obligations on

the part of the utility in which a project is sited

to negotiate with prospective non utility producers on the issue of transmission access.

Modifications to PURPA to broaden the wheeling provisions, however, would have to be carefully constructed since the implications of such

modifications vary greatly from region to region

as well as from utility to utility within regions. Utility concerns about efficiency and control over the

transmission and distribution system must be

carefully addressed in any proposed modificat ions.

Finally, streamlining of Federal licensing and

permitting procedures where such procedures

apply to transmission projects—i,e., on Federal

lands–could reduce the time it takes for PURPAqualifying facilities to gain access to transmission

capacity.

Option B3: Develop clearly defined and/or

preferential avoided energy cost

calculations under PURPA

In chapter 8 the avoided energy (and capacity) cost that utilities pay to non utility producers

for generated power was identified as one of the

key factors affecting the profitability of nonutility power projects. Investors in nonutility power

projects seek secure, long-term energy credit and

capacity payment agreements with utilities to ensure a stable revenue stream for the project. In

States encouraging non utility projects, e.g., California, standard agreements have evolved that are

Ievelized pricing contracts or fixed price scheduIes negotiated for the duration of the proposed

projects. Such standard contracts have greatly increased nonutility generating activity in these

States and could provide a model for other States.

In other States, public utility commissions have

mandated minimum avoided cost rates—e. g.,

New York and lowa have minimum rate of 6 and

6.5 cents/kWh, respectively, for small power producers which are generally above the prevailing

avoided cost of the utilities. Attempts to remove

such rates through the courts have to date been

unsuccessful, although some appeals are still

pending. If the courts interpret the primary purpose of PURPA’s avoided cost provisions as encouraging small power production, then adoption of such mandatory rates could serve to

accelerate small power production substantially
Ch. 10—Federa/ Policy Options ● 295

in States where these rates exist. If, on the other

hand, the courts rule that implementation of

PURPA’s avoided cost provisions’ must consider

immediate rate savings for a utility’s customers,

the future of such rates is less clear since public

utility commissions will be obligated to strike a

balance between customer savings and incentives

for small power producers. The outcome is of

considerable importance to the rate of commercial deployment of new generating technologies.

Legislative action to co-opt the courts’ decisions

in this area could serve to reduce uncertainty,

and in the process, accelerate deployment of new

generating technologies that would qualify for

mandatory rates where they exist.

Option B4: Standardize interconnection

requirements

As the penetration of nonutility owned and

operated dispersed generating sources (DSGs) increases in U.S. electric power systems, the implications for system operation, performance, and

reliability are receiving increased attention by the

industry. For the most part, however, the technical aspects of interconnection and integration

with the grid are fairly well understood and most

utilities feel that the technical problems can be

resolved with little difficulty. State-of-the-art

power conditioners are expected to alleviate utility concerns about the quality of interconnection

subsystems.

Prior to 1983, most interconnection configurations were custom-fitted and no standardized

guidelines existed. Since 1983, however, the

number of applications from DSGS has increased

and, as a result, more utilities are developing such

guidelines. These individual utility guidelines vary

widely, but a number of national “model” guidelines are being developed by standard-setting

committees (discussed in chapter 6), although

none has yet released final versions. Indeed, these

groups are expected to continue to revise draft

standards. Even if a consensus standard does

emerge, however, widespread utility endorsement is still uncertain. As a result, DSG customers are likely to face different and sometimes conflicting interconnection equipment standards well

into the 1990s. This lack of standardization may

hamper both the use of DSGs as well as the manufacture of standardized interconnection equipment. Development of a set of national standards

for interconnection that could be flexibly interpreted for individual utility circumstances could

accelerate deployment of non utility power projects in many regions.

GOAL C: ENCOURAGE INCREASED UTILITY INVOLVEMENT

IN DEVELOPING TECHNOLOGIES

Electric utilities on average currently spend less

than 1 percent of gross revenues on R&D, considerably less than most other capital-intensive

industries. Traditionally, the response to this concern is that equipment manufacturers and vendors are carrying the principal burden of R&D for

the power industry. But, with the decline in new

equipment orders in recent years, manufacturers

are less likely to commit R&D to new products

for which strong markets are not assured. As a

result, if R&D activity in new generating technologies is to continue, at least a portion of the burden may fall on the utilities themselves. With

environmental and other pressures on utilities to

consider new technologies, how public utility

commissions treat cost of RD&D and of early

commercial applications is a pivotal issue. The

following are alternative strategies aimed at improving this regulatory environment.

Option Cl: Increase utility and public utility

commission support of RD&D activities

increased RD&D activity in new generating

technologies will require utilities and utility commissions to agree on appropriate mechanisms for

supporting such activities. Direct support from

the rate base for research activities, such as the

allowance for contributions to the Electric Power

Research Institute while desirable and important,

38-743 0 - 85 - 11
296 . New Electric Power Technologies: Problems and Prospects for the 1990s

is not now at a level that would cause significant

deployment of these technologies by the 1990s.

Allowance of or even encouragement of a higher

percentage of annual revenues to support RD&D

activities could be an important step in accelerating commercial applications of new technologies.

Even larger RD&D commitments, however, that

involve large capital investments for major demonstration facilities may only be justified by a

sharing of the risk between ratepayers, stockholders and, if other utilities would benefit substantially, taxpayers. One mechanism for supporting

such projects is to finance a portion of proposed

project with an equity contribution from the utility and the rest through a "ratepayer loan”

granted by the public utility commission. The

public utility commission might argue that a candidate demonstration project is too risky for the

ratepayer to be subsidizing, particularly if other

utilities could benefit substantially from the outcome, but are not contributing to the demonstration, i.e., sharing in the risk. In such cases, there

could be a Federal role. For example, the ratepayer contribution to the demonstration could

be underwritten by a Federal loan guarantee, thus

transferring at least a portion of the investment

risk from the ratepayer to the taxpayer.

Finally, since high interest rates and high capital costs have discouraged utilities from making

investments in new generating capacity, a wide

variety of regulatory changes have been suggested that would make it easier to resume construction programs. These include:

1.

2.

3.

rate base treatment of utility assets that take

inflation into account—sometimes called

“trending” the rate base; l”

allowance of some or all construction work

in progress (CWIP) to be included in the rate

base; and

adoption of real rates of return on equity

commensurate with the actual investment

risk.

l~Trended rate base proposals are discussed in U.S. Congress,

Office of Technology Assessment, Nuclear Power in an Age of Uncertainty (Washington, DC: U.S. Government Printing Office, February 1984), OTA-E-2 16.

These options are all aimed at evening out rate

increases (prevention of so called “rate shock”)

and providing more financial stability for utilities.

They would, however, reduce the attractiveness

of smaller, modular generating technologies relative to larger units since the options transfer some

of the investment risk from the stockholder to the

ratepayer. While all capital projects—large or

small—wou Id benefit by this risk transfer in terms

of lower capital costs, the larger the project the

greater the net savings to the utility. Whether this

is sufficient to outweigh the benefits of smaller

units in a period of uncertain demand growth

would depend on the particular utility and its

longer term outlook.

Option C2: Promote involvement of utility

subsidiaries in new technology

development

Some electric utilities are using (and many are

considering) the use of regulated or unregulated

affiliated interests (corporate subsidiaries or other

holding company structures) to initiate new technology projects where they have identified a

project as an attractive investment opportunity

but riskier than more traditional utility investments, i.e., the utility’s allowed rate of return is

not commensurate with the project’s perceived

financial risk. In practice, this usually amounts

to a situation where the public utility commission agrees to permit a project to proceed but

does not give assurances that the entire final

project cost will be permitted to enter the rate

base.

Using an unregulated affiliated interest to carry

out new technology projects allows utilities to finance such projects with sources from the capital markets since higher rates of return can be

offered to attract capital. It is also one example

of how utilities are diversifying into other lines

of business. As discussed in chapter 3, electric

utility diversification activities are already widespread and growing. Most of these activities (74

percent according to a recent Edison Electric institute survey) involve fuel exploration and development, real estate, energy conservation services, fuel transportation, district heating and

cogeneration, and appliance sales. A small per-
Ch. 10—Federa/ Policy Options ● 297

centage (6 percent) do, however, involve alternative technology projects. Generally diversification

1.

2.

3.

4.

has led to:

A higher return for investors, increase in

price-earnings ratio and, as a result, an improved standing in the financial community

and a lowering in the cost of capital. Diversified utilities have consistently outperformed

nondiversified utilities in the stock market.

More efficient use of company assets including labor, customer base, computational faciIities, and services.

Diversification, protection, and stable pricing of fuel supplies through diversification

into fuel acquisition activities and alternative

technology projects.

An ability to take advantage of favorable tax

benefits not afforded to-regulated public

utiIities.

The problems of potential cross-subsidization

of unregulated projects from regulated interests

has to be monitored closely by public utility commissions as they allow utilities to become involved in diversification activities.

Option C3: Resolve siting and permitting

questions for developing technologies

To date, the rate of deployment of some new

generating technologies in both utility and nonutility applications is being lowered because leadtimes being experienced by early commercial

projects have been longer than anticipated, partially due to the time required for regulatory review. As reguIatory agencies become more familiar with the technologies and their environmental

impacts become clearer, the time to complete

such reviews could decrease, although as noted

earlier this is by no means guaranteed. Action to

educate reguIators and all others who would ultimately be affected by eventual deployment of

the technology i n the course of demonstrations

might reduce the lead-times of early commercial

units. For example, close coordination with State

and Federal regulatory agencies as well as public utility commissions during demonstration projects shouId be a major feature of these projects.

Finally, as noted for non utility projects discussed

earlier, streamlining of Federal licensing and permitting procedures where such procedures apply to transmission projects could reduce leadtimes considerably.

Option C4: Other legislative initiatives:

PIFUA, PURPA, and deregulation

In addition to maintaining a continued presence in research, development, and demonstration as well as implementing environmental

policy affecting power generation, e.g., administration of the Clean Air Act, several possible Federal policy decisions affecting electric utilities

could influence the rate of commercial development of new generating technologies over the

next 10 to 15 years. These include removal of the

Powerplant and Industrial Fuel Use Act (PIFUA)

restrictions on the use of natural gas, extension

of complete PURPA Section 210 benefits to electric utilities, and increased steps toward deregulation of power generation and bulk power transfers. All of these actions could increase the rate

of deployment of developing generating technologies, but their other effects have to be carefully

reviewed before and during implementation.

If increased availability of natural gas should

occur, a repeal of PIFUA or, at a minimum, a

more liberal policy on granting exemptions in

power generation applications could, in addition

to providing more short-term fuel flexibility for

many utilities, be a step toward accelerated deployment of “clean coal” technologies such as

the IGCC since they can use natural gas as an

interim fuel. In addition, some technologies such

as CAES and some solar thermal electric units use

natural gas as a supplementary fuel and may or

may not fall within the applicable size limits established by PIFUA automatically exempting such

installations from the Act. ’1 Where exemptions

are required, their acquisition introduces delays

or even the possibility that approval might be

denied.

Permitting utilities to participate more fully in

the PURPA Section 210 benefits of receiving

avoided cost in small power production would

most likely result in increased deployment of

I I Cha nges i n PI F(JA wou Id also affect non uti lity producers, as

discussed in ch. 9.
298 • New Electric Power Technologies: Problems and Prospects for the 1990s

small modular power generating technologies,

particularly cogeneration.12 For example, utilities

are currently Iimited to less than sO percent participation in PURPA qualifying cogeneration facilities. In addition, ratepayers would likely see

more of the cost savings resuking from cogeneration if utilities were allowed full PURPA benefits. Currently, ratepayers see only the difference,

if any, between the avoided cost and the rate negotiated between the cogenerator and the utility. The owner of the qualifying facility retains the

rest of the excess over the cost of generating the

power. Similar benefits would accrue to the ratepayer by utility participation in PURPA for other

types of generating technologies to the extent that

costs of power production fall below avoided

costs.

In relaxing this limitation, potential problems

requiring attention include ensuring that utilities

do not show undue preference for utility-initiated

projects in such areas as access to transmission

or capacity payments. Moreover, project accounting would probably need to be more segregated from utility operations than non-PURPA

qualifying projects in order to ensure that crosssubsidization does not occur that would make

utility-initiated projects appear more profitable

at the expense of the ratepayer. These concerns

can be allayed through carefully drafted legislation or regulatiorls, or through careful State review of utility ownership schemes.

It should be noted, though, that granting of full

PURPA benefits to utilities would be viewed with

disfavor by most nonutility owners. In particular, allowance of such benefits likely would cause

avoided costs to be determined by the cogeneration unit or alternative generation technology

itself rather than the fuel and/or capital costs of

I ZFor a more complete discussion, see U.S. Congress, Office of

Technology Assessment, Industrial and Commercial Cogeneration

(Washington, DC: U.S. Government Printing Office, February 1983),

OTA-E-1 92, pp. 20ff.

a conventional plant that would be avoided by

a utility as is currently the case. Unless prospective nonutility owners could produce power still

cheaper than these newly defined avoided costs,

they obviously would not enter into any projects.

This would clearly reduce the number of cogeneration and alternative technology power projects

started by nonutility investors. This drop-off, however, might be more than compensated by expanded utility involvement. It is also possible that

potential cogeneration and alternative technology sites may go unfulfilled if utilities were allowed full PURPA benefits, since many of these

site owners—industrial firms and large buildi rigs-may not want utility control over facilities

on their site. Here, too, careful establishment of

reguIations or contracts couId protect all parties

of interest.

Finally, as perhaps a logical next step to PURPA,

a number of proposals for deregulation of the

electric power business have been proposed in

recent years, ranging from deregulation of bulk

power transfers among utilities, to deregulation

of generation, to complete deregulation of the

industry. While OTA has not examined the implications of alternative deregulation proposals

on the rate of commercial development of new

generating technologies, such proposals would

almost certainly have an impact. The experiences

of PURPA and the FERC Bulk Power Market Experiments will be important barometers for assessing the future prospects and desirability of

deregulating U.S. electric power generation. It

is important to note that allowance of full PURPA

benefits for utilities would be a significant step

toward deregulation of electric power generation,

at least for smaller generation units.

1 jThis experiment deregulates wholesale bulk power transactions

among four utilities in the Southwest; see “Opinion and Order Finding Experimental Rate To Be Just and Reasonable and Accepting

Rate for Filing, ” Federal Energy Regulatory Commission, Opinion

No. 203, December 1983.
Ch. 10—Federal Policy Options ● 299

GOAL D: RESOLVE CONCERNS REGARDING IMPACT

OF DECENTRALIZED GENERATING SOURCES ON

POWER SYSTEM OPERATION

In recent years, utilities that interconnect with

non utility power producers operating DSGs are

concerned about the potential impact of increased penetration of DSGs on overall power

quality available in the utility grid as well as

proper metering, effect on system dispatching

and control, short-term transmission and distribution operations, and long-term capacity planning.

As utilities gain experience with DSGs on their

own systems, these concerns are being resolved.

However, many utilities are only beginning to

gain this experience; the following options are

aimed at addressing such concerns.

Option Dl: Increase research on impacts at

varying levels of penetration

While most of the problems associated with incorporating DSGs into the utility grid appear to

have technical solutions, the cost and complexity of these solutions may vary considerably

across utility systems. In particular, one concern

is the potential impact on power quality of high

levels of penetration of DSGs on individual distribution feeders. Other issues include protective

equipment performance, appropriate safety procedures, system control at the distribution level,

and impact on system generation dispatching procedures. Most research to date indicates that at

low levels of DSG penetration–up to 5 percent

of total installed capacity—there are no ill effects

on system operations as measured by indicators

such as the area control error (see chapter 6). Beyond a 5 percent penetration, however, there is

less agreement among researchers. Research on

the conditions under which DSGs would significantly affect system operation over a wide range

of utility circumstances would improve utility

engineers’ ability to assemble appropriate and

cost-effective interconnection configurations and

control procedures for mitigating potential impacts. Such research could help resolve concerns

and serve as a basis for implementing appropriate technology and procedures to accommodate

increased penetration of DSGs.

Option D2: Improve procedures for

incorporating nonutility generation and

load management in economic dispatch

strategies and system planning

Many of the problems associated with incorporating DSGs into the utility grid stem from

modifications to the grid necessary to accommodate electric generation at the distribution level.

Management of “two-way” power flows at the

distribution level has added a new level of complexity. Some utilities have developed strategies

for incorporating DSGs into economic dispatch

strategies but control mechanisms for coordinating a large number of DSGs are generally not

available. As the number of DSGs on a utility system increases, the complexity of this coordination becomes more difficult and the need to automate such procedures becomes more important.

Similarly, some recent research sponsored by

the Electric Power Research lnstitute14 indicates

that conventional utility planning models may

overstate the reliability benefits of load control.

Developing load management systems.15 attempt

to better integrate load management into hourly

scheduling of resources in energy control centers.

As a result, these new systems also provide better control over load management resources and,

hence, more reliability benefits.

I JElectric Power Research Institute (EPRI ), Eft’ecf Oi LOJd Mamgernent on Re/labi/ity (Palo Alto, CA: EPRI, july 1984), EPRI EA-3575.

I $uch as B. F. Hastings, “The Detroit Edison Second Generation

Load Management System, ” Proceecilngs of the Institute ot [lectrlcal and Electronm Engineers (IEEE) Summer Po\\er Aleeting, Paper

No. 84-SM-559-1 , jU!Y 15-20, 1984 .
Appendix A

Cost and Performance Tables
Appendix A

Cost and Performance Tables

Table A-1:

Table A-2:

Table A-3:

Table A-4:

Table A-5:

Table A-6:

Table A-7:

Table A-8:

Table A-9:

Table

De fin

Photovoltaics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Solar Thermal Electric . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Wind Turbines . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Geothermal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Atmospheric Fluidized-Bed Combustion. . . . . . . . . . . . . . . . . . . . . . .

Integrated Gasification/Combined-Cycle . . . . . . . . . . . . . . . . . . . . . . .

Fuel Cells . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Compressed Air Energy Storage . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Batteries. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

A-10: Summary Tables . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

tions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Page

304

306

308

309

311

312

313

315

316

317

319
304 ● New Electric Power Technologies: Problems and Prospects for the 1990s

Table A-l.—Cost and Performance of Central Station Photovoltaics

May 1985 technology status Flat-plate Concentrator

Commercial

9.5MWe

general characteristics

1995

20-4,730 MWe2

10 MWe4

2years 5

60-320 acres8

very Iittleg

performance parameters

90-100% 10
App. A—Cost and Performance Tables ● 305

Array Rehablhty A Compdat!on of Sarrdia Corrtr{buted Papers to the 17th IEEE Photovoltaic

Spec(a/(sts Conference Or/ando FL May /.4 f984 Edward L Burgess (ed I (Albuquerque NM

Sandia Nahonal Laboratories 1984) SAND84-1167c pp 94100

“Capacity factor IS dehned as the rallo of actual energy produced by the plant In a year to !he

energy the plant could have generated If It operated conhnuously al Its ra!ed power The capacity

factor IS a funcllon of Ioca!ion The three figures represent Boston Mlaml and Albuquerque The

high values for (he fixed flat-plate arrays are taken from Taylor op cIt 1983 pp 4-6, the high

values for tracking-arrays were found by enhancing the fixed array data by 40 percent as sug.

gesfed by R E L Tolbert and J C Arnett ARCO Solar Design Installation and Performance of

ARCO Solar Photovoltalc Power Plants Proceedings of 17fh /EEE Pho/ovo/fa/cs Spectahs!s Confererrce Ktssimmee, FL May 1984 p 1149 and the high concentrator values were compiled

from tables from the followlng 1 ) J W Deane and J B Gresham Science Applications Inc Pholovo/falc Reqwremerrls Estimaf/orr-A S~mp/~f[ed Method (Palo Alto, CA Elecfrlc Power Research

Instltule February 1983 I EPRI AP.2475 2) Gary J Jones Superwsor, PV Systems Development

DIvIsIon Sandla Nahonal Laboratories A Comparison of Concentrating CoHecfors to Tracking

Flat Panels A Corrrpda(lon of Sar?dla Corffnbuled Papers 10 the 17th /EEE Phofovo/fa/c Specla/@

Conference Or/ando FL May 1-4 1984 Edward L Burgess (ed 1 (Albuquerque, NM and Lwermore CA Sand!a Nat{onal Laboratories June 1984) SAN D84-t 167c Pp 8-13

In all cases the low capacity factors arbitrarily are set 5 percentage pofnts below the high value

10 reflect the effects of low operatlrrg avallablhty dirt and other factors of her than long-term cell

degradation on capacity factors

‘zLlfetlme IS defined as the period In whtch the energy output of a plant drops by 20 percent

Ronald G Ross Jr Manager Reliablhty and Engmeerlng Sciences Flat-plate Solar Array Protect

Jet Propulsion Laboratory mterwew wlfh OTA staff, Aug 22 1984

I ]The Iow value IS an extrapolation of the performance of equl Pment which has already been

In the field for several years Ronald G Ross Jr op cIt 1984 The high value represents DOE

goals U S Department of Energy (DOE), Fwe Year Research P/an 1984-1988 (Washington DC

DOE May 1983)

“These figures are based on ad/usted estimates that modules would have efhclencles of 11

to 18 percent The 11 percent value IS from a currently commercial module Dan ArvIzu and Michael

Edenburn Sandla Nattonal Laboratories ArI Overwew o! Concentrator Technology paper presented at the Annual Meeting of the American Soc!ety of Mechanical Eng!neers New Orleans LA

December 1984 The 18 percent value represents a module efftclency based on the best laboratory

slllcon cell Taylor op clt 1983 The module efflclencles shown tn the table result from adlustmg the 1 ? to 18 percent range to reflect nommal peak operating condlttons at each site The methodology used IS described tn app B of an Electrlc Power Research Inst!tute report Taylor op

clf 198 3

“These figures are based on ad/usted esflmales that modules would have efflclenc!es of 16

fo 25 percent The 16 percent value IS from a currently commercial module Arwzu and Edenburn,

op clt 1984 The 25 percent figure IS Sandla’s estimate for the best commercial GaAs module

In the 1990s The module efflc!enc{es shown In the table result from adlustmg the f 6 to 25 per.

cent range fo reflect nominal peak operating condihons at each site The methodology used IS

described In app B of Electrlc Power Research Institute Taylor op ctt 1983

~#The Iow end IS a Bechfel prediction Bechtel Group l?rotovo/falc 8a/artCe-Of-SyStem Assess.

n?errl OP c!t 1982 and the htgh end IS a Sandla estimate from Gary J Jones, Superwsor PV

Systems Development Dwlslon Sandla National Laboratories Albuquerque NM Interwew with

OTA Staff August 8 1984

“The low end IS a Bechtel prediction Bechtel Group Photovo/(afc Ba/ance-ot-Sysfem Assessment op cd 1982 and the high end IS a Sandla esttmate Gary J Jones, op cit 1984

~~plant efficiency IS the product of the module and the BOS efficiencies

19These cost figures do not Include overhead Contingency Or owner’s costs

ZOThe low figure represents industry Charles F Gay Vice Pres~dent. Research & DeveloPrnent

ARCO Solar Inc Intewew with OTA staff Auqust 10 1984 Electrlc Power Research Institute

Roger Taylor Photovo/talc Systems Assessment An /nlegrafed Perspectwe OP CI! 1983 and

the Department of Energy, U S DOE Fwe Year Research P/an /984- 1988 OP clt 1983 goals

The high figure represents OTA eshmates of costs ot current commerlal Ihnes If they were run

at larger volumes of producflon and used less labor

“The low end represents Department of Energy U S OOE Fwe Year Research P/arr. 1984-1988

op cit f983, and Sandla Dan ArvIzu and Mchael Edenburn, An Ow?cwew of Concentrator Technology op c!t 1984 goals The high figure IS the cost of the best currently commercial module

If It were produced at 10.20 MW/yr This IS based on Information from 1 ) Juns Berzms Intersol

Power Corp Interwew wlfh OTA staff August 10 1984 and 2) Dan Arwzu and Michael Edenburn, An (lverwew o! Corrcentrator Tecfrno/ogy, op clt 1984

‘

] Bechtel Group Photovo/falc Ba/arrce-of-System Assessment OP clt 1982

Z] photovoltalc Sylems ‘EPR/ Journa/ VOI 9 NO 6 July/August 1984 PP 4 3

-

4 5

t~Bechtel Group Pholovo/lalc 6’a/ance-of-Sys(em Assessnrerrf oP clt 1982

“ ‘Photovoltalc Sytems EPR/ Jouma/ op cIt 198 4

Z6Bechtel Group, Phofovo/L?/c 8a/ance-of-System ASSeSsmeflf oP cf! 1982

‘T’ Photovoltalc Sylems EPR/ Journa/ op CI1 198 4

l~Bech[e{ Group photovo/fafc 8a/ance-of-System Assessmem oP cl! 1982

‘glbld

30 The !Otaj capital cost IS 91ven by

CC%l - nwule w! . 005 &ted cos1 m.m.le nfflc en. ) . BCS et f!clenc! . lr~oldr~f . BOSIwwr I :0s,s

Nominal peak Insolation and efficiency vary In different Iocatlons so that the capital costs of

a gwen system WIII vary depending on where it IS shed The values gwen represent Capital costs

at Idea/ sites In general these costs WIII be h!gher From Roger W Taylor Photovoltam Systems

Assessment An /nfegrafed Perspechve, op clt 1984 the nominal peak Insolahon In several

cltles IS

rofa k* s+- -I , w Dare] 3 ,Ocf in SQ m {0 ?“, 2(.

AI LwQ,wQ,? - WL c 881

M,am D 821 0 E34

kxlo” 0676 c 521

Note The total cost figures are rounded to the nearest Integral multlple of a thousand

3~The O&M cost range used here IS $2 00 to $2 50/square meter per year This IS based on

estimates made In the following 1) Jet Propulsion Laboratory ‘ ‘Summary of Session VI on Array

Maintenance Issue, ” Proceedings of the F/at-P/xc So/ar Array Pro/ect Research Forum on the

Dwgn of F/at-Plate Phofovo/fa/c Arrays for Centra/ StatIons (Pasadena CA Jet Propulsion Laboratory

1984) Dec 5-8, 1983, Sacramento, CA DOE/JPL-1012-98 pp 301-304 2) P K Henry ‘Econom!c Imphcatlons of Operation and Maintenance “ Proceedings of the F/at-P/afe So/ar Array Pro/eel

Research Forum on the Desrgrr of F/af-P/ate Photovo/ta/c Arrays for Centra/ Sfat(orrs op ctt pp

315-316

IZOTA Calculation The high estimate IS based on a system efficiency Of O 138 lnSo~atJOn of O 676

kWe/square meter, capacity fac!or of O 2 and annual O&M costs of $2 50/square meter The

low estimate IS based on a system efficiency of O 14, msolatlon of O 998 kWe/square reeler ca.

pacify factor of O 3 and annual O&M costs of $2 00/square meter

130TA calculation The high estimate IS based on a system efficiency of O 08, Insolation of O 676

kWe/square meter, capacNy factor of O 3, and annual O&M costs of $2 50/square meter The

low estimate IS based on a system efficiency of O 14 msolatlon of O 998 kWe/square meter capacNy factor of O 4, and annual O&M costs of $2 00/square meter

340TA Calculation The high estimate IS based on a system efficiency of O 12 Insolation of O 521

kWe/square meter capacly factor of O 2 and annual O&M costs of $2 50/square meter The

low estlmale IS based on a system efficiency of O 20, Insolation of O 881 kWe/square meter capacity factor of O 35 and annual O&M costs of $2 00/square meter
306 ● New Electric Power Technologies: Problems and Prospects for the 1990s

‘This Includes Ihree 25 kWe parabohc dish umls

Weploymenl scenanos depend heawly on whether or not the currently prowded Renewable Energy

Tax Credit IS extended beyond the end of 1985, and whether the federal government subsidizes

mstallattons m any other way The low scenario assumes that the only addltlons to currently installed capauty will be 1 ) two 25 kWe parabohc dish mstallahons now being constructed under

the McDonnell Douglas Astronautics Co s Dish/SIWmg Program 2) four additional parabohc dish

mstallahons expected under the McDonnell Douglas Astronautics Co ‘s Dish/Stwhng Program 3)

100 kWe at the federally sponsored Osage City, KS, Small Community Experiment #1, and 4) 100

kWe af the federally sponsored Molokal, Hl, demonstration project Under favorable condlhons

(e g with an exfenslon of the RTC), however hundreds of MWe may be Installed by 1995 see

N[na Markov, ‘‘Exclhng Developments Reflect Bright Future, Rerrewab/e Errergy News, VOI 7,

No 2 May 1984, pp 8-12 An upper Iimlt of 200 MWe WIII be used here, the medtum deployment

scenano WIII IS half that figure or 100 MWe

‘Based on Advanco Corp ‘s Vanguard I module, at dtrect msolatlon levels of 1,000 watts/square

meter, ambient alr temperatures of 28 C, wmd speed of 22 m/s (5mph) see Byron J Washom

et al Vanguard/ .So/ar Parabo/lc hh-.sf~rhng Engine Modu/e (Palm Springs CA Advanco Corp

1984), final report summary of work performed under Department of Energy cooperahve agreement DE-FC04-82AL16333, May 28, 1982 -Sept 30, 1984, DOE. AL-16333-2 (84. ADV-5) p 142

4

And design and 1 year of construchon

‘Ibid Based on SIX modules per acre

‘Ibid

‘figure for mdwldual module avatlablhty Based on informahon prowded by 1 ) OTA contractor

N Hmsey Gibbs & HIII Inc mtervlews with James E Rogan, Manager Market Development

McDonnell Douglas Astronautics Corp July 16 and Aug 13, f984 2) Byron J Washom, Presl.

dent, Advanco Corp personal correspondence with OTA staff, Nov 9 1984 3) Advanco Corp

Proposa/ fo (fre U S DOE Re/a(mg 10 the Srna// Conrrrwrv(y So/ar Expervnenf af Mo/oka( Hawall

(Palm Springs, CA Advance, 1984)

‘The range provtded here IS Idenllcal to that used for fhe photovoltalc concentrator modules

See Footnote 11 of the photovollalcs cost and performance table (table A-t) for an explanation

of the capacity factor used there WNhln this range fall estimates from the following sources 1 )

James H Nourse Branch Manager McDonnell Douglas Corp personal correspondence with OTA

staff, Nov 1 t 984, 2) Byron J Washom, President, Advanco Corp personal correspondence

with OTA staff, Nov 9 1984 Washom mdlcated that a faclltty located at Barstow CA, would

have an annual capacity factor of 257 percent, 3) Byron J Washom, et al Vanguard / So/ar

Parabohc Wr-Sf/r/mg Engine Modu/e op clt , 1984, 4) Tony K Fung, Semor Research Engineer

Southern Cahfornta Edison comments on OTA draft report, Aprd 1985

‘OTA contractor N Hlnsey, Gibbs & HIII, Inc mlervlews wl!h James E Rogan op ctt 1984

‘OWashom op clt Nov 9 1984 Annual average efficiency at Barstow CA, would be about

23 percent

I ~ Based on Information provided by 1 ) OTA contractor N Hmsey, Gibbs & HIII, Inc lnte~lews

with Don H Ross, Director, Energy Systems Center, Sanders Associates, Inc July 1 t and 16,

1984 2) OTA contractor N Hlnsey, Gibbs & HIII, Inc Interviews with James E Rogan, op cd

1984 3) James H Nourse, Branch Manager, McDonnell Douglas Corp personal correspondence

with OTA staff, Nov 1, 1984 4) Byron J Wasfwm, Presldenl, Advancu Corp personal correspondence wtth OTA staff, Nov 9, t984

Advanco reportedly estimates that mass produced Stlrhng/dish umts would cost approximately

$2,300/kWe see ‘SCE’S ‘A/R’ Program Rediscovers a Solar Thermal Power Technology –’The

Parabolic Olsh ‘,” SCE R13D Newsletter VOI 13 No 1, 1s! Quarter 1984, pp 1-2

“OTA figure, based on Information oblamed from McOonnell Oouglas and Advanco Corp. see

Byron J Washom et al Varrguard / So/ar Parabo/lc fish-.stwhrrg Engine Modu/e op cd 1984

and Advanco Corp Proposa/ 10 (he U S LXX Re/a(mg to the Snra// Cornrnurufy So/ar Expermenf

af Mo/okal ffawal~ op clt 1984 The O&M cost for a commercial module would be $1 ,600/year

and average annual module net outpul would be 56234 kWh This amounts to 28 mills kWh

a figure wlthln the lower end of the OTA range

‘

] The capital cost for this plant varies most Importantly with the cost of the hehostats which

here are assumed to 42 percent of total plant costs This colncldes roughly with esllmates made

by the Cahforma Energy Commmon, the Electrc Power Research Institute, and Teknekron Research,

Inc Cahfornla Energy Commm.ion, Append/&s, Techrrma/ Assessrnerrf Manua/, op clt 198 4

Hehosta! costs are especially sensltwe to the number of hehostals produced Using extremely

optmstlc assurnphons about heliostat produchon levels a Sandla study suggested that heliostat

costs would vary between $100 and $150 per square meter of hellostat ( 1980$) If 520000 heliostats

were produced over an 11 year period see H F Norris Jr and S S White, Manufacturing and

Cost Analyses of Hehostats Based on the Second-Generation Heliostat Development Study (Lwer.

more CA Sandla National Laboratories n d ) CE83006664 If a single 100 MWe plant requires

about 15400 hehostats that IS enough heliostats for nearly 34 Installations of 100 Mwe each

The report suggests that If production were scaled down to half that number (about 17 mstalla.

hens over an 11 year period) the costs per square meter of heliostat could Increase 4 to 14 per.

cent If the larger Increase (14 percent) m hehostat cost IS applied to the or!glnal costs per square

meter one of)talns a range of $114 to $171 per square meter of heliostats ( 1980$) If a 100 MWe

Installahon requires 663000 square meters of hehostats this amounts to $756 to $1 134 per

kWe (1980$) this averages out to $945 per kWe ( 1980$) If enough heliostats for 17 100-MWe

plants are sold

For thts to occur the construction of a heliostat plant would have to be mthated no later than

1992, as an Inlllal production facdlty would take 3 years 10 build a fully automated factory would

have to be Inltlated even earlier than that The manufacturer would have to have assurance that

high rates of production could continue beyond the end of the century from McOonnell Douglas

Response by McOonnell Oouglas, General Workshop Olscusslon Ouestions submdted to OTA

In response to wrmen queshons submitted In connection with OTA workshop on Solar Thermal

Electric Technologies 1984 It IS highly unhkely that this quanhty of orders would be expected

to support produchon over the decade beglnmng m 1995

Hellostat costs probably therefore might be considerably higher for the few commercial umts

which are completed m the latter half of the 1990s However, while low production levels might

drwe costs higher technical !mprovemenls alone may drwe heliostat costs downward as much

as 25 percent see California Energy Commission Techn/ca/ Assessrnenl Marrua/ op c!t 1984

As a rough approxlmahon, It IS assumed here that the two opposite effects on hehostat costs roughly

cancel each other out

If the heltostat cost represents 42 percent of lotal plant costs then total plant costs would be

$2 250/kWe (1980$) Using the producer price index this yields about $2531 m 1983 dollars

or $2 500 rounded-off This figure IS based mostly on optlmlstlc assurnphons for 1995 and there.

fore will be used as the low end of Ihe OTA cost range for 1995

The high end of the range assumes that hehostats will cost $250 per square meter ( 1983$)

the preser,f eshmated cost for hehostats This IS based on informahon from the followlng sources

1 ) Personal correspondence between A Skinrood Sandia National Laboratories Lwermore CA

and N Hlnsey Gibbs & HIII Inc May 11 1984 2) Nma Markov Excltmg Developments Reflect

Bright Future Renewable Energy News, VOI 7, No 2 May 1984 pp 8-12

If 663000 square meters are required for a 100 MWe plant the price of the hehostats IS approximately $1 658/kWe If this represents about 53 percent of plant costs then total capital costs

would be $3, 108/kWe This table WIII use fhe rounded figure of $3, 100/kWe as fhe high end

of the cost range This IS somewhat lower than the $3,616/kWe ( 1983$) used In a 1984 analysls

by the Solar Energy Industries Assoclatlon to represent the cosfs of bulldlng three central recewer

plants (30 MWe 60 MWe and 100 MWe) between 1985 and 1992 And It IS considerably lower

than the $4 000/kWe figure cded m one source, Markov, op cIt 1984 as being the present

cost of central recewers, as estimated by ‘Industry analysts

Several pubhshed estimates for commercial units fall within the lower bounds of OTA range

The Cahfornla Energy Commission uses a construction cost eshmate In f982 dollars of $2580

(abouf $2606 m 1983 dollars) for a 1990 central recewer system with the capacity 10 store 3

hours-worth of power and 10 operate with a capacity factor of 40 percent see California Energy

Commmon op clt 1984 EPRI estimates a stmilar figure for a 1992 central recewer see EPRI

Technology Assessrrrerrl Gwde, op cIt 1982

It should be noted these earner esllmates assume mass production of heliostats m numbers

sufficient to allow hehostat costs to drop to relatively low levels It IS here assumed that mass

production of hehostats WIII not Immediately follow the startup of the flrsf 100 MWe commercial

demonstration unit, and that the heliostats utdlzed by any commercial unifs which begin operahon

In the 1990s WIII uhhze hehostals manufactured In relalwely small batches al costs as high as

$250/square meter yleldlng plant costs of about $3, 100/kWe Fortlfy!ng thts estimate IS the fact

that Solar One cost about $16,060/kWe ( 1983$) and the projected Installed cost for Socal Ed’s

proposed (and cancelled) 100 Mwe unit was about $6,000/kWe (1983$) see Cahforma Energy

Commwlon, Tecfrn/ca/ Assessment Manua/ op clt 1984

“Based on mformatlon from the following sources 1 ) Battleson op clt 1981 2) OTA Work

shop on Solar Thermal- Electrlc Generating Technologies op clt 1984

Based on 42 percent capacity factor (escalated to 1983$) O&M costs could be reduced with

the Installaflon of central control facllltles and rowng operators from OTA contractor N Hlnsey

Gibbs & HIII lnc Interview with J Bigger Electrlc Power Research Instttute May 10, 1984

However a pool of several planfs IS necessary fo operate on such a basis This WIII most Ilkely

not be the case In 1995 Therefore, O&M costs are not expected 10 drop stgnlflcantly unhl many

plants are on-line

E Weber md}cates a 124 mill/kWh O&M cost for a 60. MW plant wNh a 23 percent capacity

factor, see E Weber, “Fmanclal Requirements for Solar Central Recewer Plants’ (Phoemx, AZ

Arizona Publtc Serwce Co 1983)

This IS considerably higher than the esllmate prowded by Teknekron Research Inc Energy

and Environmental Systems Dwlston, DaftCos( Esfmates and Cos/-Forecastmg MeVrodo/og~es

for Se/ecfed Nonconvenftona/ Hecfrfca/-Generalfon Techno/og/es, submitled to Technology Assess.

menls Project Off Ice, California Energy Commlsslon, May 1982 This report eshmated that annual

O&M for a 100 MWe plant would be $1,166000 (1978$) Assuming a 42 percent capacity factor

[his amounts to 46 mdls/kWh (1983$) The figure however IS lower than would be obtained

If another source’s estimate of annual O&M of $56 millron/year ( 1981$) for a 100 MWe plant

IS used see J R Roland and K M Ross Solar Central Recewer Technology Development and

Economics–100 MW Uhhly Plant Conceptual Englneer[ng Study, ’ op cd 1983 That figure

wtth a 42 percent capacity factor would yield about 16 mills/kWh In 1983$
App. A—Cost and Performance Tables • 307

Table A-2 b.—Cost and Performance of Solar Thermal.

Electric Plants Central Receivers’

of an Advarrced Waler SJearri Rece/ver for a So/a, Them~~/ Cerfr.i/ Power Sysfem ( LIU mgsfon N J

Foster Wheeler Development Corp 19821

In the OTA s Solar Thermal Electrlc Power Workshop June 12 1984 Charles Finch of McDon

nell Oouglas Indicated fhat lhe gross capacity of a plant should be 110 MW If II IS 10 ylelo 100 MW ret

It should be noted [hat Industry observers foresee an Imtlal development of 30 to 50 MW mod,l

l~r demonst(at~ori umfs Subse~uent commercial umts could possibly De multiples of 50 MW plants

This IS based on !nformallon from 1 I E Weber Arizona PutlIc Serwce personai correspondence

with N Hlnsey Gibbs & HIII Inc May 10 1984 2) A Sklnrood Sandla National La bo,atorles

personal corces~ondence with N Hlnsey Gibbs & HIII Inc May 1 I 1984

‘Two years of preconstruction hcenslng and desiqn and 3 years of construcf[on see Elecfr!c

Power Research Institute Tec/rn/ca/ Assessmen/ Gutde op CII ‘ 982 and K Bal\leson Sof,?r

Power Tower Des/gri Gwde So/dr Therrr?a/ Cerrlra/ Rec(evef Power Syslem$ 4 Source O( E/eclrlc

/y and ‘or Process Heal I Albuquerque NM Sandla Nattonal Labs April 1981 SAN081 800CI

The latter report estimates 4 years but does no! include permltllnq and hcenslnq

Callforrma Energy Comm[sslon (CEC I Technology Assessments P~o)ecl Off Ice Acmerrd/ces Tech

mea/ Assessment Manua/ (Sacramento CA CEC 1984 I vot I 3rd ed Th{s soufce esllmates

a lead time of 8 years II Includes time for advance plannlng “ yearj ‘egulatory I 2 years, pur

chase orders ( 1 year I and construction and start up 14 years I

Based on approximately O 53 acres/mlll[on Btu hr for a plant w,lh a capaclfy facto of 42 percent and 2850 kWh sq m-yr Insolal[on see Battleson op cIt 1981

In one source Arizona Publlc Serwce Co Responses 10 (luestions Pertalmng 10 Solar Ther

mal Electric Po~er Planfs for (he Off Ice of Technology Assessment s hew Generahrrg Technology

Cosl and Performance Workshop June 1984 I! was estlmafed that about 84 acres per MWe

would be requlrea for a cenfral recewer system this would amount 10840 acres for a 100 MWe plant

“ The water requirements for a solar plant would be essermally the same as those tor a water

cooled fossil powered ubhly p(ant There woutc De a small Incremental water requirement for wash

Ing heliostats 15000 gal Iyr per MWth peak I Battleson OP cIt 1981 Waler requirements for

a conventional power Dlant are 675 gal ‘ hr MW see K veagar F/ulmzed Bed Cornbus(IorI 40

EVOhJ1mrMrjlrnpro~erner?l In Electr~c Power Gene,akm VOI 1 Augusl 1980 USDOE CONF 80048

This corresponds fo 680400 gal ‘day for a plant with 42 percent capaclfy factor This figure ad

ded to 5000 gallday for washlog heliostats (380 MWth + ‘00 MWe, ylelcs 685400 gal oay

‘Based on Information from the followlng sources 1 I N Hlnsey Gbbs & HIII lnc OTA con

tractor lnterwew with E Weber Arizona publ)C Serwce May 10 1984 2 I N Hlnsey of Gibbs

& HIII Inc OTA contractor Interwew wlfh A Sklnrood Sandia National Laboratories Llvermore

CA May ! I 1984 3) U S Congress Off Ice of Technology Assessment Workshop on Solar Thermal

Electrlc Generating Technologies Washington DC June 12 1984

Avallablflty must be 90 percent or greater especially for an Intermedlale dut] umt to be serl

ously considered by uflhhes O Van Alla Israell Solar Plant Blooms Englfleew?g News Recora

VOI 211 NO 2 ? Nov 24 1983 This figure is supported by J R Roland and K M Ross Solar

Central Receiver Technology Development and Economics– 100 MW Utlllfy Plant Conceptual En

glneerlng Study Energ} Technology X A Decade of Progress Richard F tiIll I ed ) ~ Rock

vd(e MO Govemmen[ lnstllutes lnc 19831 pp 1421-1444

I oFrom Gibbs & HII Inr, ~vervje~ and Eva/ual/or7 of New and Ccmverrhorra/ Hecmcal Generaf

frrg Techno/og/es for fhe 1990s OTA contractor report 1984 Actual capacity factcrs WIII vary

considerably depending on system design Iocatlon and operating practices

The Califorrwa Energy Commlss[on (n a 1984 report assumes a 40 percenl capaclfy faclor for

a unlf wdh 3 hours’ worth of sforage For the same amount of storage EPRI assumes a capacity

factor ot 30 pe?cent and ?eknekron Research Inc assumes a capacity factor of 50 percent see

Electrlc Power Research Inslltute Techrro/ogy Assessment Gu~de OP cIt 1982 and Teknekron

Research Inc Cost Esfmrales and Cosl Fo,ec;sfmg Mefhodolog(es for Se/ected Nor?corrvenljona/

Hecfrlca/ Gecrerakm Techno/og{es (Sacramento CA CEC 1982] CEC Report No P300 300-82-006

‘ ‘Based on Informaflon (n the followlng sources 1 I Battleson op cif 1981 21 h Hlnsey

Globs & HIII Inc OTA contractor Interview w[th J Bigger Electrlc Power Research Instlfule

May 10 1984 3) E Weber Fmarrcia/ /?equrerrrerrLs for So/ar Centra/ Recewer Harm (Phoemx

AZ Arizona Publlc Serwce Co 1983)

‘ ‘From Gibbs & HIII Inc Owerwew and Eva/uaf/orr of New dnu Ccmverrlmna/ E/eclr/ca/ Gene,jr

mg Techrro/og/es for Ihe 1990s op cd 1984
308 • New Electric Power Technologies: Problems and Prospects for the 1990s

Table A.3.—Cost and Performance of Medium-Sized

Wind Turbines

May 1985 technology status
Table A-4.—Cost and Performance of Geothermal Technologies

App. A—Cost and Performance Tables ● 309

Binary’

May 1985 technology status Dual flash Large/small

‘Two scales of binary technology are Included Although large binary geothermal plants WIII benefit

from economies of scale smaller modular wellhead units WIII also be deployed Smaller 5 to 10

MWe modular untts WIII allow the progresswe development of a geothermal resource This approach lessens the mlflal upfront dedication of capital and allows for demonstraflon of the resource

Module sizes of 10 MWe for flash umts are most Itkely the smallesf to be developed due fo Ilmlfa

tlons In turbine design from R Walter and N Hlnsey Glbtzs & HIII Inc personal correspon.

dence wNh OTA staff May 7 and June 26, 1984

‘Geothermal dual flash technology IS considered commercW today see W Colllns Pmceedmgs

of fhe Geothermal Program Rewew // (Washington OC U S Department of Energy Oecember

1983) CONF-831O177 Nearly 400 MWe of dual flash generated eleclrlclty was installed worldw!de by the end of 1983 see R OIPIppo Worldw[de Geothermal Power Development Geofherma/ Resources CouncI/ Bu//elm VOI 13 No 1 January 1984 The first U S uruf IS expected

to operate commercially (n 1985

‘The larger bnary cycle plants WIII have the!r first demonstration when a 45 MWe plant operates

{n 1985 at Heber CA Small units are already operating at several locations In the U S

‘Although no dual flash umts are presently operafmg m the U S a 30 MWe urvt has been oper

atlng since 1981 at Cerro Prleto Mexico 50 km south of Caltfornla An addmonal 440 MWe (four

110 MWe unds~ of dual flash capacNy IS expected to be on.lme this year In the same vlclnlty

The flrsl U S dual flash unit (47 MWe) IS under construction at Heber see DIPIppo op cIt 1984

‘Since the most recent and comprehensive estimates referenced make no dlstlnchon between

binary and dual flash plants a single set of deployment values are pro)ected

‘From the Electric Power Research Institute s LMllty Geothermal Survey s poss[ble’ estimate

of U S geothermal electricity power capacity In 1995 see P Kruger and V Roberts ‘‘ Uhhty In

dusfry Esllmates of Geothermal Energy Geo(herrna/ Resources CourIcd Trarrsactfons VOI 7 Oc

tober 1983 pp 25-29 Eshmate has been corrected to exclude 2680 MWe expected a! The Geysers

In 1995 see T Cassel et al Nahona/ Forecasf for Geotherrna/ Resources Exp/orakm and f7eve/oprnerrf (Washington DC U S Oeparfmenf of Energy March 1982) OOE/ET/27/242-T2

‘Kruger and Roberts op clt 1983 Esflmate has been corrected to exclude 2680 MWe expected at The Geysers In 1995 see Cassel et al op clt 1982

aThe low end of Ihe range represents the tofal generaflng capauly (dual-flash and binary only)

now Installed or under construction The high end of the range IS derived from Kruger and Roberts

op cIf 1983 This figure has been corrected to exclude 1,753 MWe of capacity at The Geysers

edher operahng under construchon planned or a speculate addlhon see OIPIppo op cIt 1984

‘An EPRI UtIIIty Geothermal Survey Ind{cated that nearly 60 percenf of respondents consider

50 MWe to be fhe minimum size for a commercial plant W(fh regard 10 Optlmu!n Size commercial

plants two. fhirds motcated a preference for 100 MWe and one-third for 50 MWe see V Roberts

Utlhty Induslry Esflmafes of Geothermal Eleclrlclfy ‘‘ Geoffrerma/ Resources Coumx 8u//ehn VOI

11 No 5 May 1982 pp 7-10 California regulations reqwre that electrlc generahng Iacllitles

greater than 50 MWe ( netl file for cerhflcat!on and also perform a documentahon of fhe resource

and technology To date all geothermal plants planned or under construction (excluding The Geysers)

[n California do no! exceed 49 MWe ( net) tn order to avo!d the delay and cost of complylng with

regulations for umts larger than 50 MWe (nef) Since most geothermal development IS expected

to occur In Callforma (n fhe nexl 5 to 10 years 50 MWe appears to be a reasonable s!ze for lhe

reference plant discussed here This IS based on mforrnahon prowded by 1 ) Walter and H!nsey

op clf 1984 2) R OIPIppo, Southeastern Massachusetts Unwerslfy, personal correspondence

with N Hinsey G!bbs & HIII, Inc May 7, 1984 3) Collins op cd 198 3

Gross plant size shown (53 MWe) represents thaf of a dual flash system

‘“Same rabonale as m footnote 9 Binary cycles require much more auxlllary power to pump

brine and would need a 70 MWe turbine (size reduction would occur as efficiency of the cycle

IS Improved) see OIPIppo, op clt 1984

“Several observers have projected that modular, wellhead umts wdl comprise a large porflon

of binary development at lower temperature, less understood resources 1 ) Jack S Wood Wood

& Associates personal correspondence wdh OTA staff Oct 6 1984 2) Evan Hughes Eleclrtc

Power Research Instdute, personal commumcation with OTA staff Oct 4 1984 3) Janos Laszlo

Senior Mechamcal Engineer, Paclflc Gas & Electrlc personal commurvcatlon wlfh OTA staff Oct

10, 1984

The 5 MWe umt corresponds to a powerplant geared to the output of one well from Ben Holf

Ben Holt Co personal commumcation wdh OTA staff Sept 10 1984

,? Great Varlatlons may result from hcenslng requwements about which there IS considerable

uncerfamty The first umt at a given site WIII take longer possibly 5 years due to Imflal permlftlng

and Ilcensmg Subsequent unds could require as Idtle as 3 years Based on Information prowded

by 1 ) OTA, Workshop on Geothermal Power Washington DC June 5 1984 2) Cassel et al

Op c!t 1982

I JFor large Units sw foofnote 13 Smaller units can be factory fabricated and shipped to the

sNe much quicker than larger unds Modular urwts depending on the ste could be brought onIlne In as few as 6 months (not mcludlng permlftlng and Itcensmg) Jack S Wood, Wood & Associates, personal commumcatton wdh OTA staff Oct 6, 1984 !ndtcated that It takes only 100

days to full operation after a modular umt arrives onslte Incluslon of hcenslng and permdtlng

should extend Iead-time to 1 year Great variations may result from Iicensmg requirements about

which there IS considerable uncerfamty

I~OTA Workshop on Geothermal Power op cd 1984 This value does not include the entire

area of the field because much of the land above the field can stall be utilized and only part of

the surface IS occupied by the factlntes (Modular units would be at the low end of this range )

~ ~The larger units should require up to 20 acres—similar to dual flash units from Walter and

Hmsey, op clt 1984 A smaller urut can vary from less than 1 acre for a modular contalnermounted unll 103 acres for a untt stmllar to an East Mesa CA wtil see G{bbs & HIU Inc Overwew Fva/uahoff of New and Corrverrf~ona/ Hecfr/ca/ Geflerarmg Tecfrrro/og~es for ffre f990s OTA

contractor report Sept 13 1984

‘

e

Based on an estimate made by J A Blckerstaffe, Gibbs & HIII, Inc personal correspondence

wtth OTA staff, May 1 1985 he eshmated that the 47 MWe (net) Heber dual flash umf WIII require

approximately 2800 gallons/mmute of make-up waler This figure was adjusted for the sllghtly

larger 50 MWe (net) reference plant operating wOh a capacity factor of 70 percent The figure
310 . New Electric Power Technologies: Problems and Prospects for the 1990s

assumes that all steam condensate IS rempcted with the spent brine If any of the condensate

IS used for cooling purposes, make-up water requirements will be smaller

“Based on estimate that the 45 MWe (net) Heber Binary plant will consume water at a rate

of 3,700 gallons per minute The water requirement was esttmated by Southern Cahforma Ed(son

Co (n comments made on OTA draft cost and performance tables, Apr 10, 1985 This was adjusted for the shghtly larger 50 MWe (net) reference plant, operating w!th a capacity factor of

70 percent

“Based on estimate made by Zrl Kneger of Ormat Turbines Mr Krleger stated that a 20 MWe

(net) Installation conslstmg of 26 modules planned for East Mesa, CA, would have make-up waler

requirements of about 1,500 to t ,800 gallons/mmute This was adjusted for the considerably smaller

7 MWe (net) reference plant, operating with a capacity factor of 70 percent

‘80TA Workshop on Geothermal Power op cd 1984

‘“lbld

“lbld

‘Zlbld

?Joeslgn life of current plants IS 30 years This IS nof expected to change m the next 10 Years,

from Walter and Hmsey, op clt 1984

Z4r3TA Workshop on Geothermal Power Op clt 1984

~~Evaluated al a 400 c F resource

‘°Flgures shown represent ‘‘ nel brine effectweness’ (defined as watts of net electrlc power

output per pound per hour geothermal flow) m w-hr/lb For current state-of-the-art power systems the net brine effectiveness ranges from 70 to 80 for dual flash cycles, respec!wely, given

a resource temperature of 200= C (400 ~ F), see T Cassel, C Amundsen, and P Blalr,Geotfrernra/ Power P/arrf R&D, An Ana/ys~s of Cosf-Perforrnance Trade-offs and the /feber Mrrary Cyc/e

Derrronstratlon Pro/ecf (Washington, OC U S Department of Energy, June 30, 1983), OOE/CS/

30674-2 Oual flash IS a mature technology and basic cycle efflctency improvements are not expected as with conventional cycles, gains m efficiency can be achieved through greater capital

and operating expenditures Economic conslderallons, as opposed to technical breakthroughs,

drwe these declstons, see Gibbs & HIII, Inc op ctt 1984

?TF(gures shown for high, medium, and IOW represent ‘‘net brine effeCIWeneSS’ (defined as

watts of net electrlc power output per pound per hour geothermal flow) m w-hr/lb For current

state-of .the-art power systems the net brine effectweness is about 95 for binary cycles, respec.

twely gwen a resource temperature of 200 C (400” F), see Cassel, Amundsen, and Blalr, op

ctf 1983 Reference 10 reveals fhat an advanced binary sysIem (ut!hzlng a countercurrent condensor and a recuperator) brine effectweness could reach 11 9 for a 2000 C resources with 2,000

to 100000 ppm total dissolved solids, wtth add!tlonal penetration Binary cycle research Indicates

that there WIII be Improvements In brine effectweness as more work IS performed on dlrecl contact

heat exchangers, staged heat relectlon, recuperafton and counter-current condensing Twelve

w-hr/lb represents the est!mated maximum probable net effectweness, see J Whltbeck, Idaho

Nahonal Englneermg Lab, ‘‘Heat Cycle Research Program, Proceedings of the Geotfrerma/ Program Review // (Washington, OC U S Department of Energy, December f983), CONF-831O77

The smaller binary plants are not as efflclent as fhelr larger counterpafls With slgmftcant penetration net effeclweness could increase to 9 w-hr/lb, from H Ram, Ormat, Inc , personal communication with OTA staff, Oct 6, 1984

ZIBased on Information from t ) Walter and Hmsey, Op cit , 1984 2) OTA workshop on Gee”

thermal Power, op cit , 1964 3) Cassel, Amundsen, and Blar, op cit., 1983

Capital costs are not expected to decrease as a function of on-hne capaclfy Small, modular,

flash umfs (approximately IOMWe) cost $t ,500 to 1,600/kWe for single units (based on data

from Gibbs & Htll, San Jose Off Ice) When several umts are purchased together the cost could

be as low as $1 ,000/kWe, from Walter and Hinsev, op clt 1984 Installations at highly sahne

resources WIII be more costly, however

?? Based on Information from the following sources 1 ) Walter and Hmsey, OP clt 1984 2)

OTA Workshop on Geothermal Power, op clt , 1984 3) Gibbs & HIII, Inc op clt, 1984

Capital costs are not expected to increase as more units are deployed Large binary plants WIII

have larger capital costs because of the greafer complexly revolved

JOThe smaller binary plants WIII have higher Capital costs than large binary OYO18 Plants Costs

of $2,000/kWe have been reported for a 7 MWe (net) plant, from HoIf, op clt , 1984 Very small

5 MWe, contamerlzed, binary umts have been adverflzed for $1 ,500/kWe, installed, from Ram,

Op Clt 1984

IIOTA workshop on Geothermal Power, op Clt , 1984 O&M costs of Plants now m OPerafmn

vary widely due to the quahtles of the resouces being utlhzed The Heber flash plant has an O&M

cost of 103 mW/kWh and could be considered average Advances m operation, mcludmg computerized controls and rowng operators, could reduce the operating component of O&M costs somewhat m the nexl 10 years But Ihls Improvement would not be sigmftcant when compared to the

possible range of total O&M costs, see Walter and Hlnsey, op cit , 1984

3’O&M costs are expected to be the same as those of the dual flash technology Based on information provtded by 1 ) Walter and Hlnsey,” op cit 1984 2) OTA Workshop on Geothermal Power,

Op clt 1984

I~OTA workshop on Geothermal Power, op CII 1984 Brine COSk reSUlt from negotiation wflh

the brine suppher The brine cost WIII tend towards a price which causes the total cost of the

geothermal plant to be competttwe with the least expenswe alternate form of base load generation Oependlng on location, this could vary between 20 to 70 mlHs/kWh, see P Blair, T Cassel

and R Edelsteln, Geofhernra/ Energy /rrvesVrrerrt Dec/s/ons arrd Cormnerc/a/ Oeve/opmefll (New

York Wdey Intersclence, 1982)
App. A—Cost and Performance Tables . 311

Table A-5.—Cost and Performance of Large

Atmospheric Fluidized-Bed Combustion Systems’

May 1985 technology status

Level of technology development: commercial demonstration

unit under construction

Installed capacity (large units only): none

Reference. system: general characteristics

Reference year: 1990

U.S. deployment level scenario, 1990 (large units only,

including retrofit units):3

High. . ........735 MWe

Medium . ......610 MWe

Low . .........510 MWe

Plant size (no. of units x unit size):

Gross . . . . .1 x 163 MWe

Net . . . . . . .1 x 150 MWe

Lead-time: 5-10 years4

Land required: 90-218 acress

Water required: 1.5 million gallons/dayE

Reference system: performance parameters

Availability: 85-87 percent7

Duty cycle: base/intermediate

Plant lifetime: 30 years

Plant efficiency: 35 percents

Reference system: costs

Capital costs: $1,260-1 ,580/kWeg

O&M costs: 7.66 mills/kWh’O

Fuel costs: 17.4 mills/kWh ”

‘Unless otherwise speclhed the figures relate to entwely new ‘‘grass roots” electrlc powerplants not to the retrofits of flu!dlzed bed combustors to exlstmg power plants Also unless otherwse

stated the figures apply only to plants des!gned and operated to produce electrlc power only,

cogenerators are excluded

‘Note that three large retrofd umts are under construction Two of these are utilltydemonstration units, one IS a commercial nonutlllty umt

‘The deployment figures include bofh enttrely new plants and retroftts All deployment levels

assume that the following plants WIII have been completed and will be operating by 1990

–Tennesee Valley AuthorNy Shawnee Urut 160 MWe, to be completed 1989

–Colorodo Ute, Nucla untt, 100 MWe, to be completed 1987 (retrofit)

–Norihern States Power Co Black Dog Unit 2, 125 MWe, to be completed t986 (retrofit)

–Florlda Crushed Stone Co Brookeswlle FL 125 MWe to be completed 1987 (retrofit

cogenerahon)

The low scenario assumes that no plants other than those Itsted above WIII be operahng In 1990

The high scenario assumes that two add!tlonal retrofit urut WIII be operahng with a total additional

capacdy of 225 MWe and the medium scenario assumes that one addNlonal 100 MWe umts WIII

be operating Neither the medium nor the high scenarios are expected only the low one IS

‘It IS assumed that the AFBC WIII have roughly the same Iead.time as the IGCC This assumes

3 to 5 year preconstruction period and a 2 to 5 year construchon period Exceptionally favorable

circumstances could lead to Iead-times below this range unusually poor condlllons to result In

a higher Iead-time

5Usmg a figure of O 6 to 1 45 acres/MWe The land estimate includes the land required for

solid waste disposal and coal storage This figure IS based on two sources 1 ) Batfelle Columbus

Dwlslon, Fma/ Reporf orr A/ferrratwe Gerreraflon Technologies, VOIS I and II (Columbus OH Battelle, 1983) This source Indicated that a 1 000 MWe plant would require 1 450 acres this averages out to 1 45 acres/MWe 2) Kurt E Yeager, Electrlc Power Research Institute ‘Coal Uhhzatlon

in the U S –Progress and Pttfalls “‘ Proceedings of the Sixth In fernaflonal Conference on Coal

Research, London UK, Oct 4, 1982 (London, UK National Coal Board, 1982) pp 639-664

This source suggests that 1,200 acres would be required for a 1,000 MWe plant this averages

out to 1 2 acres/MWe 3) James W Bass, Ill Prolect Engineer, AFBC Technical Serwces TVA

personal correspondence with OTA staff Apr 30, 1985 He estimated that the TVA 160 MWe

demonstration plant WIII occupy approximately 93 acres This amounts to about O 6 acres/MWe

‘Based on an estimate that an AFBC would consume approximately O 6 gallons per kWh and

a capacity factor of O 7, see Yeager, op cd 1982 These figures are consistent with esllmates

made by Bass, op cIf 1985

7Based on Information provided by 1 ) Workshop on Fluldlzed-Bed Combustors OTA, Washington OC, June 6, 1984 2) Electrlc Power Research Instllute Techn~ca/ Assessment Gwde (Palo

Alto, CA EPRI, May 1982), P-241O-SR 3) Stratos Tavoulareas. Project Manager Fluldlzed Combustion, Coal Combushon Systems Dw!slon EPRI, personal correspondence with OTA staff Feb

19, 1985

‘Based on Information provtded In the following sources 1 )K E Yeager ‘Fluldlzed Bed

Combustion–An Evolutionary Improvement In Electric Power Generation, The Proceedings of /he

SLWI /nternaf/ona/ Corrference orI F/u/d/zed-8ed CorrJbustIon Apr 9-11, VOI 1.1980, CONF-800428

2) ‘‘EPRI, B & W Score Major Advance with Atmospheric Ftuldlzed Bed Boiler The Energy Da//y

Oct 10, 1979 3) Burns and Roe Concepfua/ Des/gn of a Gu/f Coast Llgrv[e-fwed Atrnospher/c

F/u/d(zed-Bed Power P/an( (Palo Alto CA Electric Power Research Instlh.rte 1979) EPRI EP-1 173

4) R Smock, ‘‘ Utildies Look to Fluld Bed Design as Next Step In Boder Design, E/ecfr/c Llgfrf

and Power, VOI 62 No 7, July 1984, PP 27-29 5) Yeager, OP clt 1982 This source suggests

that a 1,000 MWe untt would have an efficiency of 353 percent

‘The high end of the range IS based on an estimate made by Tavoulareas, op clt May 15

1985 He estimated that the costs, In 1984 dollars, might be approximately $1 ,640/kWe for a

plant w[th a net capacity of 1933 MWe (209 6 MWe gross) Converted to 1983 dollars using

the Handy Whitman Bulletln Cost Index (see Defmdlons section of this apppendtx), this yields

$1 ,580/kWe This IS considered the high range of the OTA estimate The low end of the range

IS set 20 percent lower than that figure, or $1,260

~oThls IS based on an estimate made by Tavoulareas op clt 1985 He estimated that the O&M

costs, in 1984 dollars, might be approximately 796 mills/kWh for a plant wtlh a net capacity

of 1933 MWe (209 6 MWe gross) Converted to 1983 dollars using the Handy Whttman Bulletln

Cost Index (see DeflnNlons sectton), this yields an O&M cost of 766 mills/kWh

“Based on a 1990 coal cost of $1 78/mNlon Btu (see detads In the DefmKlons section of this

append!x for an explanahon for fuel costs) and an average annual heat rate of 9751 Btu/kWh
312 ● New Electric Power Technologies: Problems and Prospects for the 1990s

Table A.6.—Cost and Performance of Integrated

Gasification/Combined-Cycle Powerplantsl

May 1985 technology status
App. A—Cost and Performance Tables ● 313

Table A-7.—Cost and Performance of Fuel Cell

Powerplantsf

May 1985 technology status Large Small

1.5 ‘MWe4 “

2 x 200 kWe

2 x 200 kWe

2 years

42-11.5

42-11.3

43-10 7

30-33

‘Only ohosphonc-acrd fuel cells are corrsldered

z I n 1983 no commercial.scale demons! rallon umts were operallng In the Unlfed States In 1984

the hrst of a ser,es of about fifty 40. kWe umfs were operaflng In the Unlfed States and a 4 5

MWe faclllty was operat[ng (n Japan Further demonstration units are planned for Ihe next hve

years In a varlely of szes bo[h In Japan and In the Unifed States

‘These umts are 40 kWe and are substantially different In desgn trom the larger unlfs (wlfh

capaclt!es of several hundred kWel expected 10 be commercially deployed In the 1990s

‘This conslsfs of 38 units rated at 40 kWe each

‘The low estlmale assumes that approximately fifty 40-kWe (net) unlfs two 11 -MWe unlfs and

two 7 5-MWe Dowerplants WIII have been installed by 1995 All would be demonstrahon units

some of which WIII cease operallon betore 1995 The low scenario assumes that no commercial

units WIII be operahrrg (n 1995

The meclum scenar!o assumes lhe followlng 1 ) The bulk of Inlhal orders WIII be for large fuel

cell powerplanls rather fhan small ones 2) Investors WIII not Inltlate commercial fuel-cell projects

until they have seen demonstration un!ts operating tor a year 3) Large commercial demonstrahon

uru!s WIII go Into serwce In 198889 and Investors WIII Irullate projects no sooner than 1989-90

4 I Demonstration and commercial prolects WIII have Iead-hmes of 3 years the commercial projects

therefore would not yield operating generahng capaclfy until 1992-93 5) Beglrrmng in 1992-93

an average of 200 MWe of fuel cell powerplants WIII be placed (n operat[on each year through

1995 Th(s deployment level IS considered by industry sources to be the mmlmum level which

allows the economic production of fuel cells In one manufacturing faclllty Thts IS equwalent 10

the startup of about eighteen 11 MWe plants each year

Th[s results In a deployment scenano of 400 to 600 MWe (absorbing all of the fuel cells produced

In 2103 years from a single manutacturmg facdtfy) This IS equwalenl to between thirty.six and

fifty-five : 1 MW umfs though In actuallty the [nstalla!lons would vary In size

The high scenario IS based on assumptions ~ 1 ) through (4) above Assumpllon (5) however

IS changed to an average deployment level of 400 MWe annually from 1992-93 through 1995–double

the deployment levels assumed (n the medium scenario This results In a deployment level In 1995

of 800 to 1 200 MWe This deployment level could be met by expanding the fuel-cell output of

a single manufacturing plan! or by operating more than one manufactunrrg plant Under this

scenario the equwalent of lhlrty-slx 11 MWe plants would be started up each year, starfmg In

1992 or 1993 a total of 73 to 109 such plants would be operating by mld-1995 under fhls Scenario

‘The small fuel cell mstallatlons deployed m the 1990s hkely WIII be budt around two or more

stacks each capable of delivering 200 kWe (net) AC It IS assumed lhaf two stacks WOUIO be used

In the reference plant but several more mlghl be deployed at any one ste It IS assumed that

the large fuel cell [nslallatlons In the 1990s WIII be bud! around stacks each capable of generating

250 to 700 kWe (OC) Installafton capaclly probably would range from several megawatts and

up The Insfalla[lon assumed here would consist of approximately 18 stacks, each capable of generating 675 kWe (DC) While larger or somewhat smaller mstallahons are hkely to be budt and operated their cost and performance should roughly colnclde wlfh that of the t 1 MWe plants

‘The lower esflmale for the large fuel cell mstallaflon IS based on discussions at OTA Workshop

on Fuel ~ells Washington DC June 6, 1984 The upper estimate for fhe large plant IS based

on esflmates made by Cahforma Energy Commission Tecfrmc.al Assessrnerrf Mamza/ VOI 1 Edihon Ill (Sacramento CA CEC 1984) P300-84.013 and by OTA staff The greatest uncertainty

m the range results primarily from uncertainty regarding regulatory delays Many of the fuel cell

Insfallatlons are hkely to be deployed In areas where Ilttle prewous powerplant development has

occurred and where population densdles increase the posstbddles for regulatory confhcts The

potenfial for regulatory problems was exemplified by a 45 MWe demonstrahon umt which was

budt (but never operated) m New York CIfy Numerous unanhctpated regulatory delays were encountered, and prevenfed the expeditious completion of the plant approval of the project by New

York City’s fire department fook 3 years

The estimate for the small fuel cell lnstallatton IS based on discussions at OTA Workshop on

Fuel Cells op clt 1984 The extremely small size of fhe plant suggests thaf regulatory delays

would be considerably less problematic than would be the case with larger plants Some wlfhln

the Industry believe that Iead.limes could be as short as several months see R A Thompson

Manager Business Planmng, United Technologies Corp Fuel Cell Operations personal correspondence with OTA slaff Feb 15, 1985

‘Burns & McOonnell Englneerlrrg Co Sysfern Harmer Gwde for Eva/uahng Pfrospfrorlc Ac(d

Fue/ Cc// Power P/ants (Palo Alto CA Electric Power Research Instttute, 1984) EPRI EM-3512

See also comments of Thompson op cd 1984

‘OTA esftmate based on two modules, each measuring 30 x 8 feef ~hls IS fhe size of module

suggested by Richard R Woods Jr Manager Fuel Cells Gas Research Ins!lfute In personal

correspondence with OTA staff Feb 4 1985

IoUn)ted Technologies Corp Speclf)caflon for Djspersed Fue/ Cc/l Gerrerator lnterlm Repofl ( palo

Alto CA Electric Power Research Instlfute 19BI I EPRI EM-2123 Project 1777-1

“ Umted Technologies Corp Power Systems Dlvlslon Drwle 40-kf/owaH Fue/ Cc// Power P/anf

Mode/ Specffcal~on prepared for U S Departmen! of Energy and the Gas Research Instlfute (South

Windsor CT Umted Technologies September 1979), FCS.1460

j2Thls IS based on Fuel Cell Users Group. System Planning Subcommittee Ad HOC Rellablllty

Task Force Reporf on Fue/ Cc// Rehabdfly Assessment (Washington DC Fuel Cell Users Group

March 1983) The report recommended use of an 85 percent avatlablllfy factor In system plannlng

studies for large fuet cell powerplant Installations It however stated that avadabdlty could range

between 80 and 88 percent, depending on assumptions made about component redundancy and

about the avallablllfy of spare parts It IS assumed that the operahng avallabllllles of small fuel

cell powerplants WIII fall wlthm the same range as that of the larger fuel cells as no comparable

studies are available on the operahrrg availabhhes of the Smalt plants

“This refers to the plan! hfehme Cell stacks themselves are assumed to have Ilfetlmes of 40000

hours when running at full capacity

liTh{s ,s the operating efficiency at which eleclriclfy IS produced when the Plant Is operated

at Its full rated capacdy In cogeneratlon appllcahons where useful heat WIII be produced along

wlfh electric power the total energy efficiency [which Includes all useful energy outputs thermal

and electrlc ) would be much higher The cogeneratlon efftclency could be as high as 85 percent

“Based on higher heating value of fuel This range IS consistent with eslimates made In numerous sources includlng 1 ) Umted Technologies Corp Soectf~cahon for flspersed Fue/ Cc// Gerrer

afor Interim Report (Palo Alto .CA Electric Power Research Instlfute 1981 ) EPRI EM-2123 Project

1777-1 2) Mike Ringer Callforma Energy Commlsslon Re/afwe Cosl of Heclrmfy Produclfoo

(Sacramento CA CEC, Oecember 1983) 3) Utddles Show Interest m Large Fuel Cell lnstallahons for Late 80s Elecfnc L~ghf and Power VOI 62 No 6 June 84 p 53 4 ) Irwtn Stambler

Fuel Cell Outlook Br!ghtens as Techmcal Obstacles Fall Research & EZeve/oprnerrf December

84 pp 50-53 5) Battelle Columbus Dtwslon Fma/ Report on A/lerrrallve Generahon Tecfmo/ogles VO(S I and 1/ (Columbus OH Batfelle 1983) 6] Thompson, op cIt 1985

“Based on higher heahng value of fuel From 1 ) J W Stamunas and G P Merfen and R M

Smith Un[ted Technologies Corp Fo//ow-On 40-/rWe Fle/d Tesl SUppoil Annual Reporl prepared for Gas Research Instifute (Chicago IL Gas Research Inshtute 1984) FCR-6494

GR1-84/0131 2) Woods, op clt Feb 4, f985

17 Eshmates do not include cell replacement costs The lower end of the range assumes a mature

technology and mass production the high end of the range represents the estimated cost of the

commercial demonstration umts expected to be Installed and operated (n the late 19BOS WNhln

this range fall the estimates cded In the followlng 1 ] The partmpants n an OTA Workshop on

Fuel Cells op cIt 1984 2) Ringer OP clt 1983 31 Calrforrwa Energy Commlsslon, op clt

1984 4) I R Sfraughn Southern Callforrua Edison Co R & D Inou[ to the Fall 1984 Generation

Resource Plan unpublished memorandum August 1984 5) Lee Catalano Can Fuel Cells Survwe the Free Market m the 1990’s7 Power, VOI 128 No 2, February 1984 pp 61.63 6 ) Burns

& McOonnell Englneerlng Co System P/anner’s Gu{de for Eva/uaWrg Phospfrorlc Acid Fue/ Cc//

Power P/ants (Palo Alto, CA Electrlc Power Research Institute 1984 I EPRI EM-3512 7) Battelle

op clt 1983 8) J R Lance et al Westinghouse Electrlc Corp Economics and Performance

of Ufhty Fuel Cell Power Planls ‘‘ Advanced Energy Sysferns-Thew Ho/e m Dur Fufure Proceedings of 19th Intersoclefy Energy Conversion Engmeermg Conference Aug 19-24 1984 San Fran

CISCO CA (U S Amertcan Nuclear Society 1984) paper 849133 pp 821-826

Where a single expected’ value IS used m this report a value of $1 430/kWe IS used

‘“The estimates do not Include cell replacement costs The lower end of the range assumes

a mature technology and mass production the high end of the range represents the estimated

cost of the first commercial cogenera!lon units Wlthln this range fall the eshmates cited {n the

following 1) Richard Woods Gas Research lnstltute as quoted m Ernest Rala, Fuel Cells Spark

Uhlltles Interest ‘‘ Htgfr Tecfrno/ogy VOI 4 No 12 December 1984 pp 52-57 2) Catalano

op cit 1984 3) OTA Workshop on Fuel Cells op clt 1984 4) Thompson op cd 1985

As an expected value for capdal costs DTA uses In Its analysis a value of $2240 (1983 $)

This IS based on an estimate made by the Gas Research Instttute (G RI) of the cost of a 200 kWe

cogenerahon module see Stephen D Ban GRI Gas-Fueled Cogenera[/on–Gf?/s Curren( R&O

Program unpublished mimeograph (Washington DC GRI n d ) The GRI estimate referred 10

the expected costs during the period of early market entry with Iow-quanhty fuel-cell produchon

levels
314 ● New Electric Power Technologies: Problems and Prospects for the 1990s

!QTOtal O&M costs include fixed O&M costs, variable O&M costs and stack replacement costs

This study assumes fixed O&M costs of $200 to $5 00/kWe-year and variable O&M costs of 2

to 5 mdls/kWh These estimates of fixed and variable O&M costs appear to be In accord with

mformahon prowded m the followlng documents 1 ) Ringer, op clt , 1983 2) Straughn, op clt

1984 3) 8urns & McOonnell Engmeermg Co , op cd , 1984 4) Battelle, op CII , 1983

Estimates made m the above sources do not appear 10 include stack replacement costs, these

are rarely eshmated m the hterature Ewdence available to OTA suggests that these WIII range

belween $100 and $300/kWe, depending especially on fuel-cell production levels at the hme the

replacements are made It IS assumed that fuel cells are replaced after 40,000 hours of operatton

at full capacity The replacement cost est!mates are Ievellzed values over 30 years, using a 5 percent discount rate

Total O&M costs estimates consequently are as follows (mdls/kWh)

Duty Cycle F/xed K?r/ab/e Rep/acerrrertf Total

8ase/Cogen 03-08 2-5 19-5 7 42-11 5

Intermediate 06-1 4 2-5 16-4 9 42-11 3

Peaking 23-5 7 2-5 -o- 43-107

Under the assumption that fuel cells would have to be replaced every 40,000 hours at full capacity operahng levels, no replacement stacks would be required for a peaking powerplant

?oBased on I gg5 natural gas price of $4 40/mm Btu (see Oefmltlons SeCtlOfl Of this appendix

for an explanation of assumed fuel costs), and a heat rate of 8,533 to 9,481 Btu/kWh (36 1040

percent efftctency) for small fuel cell plants and 7,757 to 8,533 Btu/kWh (40 to 44 percent effl.

ciency) for large fuel cell plants
App. A—Cost and Performance Tables • 315

Table A-8.—Cost and Performance of Compressed Air

Energy Storage Plants

May 1985 technology status Maxi -CAES Mini -CAES

‘A 290 MWe salt dome based CAES plant IS operating m Huntorf West Germany Another smaller

25 MWe plant lust has been completed In Italy Neither however has ever been demonstrated

[n the Umted States

‘No capacity [n the Unlled States has been Installed One project sponsored by Soyland Power

cooperahve was scheduled for commercial operat!on In 1986 However (t was canceled In 1983

‘Brown Boverl currently offers plant equipment for 50 100 220 and 300 MWe applications

from Z Stanley Stys Vice President BBC Brown Boverl Inc personal correspondence with Fred

Clements G!bbs & HIII Inc May 9 1984 The following two references selected 200 MWe as

a typical size 1 I Electric Power Research Institute Compressed A/r Energy Storage Commerc/a/iza!lon Po/enf~a/ (Palo Alto CA EPRI 1982) EM-7750 2) Electrlc Power Research Instlfute Tecfmica/

Assessmeo[ Gwde (Palo Alto CA EPRI 1982) EPRI P-241O-SR

However since then EPRI commlss[oned a study on mln! CAES plants see Gibbs & HIII Inc

Mm{ Compressed 4tr Energy Storage Sys!ems (25 MWe 50 MWe modules) draft report sub.

mltfed to EPRI ( New York Gibbs & HIII Inc April 1984) the reporl Indicates that mlm CAES

plants In the 25 to 100 MWe range are also economically wable and can compete with the larger

220 and 300 MWe plants The mini CAES plants use proven equipment In modular conllgurahons

and reqwre shorter Iead.ttme

‘The low end of fhe esllmate assumes no plants are completed by 1990 The high end assumes

two mint-CAES plants are completed by that time

~Based on Information from the followlng 1 ) ConstructIon time of 3 to 4 years for maxi-CAES

and 2 5 years for mlnl-CAES from Robert B Schamker Electrlc Power Research Institute and

Michael Nakhamkm Gibbs & HIII Inc Compressed-Air Energy Storage (CAES) Overwew Per

formarrce and Cost Data for 25 MWe-220MWe Plants ‘‘ /EEE Power Engmeermg Rewew Apr[l 1985

pp 32-33 21 Llcenslng time of 2 to 4 years The low esllmale IS prowded by Schainker and Nak

hamkin op clf 1985 The high estimate was oblained from Peter Schaub Manager New Technology Program Potomac Electric Power Co personal correspondence with OTA staff November

1984

‘Gibbs & HIII Inc Overwew Eva/uaf/on of New and Corrverrtfona/ E/ecfrfca/ Gerrerafmg Techrro/o -

g~es for (he 1990s OTA contractor report 1984, calculated tor a plant using a salt cavern

‘Gibbs & HIII Inc op clf April, 1984 Calculated for a plant using a salt cavern

OHans Chrtstoph Herbst NWK and Z Stanley Stys Vice President BBC Brown Boverl Inc

Hunforf 290-MWe the Wor/ds Fwsf A/r Sforage System Errergy Transfer (Assell P/anf Cor?sfrucflon and Commisslorwrg Presented to American Power Conference Chicago, IL Apr 24-26 1978

Downsized for lyplcal 220 MWe plant calculated for a plant using a salt cavern Note lhat CAES

plants can be designed to use no water at all from Robert B Schamker EPRI personal correspon

dence w!th OTA slaff May 28 1985

‘Gibbs & HIII Inc op CII April 1984 calculated for a plant using a salt cavern

10wllh respect to maxi.CAES see Robert B Schalnker EPRI and M Nakhamkln Gibbs & HIII

Inc Compressed-A)r Energy SYorage Overwew Performance and Cosl Data for 25kfWe to 220Mwe

P/anK paper prepared for the Joint Power Generahon Conference October 1984 Toronto Canada That paper states tha[ the Hun[orf West Germany p(ant has 90 percent avadablhty the avallablllty for the last repofllng period was 98 percenl– Stys op crt May 1984 For mini.CAES

operating avallablllty IS expected to be at the high end of the range thts IS supported by Intorma

tlon provided by 1 I Gibbs & HIII Inc op cd 1984 21 Schalnker and Nakhamkin op clt Oc

tober 1984

“Gibbs & HIII Inc op clt 1984

~ ]The estimate for maxi-CAES IS based on Information prowded by EPRI Comwessed ~lr Eflw

gy Storage Commercla/fzal/orr Pofentla/ op clt 1982 The estimate for maxi-CAES IS based on

Information provided by Gibbs & HIII Inc op clf April 1984

‘

] Schalnker and Nakhamkln op clf October 1984

‘“Robert B Schainker EPRI [n a personal correspondence wlfh OTA staff May 28 1985 lndlcated that mlm-CAES would have the same fuel efficiency as maxi-CAES

‘

5 Schalnker and Nakhamkln op clf October 1984

‘OSchalnker op CII May 28 1985 mdlcated that mlnl-CAES would have the same electrlc~fy

efflc!ency as maxlCAES

I TThls calculation assumes that for every kWh (3 413 Bfu ) generated 4 000 Bfu of fuel and

2662 Btu of electricity are required Thus the efftc!ency IS 3 413/6,662 or 51 percent This calculation does not consider the efficiency losses associated wlfh the electrlc power supplled 10 fhe

CAES plant

‘‘A CAES plant does not need to charge and discharge af the same power Thus a plant wh!ch

discharges 220 MWe for 4 hours can charge wlfh 43 MWe for 16 hours In general the power

needed to charge a CAES plant which WIII discharge af full power for TO hours IS

Power-In = (aMWe x TO)/(Tl x O 78)

where T1 IS the charge time O 78 IS the kWh-in/kWh-out efflclency, and a IS fhe capacity rating

of fhe CAES plant

‘“The Huntorf plant has a 4 hour/16 hour discharge/charge cycle see Peter Maass and Z Stanley

Stys Operat/on Experience W(th Hunfort 290 MW Wor/d’s First Av Sforage System Energy Transfer

(ASSET) P/anf paper presented to American Power Conference Chicago IL Apr 21-23 1980

However plants can be made wlfh discharge times over 10 hours see BBC Brown Boverl, 220

MW Slxfy.Cyc/e Assef P/anl Promotional Brochure (USA BBC Brown Boverl n d I Publlcatlon

No CH-T 113390 E

20 Gibbs & Hill Inc Op Clt I g84 $570/kWe fetal comprises $515/ kWe for above ground com

ponents (e g , turbomachlnery structures) and $55/kWe for underground salt dome cavern Cost

IS based on average U S condlfions and IS not expecfed to be sens[tlve to local~on

~~ Schalnker and Nakhamkln op clt October 1984

221bld

131bld

?~Glbb5 & HIII Inc Op ctt April, 1984 This report prowdes costs In January 1984 dollars

for 266, 50, and 100 MWe plants with 10 hour storage Based on The Handy Whlfman Index

(see Oefm!tions to this appendix) these costs were reduced by 17 percent to reflect mtd-1983

dollars The costs depend on the type of cavern $487/kWe IS for a 50 MWe module wlfh salt

dome cavern The breakdown of $487/kWe IS as follows $392/kWe above-ground Items and

$95/kWe fOr Salt dome cavern For rock and aquifer sforage the total costs would be $833/kWe

and $440/kWe respectwely Cost IS based on average U S condlflons and IS not expected 10 be

sensltwe to Iocatlon

~5Tfle estimate E based on an eshmate by EPRI Compressed A/r Energy .$(OfaQe COMMerCM/lzahon PoferWa/ op cd 1982 Mlm-CAES costs would of roughly the same magrmude

?sBased on 199o d!stlllate costs of $7 O/MM Bfu, and based on a 4,000 Btu/kWh dmchargmg

heat rafe fuel cost IS 28 mWs/kWh Charging-energy fuel.cost IS esflmated at 16 to 35 mills/kWh

based on an energy-ratio of O 78 kWh-in/kWh-ouf and an Incoming-electricity cosf of 20 to 35

m!lls/kWh The total fuel cost for CAES plant thus hes between 54 and 72 mdls/kWh (befween

(28 + 26) mills/kwh and (28 + 45) mills/kwh) (see Oeflnmons sechon of this appendix for

an explanation of fuel and !ncomlng-electrlclfy costs )
316 ● New Electric Power Technologies: Problems and Prospects for the 1990s

Fuel costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

‘Thlsrefers lolhelesting of asingle moduleal the Baffery Energy Storage Test (BEST) factitiy

In New Jersey The baffery hasnot been demoflsfrated In acommerclal-scale ~aultiyln~heUnfled

States

‘Ibid

3Thls figure refers toa demonstration uml which was In operation by the end of 1983 at the

BEST facflfly The bafferyls expected fobecapable ofproduclng 500 kWe, wrfha 1 hour dls.

charge rate, at the endoftistife, seeGNB Battertes, Inc 500-/r~e~ed~-,4c@ EJaffery for Peak.

ShawrrgErrerg ySforage Tesfmgarrd Eva/uafrorr (Palo Alfo,CA Electric Power Research Insfttute,

1S84), EPRI EM-3707

4Note however that an advanced-design zlnc-chlonde baffery operated from the endof 1983

to early t985 at the BEST facrhfy The unfl was capable ofproduclng 100 kWeover5-hourdis.

charge pertods

~The zinc-chlorlde battery comes (n 2 MWe modules, see Electrlc Power Research Institute,

ZnC/Mflefles brUOfi~Apphcations (Palo Alfo, CA EPR~ 1984) The lead-actdbaffery comes

m440k Westrrngs see Exlde Management &Technology Co Researcfr Deve/oprrrerrf and&monsfrafron of,4dvanced Lead-Ac/d f?a(fer/esfor UtrMy Load Leve/mg( Argonne IL Argonne National

Laboratory, August 1983] ANL/OEPM.83-6

‘Assumes 5-ho~rdwharge periods, or 100 MWh storage capaclly, see Alberf R Landgrebe,

‘Operaftonal Characlensticsof Htgh-Performance Baffenes for Stahonary Apphcations,” Advanced

Errergy Sysfems-Tfraw RotimOurFufure Proceedmgsof 19fh lntersoclety Energy Conversion

Engmeenng Conference, Aug 19-24 1984 San Francisco CA(U S American Nuclear Society

1984), paper 849122, pp 1091-1096

‘Assumes 5-hour discharge periods ora storage capacity under the high scenarloof 30,000

MWh Thehlgh eshmate assumes that 200 MWeworfh of baffenes are produced during each

of the folfowlng years 1991 1992, 1993, and 1994 This Is the level of productionon which

the captial cost esbmates are based These baffenes would beglnproducmg electrical powerm

1992, 1993, 1994, and 1995, respecfrvely Gwen 2-year leadtimes for baffery mstallafions, this

producf!on scenano assumes that ten 20-MWebaffery Installations aremtiated each year, beglnmng m 1990

CAssumes 5.hour discharge periods, or a storage capacty under the high scenario of 8,400

MWh The hlgheshmale assumes that 700 MWeworthofbaffenes are produced duflng each

of the followlng years 1991, f992, 1993, and f994 This IS the level of production on which

the cap~alcost eshmates are based These baffenes would begmproduction lnt992 1993, 1994,

and 1995, respectwely Gwen2-yearlead-times for battery mstallatlons thlsproductlon scenario

assumes that thlrfy-fwe 20-MWebaffery lnstallahons are mhatedeachyear, beglnnmgm f990

‘Consensus from OTA Workshop on Energy Storage, Washington OC, June 6, 1984, based on

2MWelnstalfahon shorfpermtitinghme(neghgible poliufion) factory assembly andslmplestimg requirements

‘

O

Theland used depends on theenergy densfly footpflnt (measuredly untisofkWh/sq meter)

of the batlery It ks assumed that Iead-acld and zmc-chlonde battefles have slmdarfootprmtsof

80-125 kWh/sq meter Thlsfootprmt eslmate Is consls!ent wrfh estimates made mthefollowmg

lhree documents l] PfxlIpC Symons Elecfrmhem!cal Engmeermg consultants, Inc “’Advanced

Technology Zmc/Chlorme Bafferies tor Electric UfrMy Load-Leveling “AdvarrcedErrergySysfems–

Tfre~f?o/e mOurFu(ure, op cfl pp 857-862 2)Landgrebe etd op cfl 1984 3]James

Oulnn, U S Oeparfment of Energy “OOE Mulflyear Planing,” ExferrdedAbsfracts SrXIfI DOE

E/ectiwhemCa/ Conkaclork%wew June 25-29 1984 (Washington,0C US OOE, June 1984~

CONF.840677 pp 64-67

‘IBased on arougheshmafe that the system would use l,OOOto 1,500 gallons per week This

figure assumes afufl discharge/chargecycle fwefimes each week Esf!maleprowdedby John

L Oel Monaco, Prmctpal Staff Engineer, Research, Pubhc Service Electric&Gas Co Newark,

NJ personal correspondent wtih OTA staff May 1, 1985

“Basedo naroughesfimafe that the system would use ll,OOOgallons each day Thlshgure

assumes afufldkicharge/charge cycle, and includes only the water requirement of the battery

system flself Mosf of the wafer IS used In evaporative coohng Estimate prowded by Monaco,

Op Clt 1985

27-50 mills/kWh32 29-58 mills/kWh33

~~FromEpRl Techfl~a/Assessmenf Guide (Palo Alto, CA EPRI, 1982). EPRl P-2410-sR, modlfied(rounded off) maccordance wthdrscus~onatOTAWorkshop on Energy Storage, op at, 1984

“Baffenesc analsoprowde splnnmg reserve and system regulafionfunchons seeEPRl UfIf@

L3affery Operafrons and Appficafions (Palo Affo, CA EPR~ March 1983), EPRI EM-2946-SR

“Glbbs& HIII Inc Overview Eva/uafion of rVewarrd Corrvenfmrra/ E/ecfrrca/ Generafmg Techno/og/es forffre /990s OTA contractor repofl, Sept 13 1984

lcThe number of cycles per year depefldsorl how the battery was used but a f19ure of 250

cycles/year IS offen used asa reasonable average In general the stacks (and sumps where

appropriate) would be replaced several times over the life of the system The remainder of the

baffery plant should last 30years

‘7Arnold Flckeff EPRI personal correspondence wflh OTA staff Aug 30 1984

‘° Flckett op clt 1984

“AC to AC efflclency, includes the 85 percent efhclency of the power-condlttomng equipment

20 Exlde Management&Technology Co op clt, 198 3

Z!Roundtr\p efficiency kwh ACoutdlvlded by kWh m including auxlflarles Efflclency lsCOnsfant w{th deployment because mult{ple umts are used loachieve various plant sizes Based on

Information prowdedb ythefollowmgs ources l)BOBrummet, etal Energy Development Assoclates, Zmc Cfr/or~de Baffery Sysfems /or E/ecV/c Uf///fy Energy Sforage paper prepared for

the 191h Annual Intersoctety Energy Conversion Engmeermg Conference, SAE San Francisco CA

August 1984, these est!mates apply to the 2 MWe commercial battery 2) OTA Workshop on Ener.

gy Storage op clt 1984 3) Energy Development Associates Deve/opmenf of(fre Zmc-Cfr/oride

Balfery /or Ufl(fy ,4PpOcaflons (Palo Alto, CA EPRI, June 1983) EPRI EM-3136

2’Consls!ent with plant size and plant efficiency, assuming plant charges and discharges al

20 MWe

2~Batte(ycoqS are &St measured In urufsof $/kWh Toconveri thegwen $/kwef!wmsto

$/kWh, dlvlde by fwe

ZdThe rarlgecorrespondsto the price of lead varying from $0 25/l bto$O 58/lb The Prlceas

of August f984was $030/lb see JJ Kelley, OrectorofResearch, EXIOECorp personal correspondence with OTA staff Aug 28, 1984 The cost ftgures assumea production of about 200

MWe/yr, see Exlde Management &Technology Co, op CI1 1983 However Ieadacldbatfery

prices should not be slrongly dependent on the vulume of production

23 Flckett, op CI1 1984

?* Exlde Management& Technology Co, op clt 1983

Z~The IOW cosf figure assumes a production volume of about 700 MWe/yr, see Energy Development Associates op clt 1983 The price of zinc-chlorlde batteries should be strongly dependent

on the level of production Based also on Information prowded by Fickett, op clt 1984 The

high figure IS based on an estimate prowded by P Sloshansi, Southern Cahforma Edison Co

personal correspondence with OTA staff Apr 10, 1985 The high estmate reflects the price penathes

which might be associated with early commercial units

?#Thls IS a Ievellzed value over 32 years, us!ng a dlscounf rate of 5 Percent The low value as”

sumes a hfellme of 4,000 cycles so that after 16 years parts totahng $300/kWe must be replaced

The high value assumes a hfeflme of 2000 cycles su that these $300/kWe parts must be replaced

after 8, 16, and 24 years

‘sF[ckett, op clt 198 4

j0Th15 M a Ievellzed value over 32 years, using a discount rate of 5 perCent The low value assumes a Ilfetlme of 4,003 cycles, so that after 16 years parts totahng $130/kWe must be replaced

The high value assumes a hfetime of 2,000 cycfes, so that these $130/kWe parts must be replaced

after 8, 16 and 24 years

3’ Flckett, op cIt , 1984

~?The charging-energy fuel-cost IS eshmated to be 27 to 50/mills kWh, based On an energY

ratio of O 7 to O 75 kWe-out/kWe-in and mcomlno-electrtctv cost In 1995 of 201035 mdls/kWh

(See Oeftmtlons sectton of this appendtx for an ;xplanatio; of Incom-mg-electricity costs )

jJThe charging.efle(gy fuel-cost IS estimated to be 29 to 58/malls kWh based on an ener9Y

ratto of O 6 to O 7 kWe-out/kWe-m and mcom{ng-electrtctty cost in 1995 of 20 fo 35 mills/kWh

(See Oeflnltlons section of this appendix for an explanation of Incommg-electricity costs )
App. A—Cost and Performance Tables “ 317

Table A-l O.—Summaries: Cost and Performance for Reference Installations

(based on tables A-1 through A-9 in this appendix)

Demo,

O 075 MWe

1995

10 MWe

5-200 MWe

2 years

67 acres

very little

95Y0

intermittent

20-35%

30 years

20-25%

$2,000 -

$3,000/kWe

15-23

mills/kWh

None

Commercial Commercial unit Commercial unit Commercial

650 + MWe none none 223 MWe

1995 1995 1995 1995

20 MWe 50 MWe 50 MWe 7 MWe

1,500- 12-1,830 MWe

2,900 MWe

1-2 years 3 years

300-2,000 8-20 acres

acres

none 3 milllon gal/day

95-98%

intermittent

20-35%

20-30 years

—

$900-

$1 ,200/

kWe

6-14

mills/kWh

None

$1,300-

$1 ,600/kWe

10-15

mills/kWh

20-70

mills/kWh

3 years

8-20 acres

41 million

gal/day

$1,500-

$1,800/kWe

10-15

mills/kWh

20-70

mills/kWh

1 year

1 acre

85-90%

base

700/0

30 years

7 0-90/0

$1,500-

$2,000/

kWe

10-15

mills/kWh

20-70

mills/ kWh
318 ● New Eiectric Power Technologies: Problems and Prospects for the 1990s

Table A.10.—Summaries: Cost and Performance for Reference Installations

(based on tables A-l through A-9 in this appendix) —Continued

Technologies

Fuel cells CAES Batteries

May 1985 technology status AFBC IGCC Large Small Maxi Mini Lead-acid Zinc-chlor

under const., &

planne

None 1.5 MWe

1995 1995

11 MWe 0.4 MWe

40-1,200 MWe

Installed U.S. capacit y none 100 MWe

Reference-system: general

Reference year ., ... 1990 1990

Reference-plant size ., 150 MWe 500 MWe

none

1990

220 MWe

O MWe

5-8 years

15 acres

360,000

gals/day

90-98%

none 0.5 MWe 0.1 MWe

1990

50 MWe

1995 1995

20 MWe, 20 MWe,

100 MWh 100 MWh

Reference year U.S. installed

capacity (est. ) 510-735

MWe

Lead-tim e 5-10 years

Land required ., ., ~ ., 90-218

acres

Water required ., 1.5 million

gal/day

200 MWe 0-100 MWe 0-600 0-2,80 0

MWe MWe

2 years 2 years

0.2-0.3 0.2-0,3

acres

11,000 200-300

gals/day gals/day

5-10 years

300-600 acres

3-5 years

0,5 acres

2 years

0.009-0.014

acre

very small

4,5-6,5 years

3 acres

acres

100,000

gals/day

3-5 million

gal/day

very small

85%

base

70%

30 years

35-40%

80-90%

variable

40-75%

30 years

40-44%

80-90%

variable

40-75%

20 years

36-40%

90-98% 90% 90%

peaking/inter, peaking/inter. peaking peaking

10-20% 1O-2O% 10% 10%

30 years 30 years 30 years 30 years

51%3 51%3 70-75 %

3 60-70 %

Reference-system: costs

Capital cost s $1,260-

1,580/kWe

$1,200-

$1 ,350/kWe

$565- $487- $600-800 $500-

$600/kWe $833/kWe kWe 3,000/

kWe

3.6 3.6 6-20 3-11

mills/kWh mills/kWh mills/kWh mills/kWh

42-63 42-63 27-50 29-58

mills/kWh mills/kWh mills/kWh mills/kWh

$700-

$3,000/kWe

$950”

$3,000/kWe

O&M cost s 7.66 6-12

mills/kWh mills/kWh

Fuel costs ., ., ., 17 15-17

mills/kWh mills/kWh

4,2-11.5

mills/kWh

27-30

mills/kWh

4.2-11.5

mills/kWh

30-33

mills/kWh
App. A—Cost and Performance Tables ● 319

Definitions

These tables provide basic information on each

technology. The data constitutes the basis for important

portions of the analysis. The cost and performance

characteristics listed in the tables are not definitive

predictions. Rather they are reasonable approximations of the status of the technology during the 1990s,

and are used to typify the technology during the last

decade of the century. Great uncertainty surrounds

these numbers and they should be treated for what

they are: educated guesses.

Where important subcategories of any particular

technology exist, and where their characteristics differ significantly from one subcategory to the next, the

subcategories are listed separately. For example, photovoltaics are divided between flat-plate and concentrator modules.

May 1985 Technology Status

This section provides information on the current status of the technology.

Level of Technology Development.–The technology already may be commercially deployed, or it may

be operating as a demonstration unit or pilot plant;

or plans may be underway to deploy such units.

Installed Capacity .–This section of the table describes the status of the technology as of May 1, 1985.

Only capacity installed and operating at that time is

included in the capacity totals.

Reference System: General Characteristics

Reference Year.— For each technology a reference

year is established. For technologies with lead-times

of 5 years or less, the reference year is 1995. For those

with lead-times longer than 5 years, the reference year

is 1990. All cost and performance figures refer to the

technology as it might appear in the reference year.

The cost and performance figures for that year are expected to typify the cost and performance of most of

the units which are deployed and operating by the

end of the century.

Plant Size.–The technologies examined in this report in many instances will be deployed in a variety

of sizes. The size listed in the tables is considered typical of plants installed in the 1990s. Considerable variation may occur from plant to plant, but most capacity installed during the 1990s is expected to be similar

in cost and performance to the reference plant.

1995 Deployment Level Scenario.–This is the total capacity expected to be operating by January 1 of

the reference year. The estimates are important be1 The cletl n Itlonis th.lt prok Icied I n the Elect rlc Pow er Research I nstlt uteifs

Technical Assessment Guide
320 • New Electric Power Technologies: Problems and Prospects for the 1990s

Capacity factors for intermediate systems are assumed

to fall between the two systems, at around 20 percent.

Where technologies are expected to operate under

more than one duty cycle, both are stated. Actual capacity factors may be quite different form the nominal values shown.

Lifetime.—This is the time over which the entire

plant would be operated commercially.

Efficiency .-This is the annual average plant efficiency, defined as the ratio of total net energy produced to total available energy contained in the fuel

or resource.

Reference System: Costs

All capital and O&M costs are reported in mid-1 983

dollars. Escalation of published costs, where required,

was performed as per the Handy Whitman Bulletin

Cost Index for electric utility construction:

Dat e Index

1/1 /78 159

7/’1 i78 166

1/1 ,’79 175

7/1 /’79 183

1/1 1’80 193

7/I /’80 I 99

1/1 )81 210

2 1 9

225

2 3 0

233

2 3 8

242

plant cost o r

TPC) generally represent approximate budgetary overnight constructed costs for the indicated location including an average allowance of 5 to 10 percent for

engineering and home office overhead and fee and

a 20 to 25 percent allowance for overall contingence.

Thus:

TPC = Bare Erected Cost (BEC) X (1 .05 to 1,1) X (1 2 to 1.25)

Capital costs do not include interest and escalatio n

during construction, land costs, and other costs suc h

as royalties, preproduction, startup, initial catalyst/

chemical charges, and working capital.

O&M Costs.–These are “first year” costs, the average O&M costs expected during the reference year.

In the case of both battery and fuel cell installation,

a portion of cost of periodically replacing batteries or

fuel-cell stacks during the installation’s lifetime is included in the O&M costs.

Fuel Costs.— Electricity and fuel costs are first year

annual average costs based on a typical plant in the

reference year. Electricity for CAES and batteries is assumed to be generated by a base load plant, at prices

expected to range from 20 to 35 mills/kWh.z Fuel

prices are based on 1983 fuel prices, with assumed

real escalation rate of 1 percent per annum for coal,

and 2 percent per annum for oil and gas. The 1983

fuel prices used in making the reference year estimates

are:

Fuel) (in dollars per million British thermal units (Btu))

O i l

~Th IS IS based on an estl mate provided by WI Illam BI rk, Electrlc Power Research Institute, personal correspondence with C)TA staff, tMay 7, 1985 Mr

Birk indicated that EPRI uses a figure ot 25 mills/kWh; for a range, he 5uggested 20 to 30 mills/kwh This analysis uses a range with a higher upper

limit, 20 to 25 mills/kWh.

~ From U .S,, Department of Energy, Energy I nt’ormatlon Adml n istratlon,

Nov. 27, 1984 Average cost of fossil fuel receipts for steam electric plants

of 50 MWe capacity or larger, 1983
Index
Index

ACE. See Area control error CAES. See Compressed-air energy storage facilities

Adjusted reserves, 187, 203, 204, 206 California-Southern Nevada Power Area (CSNPA), 183,

Advanced lead-acid batteries, 122, 123, 125, 127, 281, 189, 210, 211

282

Advanced meters, 151-152

AFBC. See Atmospheric fluidized-bed combustion

AFUDC. See Allowance for Funds Used During

Construction

Alaska Systems Coordinating Council (ASCC), 211-212

Allis Chalmers Corp., 273

Allowance for Funds Used During Construction

(AFUDC), 48, 68

Alternative technologies. See New technologies

Amorphous-silicon flat-plate modules, 79-80, 257

ANMPA. See Arizona-New Mexico Power Area

Aquifer reservoirs, 121, 122

Area control error (ACE), 164, 177-179

Arizona-New Mexico Power Area (ANMPA), 184, 189

ASCC. See Alaska Systems Coordinating Council

Atmospheric fluidized-bed combustion (AFBC)

commercial prospects, 22-23, 112-113, 115, 278

cost and performance, 115-117, 311

current activities, 140

environmental issues, 243, 245

industry development, 277-278

nonutility profitability analysis, 235, 236, 239

overview, 112-113

regional opportunities, 200

technology, 113-115

utility cost analysis, 224

Automatic generation control, 176-179

Avoided costs, 23, 30, 35, 42, 69, 190-192, 240, 241,

294, 297-298

Balance of system (60 S), 83

Battery Energy Storage Test (BEST) Facility, 280, 281

Battery storage

commercial prospects, 24, 118, 122-123, 281-282

cost and performance projections, 123-129, 316

industry development, 280-281

load management use, 157

overview, 122-123

regional opportunities, 200, 213

technology, 20, 123, 127

utility cost analysis, 224

Bechtel Power Corp., 273

Beckjord Unit 1, 140

BEST Facility. See Battery Energy Storage Test Facility

BGC. See British Gas Corp.

Binary cycle systems, 23, 99-102, 267

BOS. See Balance of system

Breakeven analysis, 234-238

British Gas Corp. (BGC), 273, 275

Brunner Island Station, 140

Bubbling beds, 114-115

Bulk power transactions, 30, 65-66, 203-208, 210-213,

215

Bureau of Land Management, 268

Capacity margins, 187

Capacity planning, 68-69

Cash return, 234

Central controllers, 154-155

Central Hudson Electric & Gas, 172

Central receivers, 24, 84, 88-89, 259, 261

CG&E. See Cincinnati Gas & Electric Co.

Cincinnati Gas & Electric Co. (CG&E), 140

Circulating beds, 115

Cogeneration, 23, 30, 42, 70, 112, 113, 115, 116, 165,

198-199, 204, 210, 212, 215, 270, 278

Colorado Ute Electric Association, Inc., 140

Combustion technologies. See Atmospheric fluidizedbed combustion; Conventional technologies;

Integrated gasification/combined-cycle powerplant

Commercial deployment

accelerated development, 2-3

advanced meters, 152

atmospheric fluidized-bed combustion, 112-113, 115,

277-278

batteries, 122-123, 280-282

compressed air energy storage, 121, 278-280

demonstration needs, 34-35

fuel cells, 102-103, 269-272

geothermal prospects, 98, 100, 266-269

industry factors and, 32-33

integrated gasification/corn bined-cycle powerplants,

108, 110, 272-277

new technologies, 3-4, 22-25

photovoltaic systems, 78-80, 253-258

solar thermal-electric powerplants, 86, 87, 89-91,

259-262

tax incentives and, 36

wind turbines, 92-93, 262-266

Commercial sector, 145, 150

Communications technologies, 155-156

Comparative cost analysis, 222-225, 246-248

Comparative profitability analysis, 234-241, 248-250

Compressed air energy storage (CAES)

commercial prospects, 24, 118, 121, 279-280

cost and performance projections, 121-122, 315

environmental issues, 121-122

industry development, 278-279

overview, 118-121

regional opportunities, 200

technology, 20, 118-121

utility cost analysis, 224

Concentration photovoltaic systems, 78-79, 83, 257

ConEd. See Consolidated Edison Co.

Conservation, 64, 157, 188, 215

Consolidated Edison Co. (ConEd), 173

Construction costs, 44, 46

Construction Work in Progress (CWIP), 48, 192

Conventional technologies, 19, 25, 64, 141, 235, 236.

See a/so Load management; Plant betterment

323
324 ● New Electric Power Technologies: Problems and Prospects for the 1990s

Cool Water demonstration project, 22, 110-111, 273,

275

Cooperative agreements, 3, 270

Cost analysis, 222-225, 246-248

Cost and performance

alternative technologies, 21

atmospheric fluidized-bed combustion, 115-117, 311

batteries, 123-129, 282, 316

compressed air energy storage, 121-122, 280, 315

conventional generating technologies, 141

data needs, 258, 265, 275-276

fuel cells, 103-108, 272, 313

geothermal systems, 98, 100-103, 268, 309

improvement needs, 257, 268, 272, 275, 280, 282

integrated gasification/combined-cycle powerplants,

110-112, 275-276, 312

photovoltaics, 79-84, 257, 258, 304

plant betterment projects, 137, 139

policy options, 286-289

solar thermal-electric systems, 86-91, 306-307

wind turbines, 23, 93-96, 265, 308

Cross-technology comparison

issues, 243, 245

nonutility producers, 234-241

utilities, 224

Crystalline silicon cells, 79, 257

CSNPA. See California-Southern Nevada Power Area

Current harmonics, 163-164, 167

CWIP. See Construction Work in Progress

DCP, See Design change package

Debt service coverage ratio, 62, 234

Decision-logic technologies, 156-157

Demand growth, 8, 44, 46, 59, 183, 185, 187, 203-207,

211, 212, 214, 227

Demand management, 143

Demand-subscription service meter, 152

Department of Energy, 29, 171, 259, 267, 270, 273,

274, 277, 280

Deregulation, 35, 298

Design change package (DCP), 136

Detroit Edison Co., 274

Developing technologies. See New technologies

Direct control systems, 152

Dispatchable applications, 19, 75

Dispersed generation sources (DSGS), 29, 68

costs of interconnection, 169-170

electric system operations factors, 176-179

electric system planning factors, 174-176

guidelines for interconnection, 170-174, 295

interconnection issues, 162-165

interconnection performance, 165-166

interconnection requirements and, 258, 266, 269, 272

overview, 161-162

policy options, 295, 299

protection issues, 167-169

regional opportunities, 211

technology, 163

Distributed control systems, 154, 156

Distribution planning, 175-176, 220-221

Diversification, 64, 66, 70, 296-297

Dow Chemical, 273, 274

DSGS. See Dispersed generation sources

Dual-flash systems, 97-99, 267

Duke Power Co,, 140

Dynamic stability, 179

East Central Area Reliability Coordination Agreement

(ECAR), 187, 188, 203

ECAR. See East Central Area Reliability Coordination

Agreement

EDA. See Energy Development Associates

Electricity demand growth. See Demand growth

Electric power industry, 7-8, 10-12, 58. See a/so

Nonutility power generation; Utility investment

Electric Power Research Institute (EPRI), 29, 147-149,

154, 171, 175, 267, 270, 273-275, 277-281, 299

Electric Reliability Council of Texas (ERCOT), 183, 187-

200, 204

Empire State Electric Energy Research Corp., 273

End-use sectors, 143, 145-146

Energy Development Associates (EDA), 281

Energy Sciences, Inc., 263

Energy storage, 117-118. See also Battery storage;

Compressed-air energy storage

Environmental issues

atmospheric fluidized-bed combustion, 243, 245

combustion technologies, 243, 245

compressed air energy storage, 121-122

cross-technology comparison, 243-244

fuel cells, 245

geothermal systems, 98, 100, 245

integrated gasification/combined-cycle plants, 243,

245, 276-277

photovoltaic systems, 80-81, 245

plant betterment, 135, 139

regional, 203, 205, 207, 214

solar thermal-electric powerplants, 91, 245

wind turbines, 93, 245

Equipment cost and performance, 257, 268, 272, 275,

282

ERCOT. See Electric Reliability Council of Texas

Federal Energy Regulatory Commission (FERC), 192, 211

Federal Power Act of 1935, 43-44

Federal support, 255, 259, 260, 262, 267, 268, 270,

273, 274, 278-280, 286-287

FERC. See Federal Energy Regulatory Commission

Financial performance, 46, 48-49, 55-56, 60-61, 68

Financing, 46, 230-234, 259, 260, 263-264

Flat-plate photovoltaic systems, 78-80, 83

FLEXPOWER, 281

Florida Power Corp., 140

Fluidized-bed combustion, 20. See ako Atmospheric

fluidized-bed combustion

Flywheels, 118

Foreign competition, 24, 257, 258, 263, 271, 280-281

Foreign markets, 4, 258, 263, 266, 288-289

Fuel cells

commercial prospects, 23, 102-103, 271-272

cost and performance projections, 103-108, 313
Index ● 3 2 5

environmental issues, 245

industry development, 269-271

nonutility profitability analysis, 235, 238, 240

overview, 102-103

regional opportunities, 200, 213

technology, 20, 103

utility cost analysis, 224

Fuel prices, 44, 225

Fuel reliance, 194-195, 203-207, 209-212, 214-215

Fuel supply contracts, 232

Fuel Use Act. See Powerplant and Industrial Fuel Use

Act of 1978

Full-avoided cost, 69

Gas Research Institute (GRI), 270

General Electric, 273

Generating capacity, 8, 25, 29-30, 61-62, 225, 229, 230

Generation mix, 44

Generation system planning, 174-175, 220

Georgia Power & Light Co., 168

Geothermal Loan Guarantee Program, 267

Geothermal power stations

binary cycle systems, 23, 99-102, 267

commercial prospects, 23, 98, 100, 267-269

cost and performance projections, 98, 100-103, 309

dual-flash systems, 97-99, 267

environmental issues, 98, 100, 245

industry development, 266-267

nonutility profitability analysis, 235, 236, 240, 241

overview, 96

regional opportunities, 31, 199, 210, 212, 213

technology, 20, 96-100

utility cost analysis, 224

Government-owned power systems, 58

Great Plains Gasification Associates, 273

GRI. See Gas Research Institute

Harmonic voltages, 163-164, 167

Hawaiian Electric Renewable Systems, Inc., 213

Hawaii Electric Light Co. (HELCo), 178

Hawaii region, 212-214

HELCo. See Hawaii Electric Light Co.

HFM. See High-frequency modulation

High-frequency modulation (HFM), 167-168

Houston Lighting & Power, 177

IEEE. See Institute of Electrical and Electronic Engineers

IGCCs. See Integrated gasification/combined-cycle

powerplants

Illinois Power Co., 273

Induction generators, 163-164, 169

Industrial sector, 145, 150

Information collection, 289

Innovative rates, 147-148, 150

Institute of Electrical and Electronic Engineers (IEEE), 29,

171

Insurance coverage, 140

Integrated gasification/combined-cycle powerplants

(IGCCs)

commercial prospects, 22, 108, 110, 275-277

cost and performance projections, 110, 312

environmental issues, 243, 245, 276-277

industry development, 272-275

overview, 108, 110

regional opportunities, 200

technology, 20, 108

utility cost analysis, 224

Interconnection

costs, 169-170

definition of terms, 164

issues, 162-165

performance, 165-166

policy options, 295, 299

protection factors, 167-169

requirement effects, 69, 258, 266, 269, 272

standards, 29, 170-174, 295 See a/so Power transfers

Interest coverage ratio, 62, 227

Internal rate of return (lRR), 234, 238-240

International cooperation, 270

Interregional transmission. See Power transfers

Inverters, 163

Investment decisions. See Nonutility power generation;

Utility investment

Investor-owned utilities (IOUs), 58, 64, 147, 212

Investor Responsibility Research Center (lRRC), 229, 240

IOUs. See Investor-owned utilities

IRR. See Internal rate of return

IRRC. See Investor Responsibility Research Center

Japan Cool Water Program Partnership, 273

Japanese programs, 270-271, 280-281

Joint ventures, 233, 270

Kellog Rust, 273

LaJet Energy Co., 194, 260

LaJet, Inc., 90, 91, 260

Land access, 265, 268-269

Lead-acid batteries, 122, 123, 125, 127, 281, 282

Lead-times

atmospheric fluidized-bed combustion, 23, 117

batteries, 123

compressed air energy storage, 24, 122

fuel cell systems, 104

geothermal systems, 23, 98, 1 0 1

integrated gasification/corn bined-cycle combustion,

22, 108, 110

investment decisions and, 62

photovoltaic systems, 81

policy options, 287-288

solar thermal-electric powerplants, 91

wind turbines, 94

Leasing, 233, 268-269

Levelized busbar costs, 222, 224, 225, 246-248

Lewis Research Center, 270

Licenses, 192, 265, 269, 272, 276, 280, 282, 294

Life extension. See Plant betterment

Lifetime rate requirements, 55
326 ● New Electric Power Technologies: Problems and Prospects for the 1990s

Limited partnerships, 233, 260, 263-264

Load control

activities, 148-151

systems, 152-157

Load dependence, 68

Load forecasting, 220

Load-leveling, 117

Load management

business strategies, 64

constraints, 21, 157-158

customer controlled technologies, 157

dispersed source generation use, 299

end-use sector variables, 143, 145-146

innovative rate activities, 147-148, 150

investment factors, 226-227

load control activities, 148-151

overview, 142-143

peak load reduction potential, 149-151

prospects for, 25, 28

regional opportunities, 30, 188-190, 213-215, 226-227

technologies, 20, 151-157

variables, 146-147

LOLP. See Loss of Load Probability

Longevity improvements, 136

Loss of Load Probability (LOLP), 54-55

Lurgi Gesellschaften, 273

Luz Engineering Corp., 259-260

Luz Industries (Israel) Ltd., 260

MAAC. See Mid-Atlantic Area Council

McDonnell Douglas, 260

MAIN. See Mid-America Interpool Network

MAPP. See Mid-continent Area Power Pool

Meters, 151-152, 168-169

Mid-America Interpool Network (MAIN), 187, 195,

205-206

Mid-Atlantic Area Council (MAAC), 183, 188-190,

204-205

Mid-continent Area Power Pool (MAPP), 187, 200,

206-207

Minimum revenue requirement approach, 222-225

Moonlight program, 271, 280

Mounted-engine parabolic dish, 90, 91, 262

Municipal utilities, 58, 148

NARUC. See National Association of Regulatory Utility

Commissioners

NASA. See National Aeronautics and Space

Administration

National Aeronautics and Space Administration (NASA),

270

National Association of Regulatory Utility

Commissioners (NARUC), 188

National Electric Code (NEC), 29,.171

Natural gas restrictions, 3, 35, 60, 211, 277, 297

NEC. See National Electric Code

NERC. See North American Electric Reliability Council

New Source Performance Standards (NSPS), 135, 139

New technologies

accelerated development, 2-3

advantages, 1-2, 67-68

commercial generating prospects, 3-4, 22-25

comparative cost analysis, 222-225, 246-248

cost and performance, 21

current activities, 25, 70, 129

description, 20

disadvantages, 2, 68-69

industry characteristics, 32-33

investment in, 31-32, 42, 59-60, 227-228

lead-times, 21-22

nonutility profitability analysis, 234-241, 248-250

overview, 19-21, 75

policy goals, 33

policy options, 33-36

regional opportunities and, 199-200, 204-209, 211-214

tax incentives, 36-37 See a/so Dispersed generation

sources; Nonutility power generation

New York State Electric & Gas, 171

Nondispatchable applications, 19, 68, 75

Nonutility power production

accelerated development, 3, 4

cross-technology profitability comparison, 234-241,

248-250

investment decisionmaking, 32, 231-234

history, 228

market characteristics, 228-229

policy options, 290-295

producer characteristics, 229-230

role of, 11

utility interaction, 68-69

See also Dispersed generation sources

North American Electric Reliability Council (NERC), 8,

183, 185

Northeast Power Coordinating Council (NPCC), 187,

189, 190, 195, 200, 207-208

Northwest Power Pool Area (NWPP), 210

NPCC. See Northeast Power Coordinating Council

NSPS. See New Source Performance Standards

Nucla facility, 140

Nuclear power, 49, 52-53, 62, 64, 204-209, 211

NWPP. See Northwest Power Pool Area

Oak Creek Station, 140

Obsolescence, 257

Occupational Safety and Health Administration (OSHA),

167

Operations management, 174, 176-179

Operations planning, 176

OSHA. See Occupational Safety and Health

Administration

Overseas markets, 4, 258, 263, 266, 288-289

Ownership structure, 230-232

Pacific Gas & Electric (PG&E), 57, 63

Parabolic dishes, 24, 84-85, 90-91, 260-262

Parabolic troughs, 24, 85, 89-90, 259-262

PCS. See Power-conditioning subsystems

Peak load reduction, 149-151

Pennsylvania Power & Light Co. (PP&L), 140

PEPCO. See Potomac Electric Power Co.
Index . 327

Performance test and analysis, 136, 137

Permits, 192, 265, 269, 272, 276, 280, 282, 294, 297

PFBC. See Pressurized fluidized-bed combustor

PG&E. See Pacific Gas & Electric

Phosphoric Acid Fuel Cell Program, 270

Photovoltaics (PVS)

commercial prospect, 23-24, 78-80, 255-258

cost and performance projections, 80-81, 83-84, 304

environmental issues, 80-81, 245

industry development, 253-255

interconnection factors, 178-179

nonutility profitability analysis, 235, 238-41

overview, 77-80

regional opportunities, 211

technology, 20, 77-80

utility cost analysis, 224

PIFUA. See Powerplant and industrial Fuel Use Act

Planning, 174-176, 220-221, 299

Plant betterment

business strategies, 64-65

cost and performance, 137, 139

current activities, 140

insurance coverage, 140

objectives of, 135-137

overview, 133, 135

prospects for, 25

regional opportunities, 30, 195, 215

regulation of, 139, 226, 227

utility cost analysis, 224, 226

Policy options

cost and performance related, 286-289

dispersed generation related, 295, 299

nonutility related, 290-295

overview, 285

utility related, 295-298

Port Washington Station, 140

Potomac Electric Power Co, (PEPCO), 140, 274

Potomac River Station, 140

Power-conditioning subsystems (PCS), 80, 81, 83, 167-

168, 170

Power Cost Equalization Program, 211-212

Power factor, 164

Powerplant and Industrial Fuel Use Act of 1978, 35,

122, 211, 261, 277, 280, 297

Power quality, 163-164, 167-168

Power sales contracts, 232-233

Power transfers, 30, 65-66, 203-208, 210-213, 215

PP&L. See Pennsylvania Power & Light Co.

Predispatch problem, 176

Pressurized fluidized-bed combustor (PFBC), 112

Prevention of Significant Deterioration (PSD), 139

Production Tax Credit (PTC), 36, 291

Productivity improvements, 136

Profitability, 60-61

Profitability analysis, 234-241, 248-250

Project financing, 231-233

Protection and control subsystems, 162-163, 165-166

PSD. See Prevention of Significant Deterioration permits

PTC. See Production Tax Credit

Publicly owned power systems, 58, 147

Public utility commissions, 11, 34-35

Public Utility Regulatory Policies Act of 1978 (PURPA),

3, 4, 22, 35, 42, 228, 230, 294-295, 297-298

Pumped hydro plants, 118

PURPA. See Public Utility Regulatory Policies Act of

1978

PVS. See Photovoltaics

R&D. See Research and development

Reactive power, 163, 164

Rate of return, 234, 238-240

Rates

battery storage and, 282

determination of, 223

innovative, 147-148, 150

load management and, 147-148, 150

minimizing, 55

nonutility generation and, 69

regulation, 190-191

research and development cost factors, 69

shock effects, 67

Real-time operations, 176

Regional differences

avoided cost, 190-191

definition of regions, 183

demand growth{ 183, 185, 187, 214

generation mix, 29-30

fuel reliance, 194-195, 214

load management, 30, 188-190, 213-214, 226-227

nonutility generation, 198-200

plant betterment opportunities, 195, 215, 226-227

power transfers, 30, 197-198, 203

region profiles, 203-214

reliability criteria, 30-31

renewable resources, 31

small-scale system regulation, 192

utility choice variables, 183, 214-215

Regional distribution

load control activities, 148-149, 151

Rehabilitation. See Plant betterment

Reliability, 30-31, 54-55, 67-68, 137-138, 197

Remote-engine parabolic dish, 90

Renewable Energy Tax Credit (RTC), 3, 24, 36, 241,

255-257, 260, 262, 264, 267, 268, 290-294

Research and development (R&D)

accelerated development and, 3

atmospheric fluidized-bed combustion, 11 7

battery storage, 281

fuel cells, 108, 270-272

geothermal power, 267, 268

integrated gasification/corn bined-cycle plants, 274-275

opportunities for, 25

policy options, 33-35, 287-288, 295-296, 299

power transmission system, 213

rate setting and, 69

role of, 12

solar thermal-electric powerplants, 87, 90

utility activities, 70

wind turbines, 95-96
328 ● New Electric Power Technologies: Problems and Prospects for the 1990s

Reserve margins, 30-31, 185-187, 203, 204, 206, 208,

209, 214, 220

Residential sector, 143, 145, 147-151

Resource assessment, 257, 261, 264-265, 268, 289

Resource availability, 199-200, 215

Risk, 57

Risk reduction, 232

RMPA. See Rocky Mountain Power Area

Rock caverns, 119, 122

Rocky Mountain Power Area (RMPA), 210

Rotating generators, 163, 164

RTC. See Renewable Energy Tax Credit

Rural electric cooperatives, 58, 148

Salt reservoirs, 119, 121, 122

Sandia Laboratory, 167, 168, 170

SEGS. See Solar Electric Generating System

Sensitivity analyses, 224-225, 238, 240-241

SERC. See Southeastern Electric Realibility Council

Shawnee Steam Plant, 115, 277, 278

Shell, 273, 275

Short-period analysis, 57

Silicon, 83

Single phase electromechanical watt-hour meters, 151,

152

Single-phase power, 164

Single watt-hour meters, 168

Siting policies, 192, 194, 297

Small Power Producer (SPP), 233

Sodium-sulfur batteries, 123

SOHIO, 273

Solar Electric Generating System (SEGS), 89, 90, 260,

261

Solar Energy Research Institute, 259

Solar One pilot facility, 259

Solar ponds, 85-87, 89, 259

Solar technologies, 76-77, 175, 200, 212-214

commercial prospects 24, 86-87, 89-91, 260-262

cost and performance projections, 91, 306-307

environmental issues, 91, 245

industry developments, 259-260

nonutility profitability analysis, 235, 238, 241

overview, 86-91

regional opportunities, 31

technology, 20, 84-86

See also Photovoltaics; Solar thermal-electric

powerplants

Solar thermal-electric utility cost analysis, 224

Solar troughs, 24, 85, 89-90, 259-262

Sole ownership, 231-232

SOLMET data, 257

Southeastern Electric Reliability Council (SERC), 187-

190, 195, 208-209

Southern California Edison, 63, 260, 273, 275

Southwest Power Pool (SPP), 187, 189, 195, 200,

209-210

Soyland Electric Cooperative, 121, 122, 279

Special rates, 147-148, 150

Spinning reserve, 117

SPP. See Small Power Producer; Southwest Power Pool

Standards

interconnection, 170-174, 295

photovoltaic equipment, 258

wind turbines, 265

Storage, 117-118.

See a/so Battery storage; Compressed-air energy

storage

Superconducting magnetic energy storage, 118

Susitna Project, 211

Sustainability, 61

Synchronous generators, 163, 164, 169

Synthetic Fuels Corp. 273, 274

System regulation, 117

Tax incentives, 3, 23, 24, 36, 240-241, 254-260, 262,

264, 266-269, 272, 290-294

Technology demonstration needs, 268, 272, 275-276,

281-282, 286-287

Tennessee Eastman Co., 273

Tennessee Valley Authority (TVA), 115, 140, 273, 277,

278

Texaco, Inc., 273

THD. See Total harmonic distortion

The Geysers, California, 266

Thermal storage, 157

Three-phase power, 164

Toshiba, 270

Total flow systems, 96

Total harmonic distortion (THD), 163

Transient stability, 179

Transmission facilities, 265-266, 269, 294

Transmission planning, 175, 220-221

Treasury Department, 240

TVA. See Tennessee Valley Authority

UCGA. See Utility Coal Gasification Association

Uncertainty sensitivity, 224-225, 240

United Stirling, 260

United Technologies, 270

Utility Coal Gasification Association (UCGA), 275

Utility-grade relays, 164, 171-172

Utility grid, 162-163. See a/so Interconnection

Utility industry structure, 58

Utility investment

business strategies, 63-70

commercial deployment role, 34

comparative cost analysis, 222-225, 246-248

constraints, 219-220

current activities, 70

demand growth and, 46, 48-49, 52-53

extent, 42

financial criteria, 61-62

new technology prospects, 31-32, 53-54, 59-60,

227-228

objectives, 54-56

operations factors, 176-179

overview, 41

planning factors, 174-176, 220-222
Index ● 3 2 9

policy options, 295-298

strategic options, 225-227

tax incentives and, 291-292

trade-off decisions, 56-60

Value studies, 174-175

Virginia Electric Power, Co., 274

Warranties, 258, 265

Washington Public Supply System, 49

WEPCO. See Wisconsin Power & Light

Western Systems Coordinating Council (WSCC), 183,

185, 189, 190, 195, 200, 210-211

Wind turbines

commercial prospects, 23, 92-93, 264-266

cost and performance projections, 93-96, 308

environmental issues, 93, 245

generating capacity, 230

industry development, 92, 262-264

interconnection factors, 177-179

nonutility profitability analysis, 235, 236, 238, 240,

241

regional opportunities{ 31, 200, 211-214

tax incentive effects, 23, 36, 290, 291

technology, 20

utility cost analysis, 224, 225

Wisconsin Electric Power Co. (WEPCO), 135-136, 140,

169

Wood River facility{ 273

WSCC. See Western Systems Coordinating Council

Zinc-bromide batteries, 122-123

Zinc-chloride batteries, 122, 281, 282