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

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

July 1985

NTIS order #PB86-121746



R e c o m m e n d e d C i t a t i o n :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 DocumentsU.S. Government Printing Office, Washington, DC 20402



Foreword

This report responds to a request from the House Committee on Science and Technol-ogy and its Subcommittee on Energy Development and Applications to analyze a range ofnew electric power generating, storage, and load management technologies.

OTA examined these technologies in terms of their c urrent a nd expec ted c ost and pe r-formance, 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 numberof strategies by electric utilities to enhance flexibility in accommodating future uncertain-ties, The study also addresses the circumstances under which these technologies could playa significant role in U.S. electric power supply in the 1990s. Finally, alternative Federal pol-icy initiatives for accelerating the commercialization of these technologies are examined,

OTA rec eived sub sta ntial help from m an y orga niza tions an d ind ividu als in the c ourseof this study. We would like to thank the project’s contractors, who prepared some of thebackground analysis, the project’s advisory panel and workshop participants, who providedguidance and extensive critical reviews, and the many additional reviewers who gave theirtime to ensure the accuracy of this report.

JOHN H. GIBBONSDirector

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Related OTA Reports

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NOTE: Reports are available through the U.S. Government Printing Office, Superintendent of Documents, Washington, DC 20402, (202783-3238; 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, OTAEnergy, 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

Lillia n Cha p m a n Ed na Sa und e rs

Contractors and Consultants

Gibbs & Hill, Inc., New York, NYBattelle Memorial Institute, Columbus, OH

Investor Responsibility Research Center, Inc., Washington, DCLotus Consulting Group, Palo Alto, CAPeter Hunt Associates, Alexandria, VA

Electrotek Concepts, Inc., Mountain View, CAStrategies Unlimited, Inc., Palo Alto, CA

E. S. Pechan Associates, Washington, DC

Howard Geller, Washington, DCPaul Maycock, Arlington, VA

David Sheridan, Chevy Chase, MD

Other OTA Contributors

Jenifer Robison Rob ert M. Friedma n Eugene FrankelPaula Wolferseder

‘ Project Director through Mdy 1984



New Electric Power Technologies Advisory Panel

George Seidel, Chairman Brown University

Edward BlumMerrill Lynch Capital Markets

Byron R. BrownEl. du Pent de Nemours & Co.

Bill D. CarnahanCity of Fort Collins Light & Power

Mark CooperConsumer Federation of America

Brian E. CurryNortheast Utilities

Janice G. HamrinIndependent Energy producers

William B. HarrisonSouthern Co. Services, inc.

Eric LeberAmerica n C hemica l Soc ietyl

Paul MaycockPhotovoltaic Energy Systems

Charles McCarthySouthern California Edison Co.

Anne F. MeadNew York State Public Service Commission

Alan MillerWorld Resources Institute

Bruce W. MorrisonWestinghouse Electric Corp.

Fred SchweppeMassachusetts Institute of Technology

Jon VeigelNorth 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

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Workshop on Regulatory Issues Affecting DevelopingElectric Generating Technologies

Sam Brown David Owens Andrew VarleyVirginia Electric Power Co. Edison Electric Institute Iowa Commerce Commission

George Knapp Eliza b eth Ro ss Jon WellinghoffNixon, Hargrove, Devans & Birch, Horton, Bittner, Office of the Attorney General

Doyle Pestinger & Anderson State of Nevad a

Therre ll Murp hy, Jr. Ric hard Sc hulerSo ut he rn C o. Se rvic e s, Inc . C o rn ell Un iv ersit y

Workshop on Investment Decisions for Electric Utilities

James Stukel, Chairman University of Illinois

jack DaveyMiddle South Utilities

Scott FennInvestor Responsibility

Research Center, Inc.

Jerry HuckIllinois Power Co.

Sally HuntConsolidated Edison Co.

Jim LilesFederal Energy Regulatory

Commission

Workshops on CostNew Electric Power

Lynn MaxwellTennessee Valley Authority

Charles MengersPhiladelphia Electric Co.

Thomas MocklerStandard & Poor’s

James MulvaneyElectric Power Research

Institute

Dave J. RobertsGeneral Public Utilities

Service Corp.

John L. SeeIkeFlorida Power & Light

and Performance ofTechnologies

James W. Bass, IllTennessee Valley Authority

Robert A. BellConsolidated Edison Co.

Elliott BermanARCO Solar, Inc.

Chris BluemleSouthern California Edison Co.

Peter B. BosPolydyne Corp.

J.J. BuggyWestinghouse Electric

Jay Carter, Jr.Carter Systems

Thomas A.V. CasselTechnecon Consulting

Inc.

G.P. James DehlsonZond Wind Resource

Development

Group,

Sam ShepardSouthern Co. Services, Inc.

Dwain F. SpencerElectric Power Research

Institute

Rodney StevensonUniversity of Wisconsin

Carl WeinbergPacific Gas & Electric Co.

H.D. WilliamsonHawaiian Electric Co., Inc.

David R. WolcottNew York State Energy

Research & DevelopmentAuthority

Carel DeWinkelWisconsin Power & Light

John DorseyMaryland Public Service

Commission

Charles M. FinchMcDonnell Douglas

AstronauticsRichard W. Foster-PeggWestinghouse Electric

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Robert GreiderGeothermal Resources

International

Ray HallettMcDonnell Douglas

Astronautics

Waker A. HansenBabcock & Wilcox

Bernard HastingsDetroit Edison Co.

Robert LacySan Diego Gas & Electric Co.

Janos LaszloASME Congressional FellowSenator Hecht’s Office

Peter Lewispublic Service Electric & Gas

Roger LittleSpire Corp.

William J. McGuirkArizona public Service Co.

Tom Morton Jeff SerfassFluor Engineers & Constructors, Fuel Cell Users Group

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Acknowledgments

In addition to panel members and workshop participants, many institutions and individuals contributed tothis report b y p roviding informa tion, ad vice, a nd substantive reviews of d raft materials.OTA thanks the follow-ing who took the time to provide information or review all or part of the study.

Institutions

Applied Economics, Inc.

ARCO Solar Inc.Argonne National LaboratoryArizona Public Service Co.American Public Power AssociationBabcock & WilcoxBattelle Pacific Northwest LaboratoriesBirch, Horton, Bittner, Pestinger &

AndersonBrown-Boveri Corp.California Energy CommissionCarter SystemsCalifornia Energy CommissionCongressional Research ServiceConsolidated Edison Co.Consumer Energy Council of America

Cornell UniversityDetroit Edison Co.Edison Electric InstituteElectric Power Research InstituteElectrotek Concepts, Inc.Energy Conversion Alternatives, Ltd.Energy Development AssociatesEnergy Information AdministrationEnvironmental Policy InstituteEnvironmental Protection AgencyEXXONFederal Energy Regulatory

CommissionFlorida Power & LightFluor Engineers & Constructors, Inc.Fuel Cell Users Group

Individuals

Marshall AlperSeymour Al pertBob AnnanJames ArnettC.J. AulisioShimon AwerbachDon BainRobert BarberRichard BellowsMichael BennetSandra Bodmer-TurnerJames Bresee

Sam BrownLarry BruneelDoug CarterDon CeriniBill ColemanWilfred ComtoisAlice Condren

Marie CorioGeorge CraneDavid CurticeMike DeAngelesEdgar DeMeoBruce EdelstonWalter EsselmanSherman FaireMerrilee FellowsArnold FickettTony FungDom Geraghty

Tom GrayLeon GreenRobert HaydenEvan HughesRobert JohnsonAlvin KaufmanKevin Kelly

Gas Research InstituteGeneral Electric Co.General Public Utilities Services Corp.Geothermal Resources InternationalHawaiian Electric Co., Inc.Houston Lighting & PowerIllinois Power C O .Investor Responsibility Research

Center, Inc.Iowa Commerce Commission

jet Propulsion LaboratoriesLurgi Corp.Maryland Public Service CommissionMassachusetts Institute of TechnologyMcDonnell Douglas AstronauticsMerrill Lynch Capital Markets

Middle SouthUtilitiesNational Regulatory Research InstituteNew York Consumer Protection BoardNew York State Energy Research &

Development Authori tyNew York State Public Service

CommissionNixon, Hargrove, Devans &DoyleNorth American Electric Reliability

CouncilOak Ridge National LaboratoryOregon Department of EnergyPacific Gas & Electric Co.Philadelphia Electric Co.Photovoltaic Energy SystemsPolydyne Corp.

Potomac Electric Power Co.Public Service Electric & GasPyropower Corp.Renewable Energy InstituteSan Diego Gas & Electric Co.Sandia LaboratoriesScientific AtlantaSolar Energy Research InstituteSolar Energy Industries AssociationSouthern California Edison Co.Southern Co. Services, Inc.Spire Corp.Standard & Poor’sState of AlaskaState of NevadaTechnecon Consulting Group, Inc.

Tennessee Valley AuthorityTexas Public Service CommissionU.S. Department of CommerceU.S. Department of EnergyU.S. Wind powerUnited TechnologiesUniversity of IllinoisUniversity of WisconsinUtah Power & LightW.A. Vachon & AssociatesVirginia PowerWestinghouse ElectricWisconsin Power & LightZond Wind Resource Development

Thomas KeyRon KukulkaAlbert LandgrebeL. Lilleleht-

E. LinBert LouksBob LynetteLarry MarkelBill MeadeWilliam MilesJames MulvaneyJames Neely

John OttsDavidOwensJohn ParkesJames PhillipsEdward PopeKevin PorterMargaret Rands

Tom ReddochJoe ReevesDavid RigneyEdward SabinskyDick SalkovRobert San MartinBob SchainkerPeter SchaubMartin SchlectRalph ScottJeff SerfassBob Sherwin

Harold SielstadFereidoon SioshansiFred SissineJetf SkeerAl SkinrodArt SoinskiBruce St. John

Ian StraughanDavid StreetsFred StrnisaTom TantonStratos TavoulareasRoger TaylorJames ToddWilliam VaughnStan VejtasaHerman VelasquezBlaine VincentWilliam Wagers

Byron WashonMichel WehreyRichard WoodsF.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 . . . . . . . . . . . . . . . . . 414. 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 Systemoperations 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





2 q NewElectric Power Technologies: Problems and Prospects for the 1990s

may be able to realize notable financial benefitsfrom smaller scale capacity additions, even whenthe capital cost per kilowatt of smaller units is asmuch as 10 percent more than that of large-scalecapacity additions. other attractive features ofthese technologies include reduced environ-mental impacts, the potential for fewer sitingand regulatory barriers, and improved efficiencyand fuel flexibility.

Despite these long-term advantages, however,at the current rate of development very few ofthese technologies are likely to be deployed ex-tensively enough in the 1990s to make a signif-icant contribution to U.S. electricity supply. Inboth groups of technologies, the ultimate goal ofresearch, development, and demonstration is toreduce costs and increase performance so thatthese new technologies can compete with moretraditional technologies.

For the first group, the likelihood of longpreconstruction and construction lead-times—up to 10 years— is the primary constraint. Al-though these technologies have the potential formuch shorter lead-times—5 to 6 years—problemsassociated with any new, complex technologymay require construction of a number of plantsbefore that potential is met. If the longer lead-times are needed, deployment in the 1990s willbe limited because of the short time remainingto develop the technologies to a level utilitieswould find acceptable for commercial readiness.

Technologies in the second group are likely tohave shorter lead-times and are often smaller ingenerating capacity. For most of them to makea significant contribution in the 1990s, however,their development will have to be stepped-upin order to reduce cost to levels acceptable toutility decisionmakers and nonutility investors,and to resolve cost and performance uncer-tainties.

In addition to new generating and storage tech-nologies, load management is being pursued ac-tively by some utilities.Widespread deploymentamong utilities in the 1990s, however, will de-pend on: continued experimentation by utilitiesto resolve remaining operational uncertainties;further refinement of load management equip-ment including adequate demonstration of com-

munications and load control systems; develop-ment of incentive rate structures; and a betterunderstanding of customer response to differ-ent load controls and rate incentives.

For load management as well as certain gen-erating technologies—specifically fuel cells, pho-

tovoltaics, solar thermal technologies, and bat-teries—economies of scale in manufacturingcould reduce cost substantially. Of course, thesereduced costs will not be realized without sub-stantial demand from utilities or other markets.

Finally, the relative advantages of both groupsof new generating technologies and load manage-ment varies by region. Factors such as demandgrowth rates, age and type of existing generat-ing facilities, natural resource availability, and reg-ulatory climate all influence technology choiceby utility and nonutility power producers.

Steps for Accelerated Developmentand Deployment

If electricity demand growth should accelerateby the early 1990s, the first choice of utilities islikely to be conventional central station genera-tion capacity. Because of many well-documentedproblems, however, there may be severe difficul-ties in relying on this choice alone and utilitiescould face serious problems in meeting demand.ASa consequence, it may be prudent to accel-erate the availability of the technologies discussed

in this study. Although not all the technologieswould be needed under such conditions, if theywere available, the market would be able to of-fer a more versatile array of choices to electri-city producers.

The steps necessary to make these technologiesavailable vary. With the first group of technol-ogies, it is necessary first to resolve cost and per-formance uncertainties within the next 5 to 6years, and then to assure the 5- to 6-year lead-time potential is met for early commercial units.

In the wake the experiences of the last decade,utility decisionmakers, in particular, are now verycautious about new technology, and they imposerigorous performance tests on technology invest-ment alternatives.This conservatism makes ad-vanced commercial demonstration projects even



Overview and Findings q 3

more important. For the basic designs of theAFBC, IGCC, and utility-scale geothermal plants,the current development and demonstrationschedule appears adequate to allow these tech-nologies to be ready by the 1990s. The c oope r-ative industry-government demonstration efforts,managed by the utilities, have a good track rec-ord. The transition from demonstration to earlycommercial units, however, will have to be ac-celerated if the technologies are to produce asignificant amount of electricity in the 1990s.Moreover, variations in basic designs or more ad-vanced designs to enhance performance charac-teristics further will require additional researchand development.

Lead-times being experienced by some earlycommercial projects in both groups of technol-ogies have been longer than anticipated, partiallydue to the time required for regulatory review.Working closely with regulators and taking stepsto assure quality construction for the early com-mercial plants could greatly assist the achieve-ment of shorter lead-times. Emphasis on smallerunit size—200 to 300 MW—wou!d facilitatethese actions.

For the technologies in the second group de-fined earlier, where cost and performance areof greatest concern, one approach to acceler-ating development would be to increase or con-centrate Federal research and developmentefforts on these technologies. This could be par-

ticularly effective for photovoltaics, solar ther-mal parabolic dishes, and advanced small geo-thermal designs.

There are othe r ap proa ches, though, in whic hFederal efforts can assist technology develop-ment. The reeme rgenc e of non utility po wer pro-duction as a growing industry in the United Statesis providing, and can continue to provide, an im-portant test bed for some of these new generat-ing technologies. For nonutility power produc-ers, the Renewable Energy Tax Credit (RTC) andthe recovery of full utility avoided costs under

the Public Utility Regulatory Policies Act of 1978(PURPA) have been crucial in the initial com-mercial development and deployment of windand solar power generating technologies. In pa r-ticuIar, with declining direct Federal support for

renewab le technology de velopme nt,the RTC hassupported both development of advanced de-signs as well as commercial application of ma-ture designs,

Without some continuation of favorable taxtreatment, based either on capacity or produc-

t ion, development of much of the domest icrenewable power technology industry may be sig-nificantly delayed. Some technologies such asgeothermal and w ind have a dvanc ed to the point,however, where industry probably would con-tinue development, although at a much slowerpa c e, even if the RTC w ere withdraw n.

Cooperative agreements among utilities, pub-lic utility commissions, and the Federal Govern-ment can provide another mechanism for sup-porting advanced commercial demonstrationprojects of technologies from both groups. A

portion of such projects could be financed withan equity contribution from the utility and theremainder through a “ratepayer loan” grantedby the public utility commission, possibly guaran-teed by the Federal Government,

Other Actions

The rate o f dep loyment o f new ge nerating tec h-nologies also will be affected by the extent towhich utilities and nonutility power producerscan resolve such issues as interconnection stanci-ards, coordination with utility resource plans, andprocedures for gaining access to transmission forinterconnection and wheeling of power to cus-tomers or other utilities.

The contribution of new generating technol-ogies is likely to be enhanced if utilities areallowed to enjoy the full benefits afforded toqualifying facilities under PURPA and if the re-strictions on the use of natural gas in power gen-eration are removed. The latter wouId allow theuse of natural gas as an interim fuel during thedevelopment of “clean coal” technologies, andgive utilities and nonutility power producersadded flexibility.

The new generating technologies that appearto show the most promise for significant deploy-ment in the 1990s are those that can serve ad-



4 q New Electric Power Technologies: Problems ancl prospects for the 1990s

ditional markets beyond the domestic utilitygrid. Such markets are particularly importantwhile the need for new electric generating ca-pacity is low, and while the cost and perform-ance of these technologies are uncertain in grid-connec ted ap plica tions. Indeed ,if priorities mustbe set in supporting developing technologies,it is important to note that broad market appealis as important as commercial readiness to theirtimely development. In this respect, Federal ef-forts to help industry exploit foreign marketscould be especially important.

The rate o f new gene rating tec hnology de ploy-ment also is tied closely to future trends inavoided cost and other provisions established by

PURPA, Long-term energy credit and capacitypayment agreements between utilities and non-utility power producers could accelerate deploy-ment. So could mandatory minimum rates orfixed price schedules for utility payments to non-utility power producers or for use as a basis forcost recovery by utilities themselves.

Finally, to increase the number ofnonutilitypower projects employing new electric generat-ing technologies, steps to streamline the mecha-nisms for wheeling of power through utility serv-ice territories might open up new markets for theelectricity they produce and thereby stimulatetheir development.



Chapter 1

Introduction



CONTENTS

Th eThe

Page Policy Context . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7Players . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 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 1970swas a decade of unprecedented change. Begin-ning with the 1973-74 Arab oil embargo, forecastsof electricity demand growth and costs, basedsolely on past trends, proved virtually useless.Utility decision makers found themselves caughtin a complicated and uncertain maze of inter-related financial, regulatory, and technologicalconsiderate ions.

Utilities had to pay, on average, 240 percentmore 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- andgas-fired generation and in favor of coal and nu-clear plants. Oil dropped from 16 to 5 percentin the utility fuel mix and gas from 22 to 12 per-cent between 1972 and 1984. But constructioncosts of new powerplants, particularly nuclear,rose dramatically during this period due to a com-bination of factors–increased attention to envi-ronmental and safety issues (leading to extendedconstruction lead-times and added equipmentcosts), an unpredictable reguIatory environment,an inflation-driven doubling of the cost of capi-ta l, and po or manag ement in some c ases. The

higher c osts of fuel and c ap ital mea nt higher elec -tricity costs, and utilities sought higher rates forthe first time in decades. in addition, most utili-ties seriously underestimated the price elasticityof electricity demand. Growth in demand plum-meted from 7 percent a year to less than 2.5 per-cent by the end of the decade as consumers usedless electricity and used it more efficiently.

During the 1970s some electric utilities werebrought to the brink of bankruptcy when forcedto cancel large, unneeded powerplants; commit-ments to these plants had been made long be-

fore it was realized that electricity demand hadbe en overestimate d. The erod ing revenue baseaccompanying declining demand growth cou-pled with the increasingly costly construction pro-grams already underway left the industry for the

most part struggling financially as bond ratingsand stock prices fell precipitously.

Even now in the mid-l980s, although utilitieshave for the most part recovered from the finan-cial trauma of the 1970s, ’ the scars remain. Theprocess by which utilities initiate, analyze, andimplement investment decisions was changedfundamentally by the 1970s experience. In the1960s, power system planners analyzed capac-ity expansion plans based on life cycle electricitycosts of alternative plans. System planners nowwork much more closely with financial planners

to analyze carefully the cash flow of the alterna-tives as well as the flexibility of alternative plansi n acc ommod ating unanticipated change s i n de-mand, capital cost, interest rates, environmentalregulation, and a host of other considerations.In short, their decisionmaking process has be-come much more financially cautious as well asmore complex.

While power system planners for most utilitiescontinue to focus on conventional generatingtechnologies, as well as advanced combined-cycle systems or enhancements to pulverizedcoal plants such as supercritical boilers, limestoneinjection, or advanced scrubber systems, theynow consider a much broader range of strategicoptions, including: life extension and rehabilita-tion of existing generating facilities; increased pur-chases from and shared construction programswith neighboring utilities; diversification to nontraditional lines of business; increased relianceon load management; and increased use of small-scale power production from a variety of bothconventional and alternative energy sources. in

1 Actually, even though1984 was a tery g o o d y e d r for utlllty stocki

on average, as of early 1985, uti i ties ta rough Iy Into t h ree cate-goric+ o{ stock performance wrne with little or no con~tructtonare q u Ite ~t rong, some m it h IOIVto modest con ~t ruct ion programsare sta hle but Iac k Iu ster i n performance, andfi na I [ywme w It h largenuclear taci Ilttes u rider corlstruction (or recently canceled) are\tl IIciolng very poorly,

7



addition, most utilities have greatly expandedtheir conservation programs, both because it nowoffers the lowest cost means of meeting demandin many cases, and it provides the utility with away to reduce future demand uncertainty. In con-sidering these various options, utilities hope tochart an investment course that will enable themboth to meet the largely unpredictable demandfor electricity in the future and to maintain theirfinancial health.

The most critical legacy of the 1970s is the un-cer ta in ty in e lec t r ic i ty demand growth. Af ter1972, not only did the average annual demandgrowth rate drop to less than a third of that ofthe previous decade, but the year-to-year changesbecame erratic as well. Users of electricity wereable to alter the quantity they used much morequickly than utilities could accommodate thesechanges with corresponding changes in gener-

ating capacity. Moreover, as of 1985, there is satu-ration in some markets—many major appliancesin homes—and the future of industrial demandis clouded as many large industrial users of elec-tricity, such as aluminum and bulk chemicals, areexperiencing decline in domestic production dueto foreign competition, At the same time, rapidgrowth continues in other areas such as spaceconditioning for commercial buildings, industrialprocess heat, and electronic office equipment.predicting the net impact of these offsetting fac-tors, along with trends toward increased effi-ciency, has greatly complicated the job of fore-casting demand,

Since requirements for new generating capac-ity over the next two decades depends primarilyon electricity demand growth (as well as the rateat which aging plants are replaced with new ca-pacity and, in some regions, net imports of bulkpower from other regions), planning for new ca-pacity has become a very risky process. To illus-trate the demand uncertainty, this assessmentlooks at a range of different growth rates–1 .5,2.5, 3.5, and 4.5 percent increases in average an-nual 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 dif-ferent demand growth rates with the currentlyplanned generating capacity for 1993 in the re-gions of the United States defined by the NorthAmerican Electricity Reliability Council (N ERC)–the NERC regions are defined in figure 1-2. In allregions, capacity surpluses are now projected by1993 if annual demand growth is 1.5 percent; andin seven of the nine regions, there would be ca-pacity surpluses if demand growth is 2.5 percent.But a 3.5 percent growth rate could mean capac-ity shortfalls in five of the nine regions; and witha 4.5 percent growth, there could be shortfallsin all regions.

At the center of the policy debate over the fu-ture of electricity supply is the mix of power gen-eration technologies that will be deployed by ei-ther utility or nonutility power producers over the

next seve ra l dec ad es. Those a nticipa ting a strongresurgence in electricity demand in the 1990ssupport the building of more large powerplants.They c ite ec ono mies of sca le of such plants tha t,in their view, would minimize electricity costsover the long run. Others, who believe demandgrowth to be more uncertain, favor a strategy offlexibility which includes the possibility of small-scale capacity additions as well as increased reli-ance on other methods of dealing with demanduncertainty such as conservation and load man-agement.

Complicating this controversy is the utilities’evolving attitude toward new technology, anotherconsequence of the 1970s. While traditionallyconservative in adopting new technology, theelectric utility industry has grown particularly cau-tious in the wake of its experience with nuclearpower. Utilities now impose rigorous economicperformance tests on new technology invest-ments. Perhaps because of this caution, projectsinitiated by nonutility power producers under thePublic Utility Regulatory Policies Act (PURPA)since 1978 have served as the principal test bedfor first generation commercial applications of

many new generating technologies.



Ch. I—introduction q 9

Figure l-l.— 1993 U.S. Generating Capacity Surplus or ShortfallUnder Alternative Peak Load Growth Scenarios a

25

20

15

10

5

0

-5

-lo

-15

-20

U.S. peak demand growthb

L



10 q New Electric Power Technologies: Problems and Prospects for the 1990s —

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

~ ~

THE PLAYERSAny 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 alongwith increased activity in new technology devel-opment have increased the number of partici- q

pants who affect the industry. Each brings a verydifferent perspective to electricity policy issues,especially with respect to new technologies.

Electric utilities, both public and investorowned, differ widely in financial health, ex-isting facilities and fuel use, and in their atti-tudes toward new technology.



q

q

SOURCE: Off Ice of Technology Assessment,

q

q

construction programs, as well as towardnew technology. -

Federal regulators such as the Federal En-ergy Regulatory Commission, the NuclearRegulatory Commission, and the Environ-mental Protection Agency, in carrying outtheir assigned missions, affect the electricpo wer industry profound ly. The prospe c t o fextensive deployment of new technologiesover the next several decades may hinge asmuch on the regulations promulgated bythese agencies as on the competitive costand performance of the technologies.Ratepayers’ response to electricity prices aswell as their attitudes on issues such as nu-clear power costs, nuclear safety, coal pol-lution, and acid rain, etc., will play majorroles in determining the future of the elec-tric 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 sup-ply-related issues–will largely determine thetechnologies that will be employed in powergeneration.

q Investors’ attitudes on the comparative risksin se lect ing future ut i l i ty and nonut i l i typower generation projects are importantconsiderations and will affect the financialhealth of both industries. As the utility indus-try recovers from a financially troubledperiod, the degree to which investors arewilling to put their money into large newgenerating plants again will greatly affect util-ity investment decisions. Similarly, the accessof new electricity-generating technologies totraditional (other than ve nture) ca pital sources,which is so critical to the continued devel-opment of many of these technologies, willdepend on investors’ perceptions of the tech-

nologies’ cost and performance prospects.Ž Vendors of conventional power generatingtechnology have enjoyed a long relationshipwith the electric utility industry, This relation-ship heavily influences new technology in-vestment decisions.

q Vendors of developing technologies includemany businesses that have not traditionallydealt with the electric utility industry. Newtechnology developers, which in many casesalso include traditional vendors, range from

giant petroleum companies and aerospacefirms to small independent firms. In manycases, the newcomers are only beginning toestablish working business relationships withelectric utilities and other nonutility powerproducers. For some technologies, thesefirms are much more diverse in terms of age,size, financial position, etc., than conven-tiona l tec hnolog y vend ors. The relat ionshipbetween such firms and the utilities as wellas non utility power producers is still evolv-ing and will affect future investment de-cisions.

q Research and development (R&D) establish-ments such as the U.S. Department ofEnergy and the Electric Power Research in-stitute (EPRI) are now important forces in thedevelopment of new electric power technol-ogies, Traditionally, until the 1970s, research,

development, and demonstration of newelectric power technologies was primarilywithin the province of a handful of equip-ment vendors cited above, i n some casessupported by the Federal Government.In -creasing Federal involvement in energy R&Din the 1970s and establishment of EPRI in1972 contributed to expanding the range ofpublic and private entities involved in com-mercial development of new electric tech-nologies.

OBJECTIVES OF THIS ASSESSMENTElectric power supply issues have been actively

discussed in recent years in Congress as well asby regulators, electric utilities, and other inter-ested parties. All parties have expressed renewedinterest in alternatives to large, long lead-timepowerplants. In 1981 the House Committee onBanking, Finance, and Urban Affairs requestedtha t OTA exam ine the prospe c ts of sma ll po wergeneration in the United States, citing that:

. . . co nside rations of e nergy polic y have not

taken adequately into account the possibilitiesof decentralizing part of America’s electrical gen-erating capabilities by distributing them withinurba n a nd other c omm unities.

At this time, the effects of the implementationof PURPA were beginning to appear. This act de-

fined a role for grid-connected, nonutility smallpower producers in U.S. electricity generation,requiring utilities to interconnect and pay theseproducers for electricity provided to the grid.During the early 1980s, it became clear that themost active nonutility area of small power pro-duction would be (and still is) industrial cogen-eration of steam and electricity. Consequently,in 1983 in response to the Banking Committee’srequest, OTA completed an assessment of indus-trial and commercial cogeneration.2



As the cogeneration assessment was underway,the effects of errors in electricity demand fore-casts and continued demand uncertainty on util-ity decision making were beginning to be feltthroughout the industry as proposed new plantswere canceled or deferred indefinitely. Thesecancellations were particularly damaging to thenuclear power industry which was already strug-gling to deal with increasing public opposition.OTA c omplete d an assessment of the future o fnuclear power which was released early in 1984. sIn the course of that study, the possibility of resur-gent electricity demand growth in the 1990s (ar-gued by some as quite likely) was raised as a verydifficult planning issue for the utility industry, par-ticularly if utilities continued to rely on large pow-erplants at a time when they were financiallystressed. To address these issues and to explorebenefits of small-scale, shot-t lead-time alternativesto central station powerplants, the House Scienceand Tec hnology Com mittee requested that OTAexamine the status of such technologies aspho-tovoltaics, fuel cells, wind turbines, selectedgeothermal technologies, solar thermal-electricpowerplants, atmospheric fluidized-bed com-bustors, coal gasification/combined-cycle plants,advanced utility-scale electricity storage technol-ogies, and load management.

In response, in late 1983 OTA undertook thisassessment of developing electric generatingtechnologies. The assessment addresses four major issues:

1..

2

What is the current status of new electricgenerating technologies compared with con-ventional alternatives and how is their sta-tus likely to change over the next 10 to 15years? In addition, what are the most prom-ising R&D opportunities that could affect thedeployment of these technologies over thisperiod and beyond?What is the nature of the industry support-ing these technologies (vendors and manu-facturers)? And how sensitive is their viabil-ity to electric utility orders over the next 10

to 15 years, Federal support (e.g., tax incen-

3.

4.

tives and/or demonstration programs), andforeign competition?What are the regional differences that affectthe attractiveness of these technologies toelectric utilities and nonutility power producers, particularly compared to other strategicoptions in those regions such as increasedpurchases of power from neighboring utili-ties, life extension of existing facilities, con-servation, and so on?What are the alternative public policy ini-tiatives (e. g., tax credits, loan guarantees,demonstration projects, etc.) for accelerat-ing the commercial viability of these tech-nologies?

This OTA assessment focuses on the group ofnewer developing generating technologies that,while not fully mature, couId figure importantlyunder some scenarios, in the plans of utility or

nonutility producers in the 1990s. Those technol-ogies considered relatively mature including con-ventional coal and nuclear plants, conventionalgas turbines, conventional combined-cycle plants,biomass technologies, vapor-dominated geother-mal technology, low-head hydroelectric faciIitiesand others are not considered in detail. It is im-portant to note, however, that in many casesthese technologies are the principal benchmarksagainst which the technologies considered herewill be compared in the 1990s. Also not consid-ered are technologies not likely to contributesignificantly to the U.S. generation mix by the1990s—e.g,, fusion, ocean thermal energy con-version, magneto hydrodynamics, and therm ionicenergy conversion.

This assessment was carried out with the assis-tance of a large number of experts reflectingdifferent perspectives on the electric powerindustry—utility executives, system planners, fi-nancial planners, State public utility commis-sioners, environmental and consumer groups,Federal regulators, engineers, technology ven-dors, nonutility small power producers, and thefinancial community. As with all OTA studies, an

advisory panel comprised of representatives fromall these groups met periodically throughout thecourse of the assessment to review and critiqueinterim products and this report, and to discussfundamental issues affecting the analysis. Con-



14 q New Electric power Technologies:Problems and Prospects for the 1990s

tractors and consultants also provided a widerange of material in support of the assessment.

Finally, OTA convened a series of workshopsto clarify important issues to be considered in theassessment and to review and expand upon con-tractors’ analyses.

The first workshop dealt with investment deci-sionmaking in the electric utility industry. It fo-cused on how the decision making environmentis changing in the industry and on identifying theprincipal considerations by utilities in making newtechnology investments. in addition, the work-shop addressed utility approaches to accommo-dating non utility power production, the Federalrole i n commercialization of new electric powergenerating technologies, and major policy con-tingencies that could affect the relative attractive-ness of alternative generating technologies overthe next several decades. For example, such con-tingencies as acid rain control policies and in-creased availability of natural gas for electricpower generation were considered.

About midway into the assessment, OTA con-vened a series of seven workshops dealing withthe c ost and performanc e of new g enerating andload management technologies. These work-shops reviewed and refined the benchmark costand performa nce figures gene rate d by OTA c on-tractors and identified the most important R&Dopportunities necessary for continued advance-me nt of the te chnolog ies be ing co nsidered. Theresults of these workshops, coupled with the sub-seq uent c ontrac tor and OTA sta ff ana lyses, formedthe basis of the comparative assessment of gen-erating technologies and the likelihood of theircontributing significantly to U.S. electric powergeneration in the next two decades under vari-ous policy scenarios.

The final wo rkshop convened in the c ourse o fthis assessment dealt with economic regulatoryissues affecting the development and deploymentof ne w ge nerating t ec hnologies. The p rinc ipal is-sues addressed were regulatory treatment of re-

search and development by electric utilities, im-plementation of PURPA, regulation of affiliatedelectric utility interests involved in new generat-ing technology, and scenarios for deregulatingelectric power production.

Based on the workshop discussions, advisorypanel recommendations, contractor and con-sultant reports, and OTA staff research, a set ofalternative policy options were developed andanalyzed. Advisory panel members, workshopparticipants, contractors, and other contributorsto this assessment are listed in the front of thisreport.

This report is organized as follows:q

q

q

q

q

q

q

Chapter 2 is a summary of the entire report.Chapter 3 establishes the context in whichelectric utility investment decisions are made.In particular, it examines the range of stra-tegic options being considered by utilitiesand the relative importance of new gener-ating technologies with those options.Chapter 4 defines plausible ranges of cost,performance, uncertainty, and risk which arelikely to characterize new electric generat-ing and storage technologies in the 1990s,In addition, the prominent R&D needs areidentified and discussed.Chapter 5 establishes benchmark cost andperformance figures for the conventionaltechnologies against which the new technol-ogies are likely to compete over the next twodecades. In addition, the prospects for re-habilitating or extending the lives of existinggenerating facilities and for increased reli-ance on load management as alternatives tonew generating capacity are considered.

Chapter 6 discusses the impact of decen-tralized power generation on the perform-anc e o f elec tric po wer system s. The fo c usis on questions of standards for and costs ofinterconnecting such sources with the gridas well the effects of increasing penetrationof such sources on power system control,operation, and planning.Chapter 7 analyzes the differences amongU.S. regions that could influence the poten-tial usefulness of new electric generatingtechnologies in those regions. The principaldifferenc es include electricity de ma nd growth

and peaks, existing fuel use and generatingfacilities, indigenous energy resources, andinterregional transmission capabilities.Chapter 8 compares the competitiveness ofnew technologies with conventional tech nol-





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

191921212225

2525252929

. . . . . . . . . . . . -2 9Regional Differences . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Existing Generation Mix . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Interregional Bulk Power Transactions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Load Management . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Reliability Criteria . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Renewable Resources . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

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

Utility Investment . . . . . . . . . . . . . . . . . . . . . . . . . .Nonutility Investment . . . . . . . . . . . . . . . . . . . . . . .

Current an d Future Sta te of Alternative Tec hnolog yFederal Policy Options.. . . . . . . . . . . . . . . . .....

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

Research, Development, and Demonstration . . . . . . .....+... . . . . . . . . . . . .Other Policy Actions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Renewable Energy Tax Credits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

2929303030

3131

31323233

33

3536

List of TablesTab/e/We. Page 2-1 . Selec ted Alternative Ge nerating and Storag e Tec hnolog ies:

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

2734

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 ofthe 1970s have made them much more wary ofthe financial risk of guessing wrong and over-committing to large central station coal and nu-clear plants. At the same time, there is growingconcern by utilities about the possibility of be-ing unable to meet demand, particuIarly in viewof increased uncertainty about future demandgrowth. In addition, the provisions of the PublicUtility Regulatory Policies Act of 1978 (PURPA),have made the role of non utility power produc-ers increasingly important to the future of U.S.electricity supply. As discussed in chapter 1, one

of the strategies being pursued by utilities to oper-ate in this new environment is through increasedutilization of smaller scale power production by

a variety of both conventional and nontraditionalenergy conversion technologies.

if electricity demand grows at an average an-nual rate below 2.5 percent through the 1990s(current estimates range from 1 to 5 percent), theneed for new generating capacity is likely to berelatively modest. Responses that include life ex-tension and rehabilitation, increased power pur-chases, and construction of realizable amountsof conventional generation are likely to suffice.But if demand growth should accelerate, theseoptions may not be enough, and the availabilityof an array of generating technologies that pro-vide a utility with greater flexibility for meetingload requirements may be desirable.

NEW GENERATING TECHNOLOGIES FOR THE 1990sA number of developing technologies for elec-

tric power generation are beginning to show con-siderable promise as future electricity supplyoptions. Some of these technologies, such asatmospheric fluidized-bed combustion (AFBC)

and integrated coal gasificatiordcombined-cycle(IGCQ conversion, and fuel cells, could pave theway for clean and more efficient power genera-tion using domestic coal resources.

In box 2A, the renewable and nonrenewabletechnologies considered in this assessment arelisted and briefly discussed. Table 2-1 shows thosetechnologies grouped according to the sizes andapplications in which they would most likely ap-pear if deployed during the 1990s. Also shownin the table are the principal conventional alter-natives against which these technologies are mostlikely to compete. Applications are divided be-

tween those in which electrical power output iscontrolled by the utility (dispatchable) and thosewhere it is not (nondispatchable). Dispatchableapplications are further broken down into base,intermediate, and peaking duty cycles. Nondis-

patchable applications are divided between thosewith and without storage capabilities.

Many of these technologiesoffer modulardesign features that eventually could allow util-ities to add generating capability in small in-crements with short lead-times and less concen-tration of financial capital. Other attractivefeatures common to some but not all of thesetechnologies include fewer siting and regulatorybarriers, reduced environmental impact, and in-creased fuel flexibility and diversity. Virtually allof the technologies considered in this assessmentoffer the potential of sizable deployment in elec-tric power generation applications beyond theturn of the century.At the current rate of de-velopment, however, most developing technol-ogies will not be in a position to contribute more

19



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within the copy of this reportfound on one of the OTA websites .



Ch. 2—Summary q 21

Installationsize (MW)

Greater than250 MWe

51-250 MWe

1-50 MWE

Less than1 MWe

Table 2-1 .—Selected Alternative Generating and Storage Technologies:Typical Sizes and Applications in the 1990s

Typical configurations in the 1990sDispatchable applications

Base load Intermediate load Peaking load(60-700/0 CF) (30-400/0 CF) (&150/o)

Geothermal Atmosphere fluidized- Compressed air storagebed combustor (maxi CAES)

Atmospheric fiuidized- Compressed air storagebed combustor (maxi CAES) Solar thermal (w/storage)

Geothermal Fuel cells Compressed air storageAtmospheric fluidized- Compressed air storage (mini CAES)

bed combustor (maxi CAES) Battery storageFuel ceils Solar thermal (w/storage) Fuel cells

Solar thermal (w/storage)

Nondispatchable applicationsb

Intermittent Others(w/o storage) (not utility controlled)

Solar thermal Atmospheric fluidized-Wind bed combustor

Solar thermal (w/storage)

Solar thermal Atmospheric fluidized-Wind bed combustorPhotovol ta ics Geothermal

Fuel cellsSolar thermal (w/storage)Battery storageCompressed air storage

(mini CAES)Geothermal. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Combustion turbine

Solar thermal Fuel cellsWind Battery storagePhotovoltaics

SOURCE. Office of Technology Assessment

than a few percent of total U.S. electric gener-ating capacity in the 1990s, and therefore, willnot be of much help in meeting accelerated de-mand, should it occur. 2

Cost and Performance

The current cost and performance character-istics (including the uncertainty in both cost andperformance) of most new technologies are notgenerally competitive with conventional alter-natives. s Cost reductions, performance improve-ments, and resolution of uncertainties will all oc-c ur as these t ec hnologies ma ture. The rate at

‘Here and elsewhere in this report, a contribution toU.S. elec-

tricity supply is considered “significant” when it amounts to morethan 5 to 10 percent of total generating capacity, orthe equivalentin terms of electricity storage or reduced demand.

31 n p a ~ i c u Ia r, w i t h c o n v e n t i o n a l generating capacity in smallerunit sizes such as conventional combustion turbines, advancedcombined cycle plants, slow-speed diesels, and participation in con-ventional cogeneratlon projects.

which this maturity occurs depends on: 1 ) sus-tained progress in research, development, anddemonstration to reduce cost, improve perform-ance, and reduce uncertainty in both cost andperformance; and 2) continued active demonstra-tion of the technologies, particularly in utility ap-plications to develop the commercial operatingexperience necessary before utility decision-makers will consider a new technology seriously.Utility and nonutility interest in these technol-ogies is also affected by a wide range of otherfactors relating to environmental benefits, sitingrequirements, and public acceptance.

Lead-Times

Common to the deployment of all electric gen-erating technologies is the need for planning, de-sign, licensing, permitting, other preconstructionactivities, and finally construction itself. Thesesteps 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—upto 10 years or more. This means that if those tech-nologies still undergoing development are to becommercially deployed in the 1990s, there maybe as little as 5 or 6 years in which to completedevelopment and establish in the minds of inves-tors that their costs, performance, and other at-tributes fall within acceptable ranges.

Specific Generating Technologies

The relative impo rtanc e o f efforts to imp rovecost and performance versus the need to shortenlead-times in order to attain commercial statusvaries by t ec hnology. This d istinction, i n pa rtic u-lar, makes it convenient to divide the technol-ogies considered here into two basic groups:

1.

2.

In

The first consists of technologies envisionedprimarily for direct electric utility applica-

tions, and includes IGCC plants; large (> 100MW) AFBC; large ( >100 MW) compressedair energy storage (CAES) facilities; large(>50 MW) geothermal plants; utility-ownedfuel cell powerplants; and solar thermal cen-tral receivers.The second group consists of technologiesthat are characterized as suitable either forutility or nonutility applications, and includessmall ( <100 MW) AFBCs in nonutility co-generation applications; fuel cells small(< 100 MW) CAES; small ( <50 MW) geo-thermal plants; batteries; wind; and directsolar power generating technologies such aspho tovo ltaics and pa rab olic dish solar therma l.

both groups, the goal of research, develop-ment, and demonstration is to improve cost andperformance characteristics to a point where thetechnologies are commercially competitive. Forthe first group of technologies, however, thelikelihood of long lead-times for early commer-cial units is the primary constraint to extensiveuse in the 1990s. Technologies in the secondgroup are likely to have shorter lead-times andare often smaller in generating capacity. For most

of them to make a significant contribution in the199os, however, their research, development,and demonstration will have to be stepped-upin 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 be-tween these two groups of technologies is notrigid. Technologies in the first group also couldbenefit from accelerated research and develop-

ment while those in the second group could beheld back by long lead-times.

In addition, many of the technologies in thesecond group are small enough to qualify as smallpower producers employed in nonutility powergenerating projects operating under the provi-sions of PURPA.The existence of a wide varietyof markets and interested investors outside theelectric utilities increases the likelihood that atleast some of these technologies will be de-ployed.

Because of its modular nature and positive

environmental features, the IGCC has the poten-tial for deployment lead-times of no more than5 to 6 years. Early commercial units, however,may require longer times—up to10 y e a r s —because of regulatory delays, construction prob-lems, and operational difficulties associated withany new, complex technology; and it may takea number of commercial plants before the shortlead-time potential of the IGCC is realized. In ad-dition, despite the success of the Cool Waterdemonstration project, a 100 MWe IGCC plantthat has increased electric utility confidence inthe technology, more operating experience islikely to be required before there will be majorcommitment to the IGCC by a cautious electricutility industry. Therefore,unless strong steps aretaken to work closely with regulators and to as-sure quality construction for these initial plants,there may be insufficient time remaining afterutilities finally make a large commitment to theIGCC for the technology to make a significantcontribution before 2000. As has been shownin the Cool Water project, though, such steps arepossible, and they may be facilitated if initial com-mercial units are in the 200 to 300 MWe rangerather than the current design target of 500 MWe.

The first la rge (a b ou t 150 MW), “ gra ss-root s”(i.e., not retrofits of existing facilities) AFBC in-stallations for generating electricity also may be



Ch. 2—Summary . 23

subject to long lead-times. Moreover, a largeAFBC demonstration unit probably will not evenbe operating until 1989. It now appears unlikelythat the operation of that unit will be sufficientto justify large numbers of orders within the firstfew years of the 1990s. The AFBC, however, alsohas the potential for needing lead-times on theorder of only 5 years. Further, favorable experi-ence with smaller AFBC cogeneration units andAFBC retrofit units which will be in service by1990 may provide the commercial experienceneeded to accelerate deployment of the largerunits.

Foremost among new technologies offeringthe potential of significant deployment in the1990s are small (below 100 MWe) AFBC plantsin cogeneration applications and larger (100 to200 MWe) AFBCretrofits to existing coal-firedpowerplants. By 1990, plants of both types willbe operating. Over a dozen commercial cogen-eration plants using AFBC have been started bynon utilities, and two large utility retrofit projectsare und erway. These first p lants ap pe ar cap ab leof producing electricity at lower costs than theirsolid-fuel burning competitors (including theIGCC and large, electric-only, grass-roots AFBCs)in the 1990s. The p rospec ts are go od that ad di-tional orders—perhaps mostly from nonutilities—will be forthcoming and that large numbers ofthese AFBC units could be operating by the endof the century.

While the prospects for wind turbines areclouded by the anticipated termination of theRenewable Energy Tax Credits (RTC) and otherpotential tax changes, the outlook neverthelessappears promising. By the end of 1984, an esti-mated 650 MWe were in place in wind farms inthe United States, mostly in California (550MWe). Over the early 1980s, capital costs havedropped rapidly and performance improvedswiftly,Improvements are expected to continue,and the cost of electric power from wind tur-bines, even unsubsidized ones, in high-windparts of the country may soon be considerablylower than power from many of their competi-tors. The rate of improvement will be heavily in-fluenced by future trends in the avoided costs or“buy-back rates” offered by utilities to nonutil-ity electricity producers. Should these costs be

low or uncertain, technological development andapplication will be slowed. Conversely, highavoided costs, stimulated perhaps by rising oiland gas prices or shrinking reserve margins ofgenerating capacity, might considerably acceler-ate their contribution.

Although geothermal development has beensubstantial compared to other technologies, mostof this de velopment has oc curred at The Geysersin California, an unusual high-quality dry steamresource (one of only seven known in the world)that can be tapped with mature technology. Allother geothermal resources in the United Statesrequire less developed technology to generatepo wer. Two deve loping geo thermal tec hnologies,though, are currently being demonstrated on asmall scale and show promise for commercial ap-plications in the West. Current evidence indicatesthat these technologies—dual flash and binarysystems—are very close to being commercial, andthat cost and performance will be competitive.Small binary units (about 10 MWe) are alreadybe ing dep loyed c om mercially. These d evelop-ments, coupled with the fact that the technologiescan be put in place with lead-times of 5 years orless, suggest that they could produce consider-able electric power in the West by the end of thecentury. As is the case with wind power,t h egrowth rate of geothermal power will be sensi-tive to Federal and Mate tax policy.

Init ial commercial application of fuel cells

should appear in the early 1990s, primarily firedwith na tural gas. The large and po tentially va r-ied market (it includes both gas and electric util-ities as well as cogenerators), the very short lead-times, factory fabrication of components, and avariety of operational and environmental bene-fits all suggest that when cost and performanceof fuel cell powerplants become acceptable, de-ployment could proceed rapidly.The principalobstacle to fuel cells making a significant con-tribution seems to be insufficient initial demandto justify their mass production. For such de-mand to appear in the 1990s, extensive commer-

cial demonstration in the late 1980s will probablybe necessary,

The development rate of photovoltaics (PV)has been considerable in recent years, but thetechnical challenge of developing a PV module

38-743 0 - 85 - 2



24 . New ElectricPower Technologies: Problems and Prospects for the 1990s

that is efficient, long-lasting, and inexpensiveremains. While technical progress and deploy-ment of photovoltaics in the United States arelikely to be slowed by termination of the RTC orby other changes in Federal or State tax law, orby declining avoided costs, industry activity islikely to remain intense. Aided by interim mar-kets of specialized applications and consumerelectronics, PVS could develop to the point wherecompetitive grid-connected applications at leastbegin to appear in the 1990s. In the 1990s, over-seas markets may dominate the industry’s atten-tion, stimulating and supporting improvementsin cost and performance, and encouraging massproduction to further reduce costs. However,European and Japanese vendors, assisted by theirrespective governments, have been more suc-cessful than U.S. vendors in developing thesemarkets, Foreign competition is likely to be amajor concern for U.S. vendors over the nextdecade .

Of the solar thermal technologies, solar para-bolic dish technologies offer the most promiseover the next 10 to 15 years; although with cur-rent uncertainty in cost and performance, solartroughs may be competitive as well. Character-istics of some solar dish and trough designs indi-cate that they could be rapidly put in place inareas such as the Southwest. The cost of powergeneration using these designs in such regionscould be very close to those of conventional alter-natives. Some demonstration and subsidizedcommercial units already are operating.Full com-mercial application, however, will require fur-ther demonstrations of the technologies over ex-tended periods of time; such demonstrationsmust be started no later than 1990 if the tech-nologies are to be considered seriously by in-vestors in the 1990s. The likelihood of suchdemonstrations appears now to depend on theavailability of some kind of subsidy. In particu-lar, development of the technology to date hasdepended heavily on the RTC.

Other solar thermal technologies, including

central receivers and solar ponds, while show-ing long-term promise, are unlikely to be com-petitive with other electric generating alternativesor have sufficient commercial demonstration ex-perience to yield any significant contribution

through the 1990s. The central receiver, how-ever, is of continuing interest to a some South-western utilities in the long term because it offersa favorable combination of advantages includingthe potential for repowering applications, highefficiency, and storage capabilities.

Along with new generating technologies, thisassessment examined two electric energy storagetechnologies—compressed air energy storage(CAES) and batteries–that show long-term prom-ise in electric utility applications.

Because of potentially long lead-times, CAESappears to have only limited prospects in the1990s. The large-scale ( >100 MW) version of thistechnology (called maxi-CAES) currently has anestimated lead-time of 5 to 8 years; of this, licens-ing and permitting and other preconstructionactivities is expected to take 2 to4 years. More-

over, while commercial installations are operat-ing in Europe, no plant yet exists in the UnitedStates. Despite strong evidence that this technol-ogy offers an economic storage option, CAES isunlikely to be the target of much investment un-til a demonstration plant is built. No plans for ademonstration plant currently exist. Further,while a demonstration project should prove thetechnology, the peculiar underground sit ingproblems and unfamiliarity with the CAES con-cept may still limit early application.

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

–promises to have a much shorter lead-time dueto modularity of the above-ground facilities andshort (30-month) construction lead-times. Heretoo, however, unless a demonstration plant isstarted in the next few years, extensive deploy-ment before the end of the century is improbable.

Resolution of a variety of cost and performanceuncertainties remains before extensive use of ad-vanced battery storage systems can be antici-pated. If the technical problems can be resolvedi n a timely fashion and demonstration programsare successful, however, rapid deployment in

electric utility applications could occur, due tothe short lead-times and cost reductions associ-ated with mass production. Of the candidates,lead-acid and zinc-halogen batteries appear toshow the most promise.




Table 2-2 summarizes the most promising areas velopment through the 1990s. Table 2-3 summa-of research and development identified by OTA rizes the major electric power generating projectfor the technologies analyzed in this assessment. utilizing these technologies installed or underAtention to these research and development op- construction as of May 1985.portunities could accelerate commercial their de-

CONVENTIONAL ALTERNATIVES IN THE 1990sThe c ontribution of de veloping tec hnologies

over the next two decades depends in part onthe relative cost and performance of conventionalgenerating options as well as a variety of optionsfor extending the lives or otherwise improving theperformance of existing generating facilities.

New Capacity

To the extent that new generating capacity isneeded at all over the next two decades, con-ventional pulverized coal plants, combustionturbines, and advanced combined-cycle plantswill continue to be the principal benchmarkagainst which utilities and others will comparedeveloping generating technologies. Utilities arevery interested, however, in smaller unit sizesof even these technologies. Also, if nuclearpower is to become a realizable choice again forutilities, it is likely to involve smaller, standard-ized units.

If hydroelectric opportunities are available, theyare likely to be exploited in both run-of-river andpumped storage applications; few new hydro-electric opportunities, though, are likely throughthe 1990s. Similarly, refuse steam plants, biomasstechnologies (e. g., wood waste-fired power gen-eration), slow-speed diesels, and vapor-domi-nated geothermal plants all use mature technol-ogies so that where opportunities exist, they arelikely to be chosen over newer technologies.

In addition, enhancements to conventionalplants such as limestone injection in coal boilers,coal-water fuel mixtures, and others will all be

reviewed carefully along with new generatingtechnologies as utilities plan for new capacity.The a vailability of suc h enha ncements could sig-nificantly affect the relative attractiveness of newtechnologies in the 1990s.

Plant Betterment

By 1995, the U.S. fossil steam capacity willhave aged to the point where over a quarter ofthe coal and nearly half of the oil and gas steamunits nationwide will be over 30 years old. Inthe past, the benefits of new technologyoften outweighed the benefits of extending the usefullives of existing generating facilities, rehabilitat-ing such facilities to improve performance or up-grade capacity, or even repowering such plantswith alternative fuels. Ail of these so-called plantbetterment options are receiving renewed inter-est by utilities because plants “reaching their 30thbirthday” over the next decade have attractiveunit sizes (100 MW or larger) and performance(heat rates close to 10,000 Btu/kWh). For that rea-son, rehabilitating or simply extending the livesof such units, frequently at much lower antici-pated capital costs than that of new capacity,are often very attractive options for many utili-ties. Prospects are particularly bright if units arelocated at sites close to load centers and the re-habilitation does not trigger application of NewSource Performance Standards, i.e., more strin-gent air pollution controls.

In many instances, plant betterment can alsoimprove efficiency up to 5 to 10 percent and/orupgrade capacity. Additional benefits from suchprojects include possible improvements in fuelflexibility or reduced emissions of existing gen-erating units at modest cost relative to that of newcapacity. Finally, an initial market for some newtechnologies such as the AFBC are in repower-ing applications, e.g., where an existing pulver-ized coal plant is retrofitted with an AFBC boiIer.

Load Management

Load management refers to manipulation ofcustomer demand by economic and/or techni-



26 q New Electric Power Technologies: Problems and Prospects for the 1990s

Wind: 1. Development of aerodynamic prediction codes2. Development of structural dynamic codes3. Fatigue research4. Wind-farm wake effects5. Development of acoustic prediction codes

Solar thermal electric:

General:1. Low cost, reliable tracking hardwareSolar ponds:

1. Physics and chemistry2. Design and performance analysis3. Construction techniques4. Operation and maintenance

Central receivers:1. Physics and chemistry2. Development and long-term testing of cheap and

durable scaled-up molten-salt subsystems (includingreceiver, pumps, valves, and pipes)

Parabolic dishes:1. Durable engines2. Cheap, high-quality, durable reflective materials

(polymers)3. Long-life Stirling and Brayton heat engines

Parabolic troughs:1. Inexpensive, long-lived, high-temperature thermal-storage media

2. Cheap, leak-resistant, well-insulated receiver-tubes3. 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 silicon3. Cheap, durable, and reliable modules and module

subcomponents (especially the optics and cellmounts for concentrator modules)

4. Reliable, inexpensive and durable “balance ofsystems, ” especially tracking systems and powerconditioners

Fluidlzed-bed combustors: Circulating-bed AFBCS:

1. Cheap, durable, and reliable equipment forseparating solids from gas streat

2. Erosion- and corrosion-resistant materials anddesigns

Bubbling-bed AFBCs:1. Adequate sulfur capture by limestone sorbent2. Effective fuel-feed systems3. Erosion- and corrosion-resistant materiais and

designsIntegrated gasificatlon/combined.cycie:

1. Cheap, durable, reliable, and efficient combustionturbines and combined-cycle systems

2. Erosion- and corrosion-resistant materials3. Gasifiers capable of effectively converting a variety

of fuels

1.

2.

3.4.5.

Corrosion-resistant equipment (especially turbineblades and underground equipment)Durable, reliable, and inexpensive recuperator(recuperator discharges heat from combustionturbine gases to incoming compressed air)Lower cost of existing underground storage sitesImproved recovery of compression heatGeologic response to air cycling in reservoir

Load management technologies: Meters:

1. Mass-produced, inexpensive, durable, reliable solid-state devices capable of operating in adverseenvironments

2. Meter capable of sustaining operation during poweroutages

Communications systems:1. Inexpensive, reliable, and durable residential

receivers or transpondersLogic systems:

1. Development of appropriate softwareFuel cells:

1. Lower cost and more efficient catalysts2. Less corrosive and temperature-sensitive structural

materials3. Higher power densities via:

a. Improved coolig systemsb. Improved oxygen flowsc. Improved cell geometry

4. More stable electrolytes5. Longer stack life

Geothermal: 1. Inexpensive, durable, and reliable down-hole pumps2. Detailed resource assessment3. Inexpensive, durable, and reliable well casing

materialsDual flash:

1. Cheap, durable, and reliable equipment for removingnoncondensable gases and/or entrained solids frombrines

2. Reliable operation in highly saline environmentsBinary:

1. Inexpensive, durable working fluids2. Equipment durability and reliability in highly saline

environments

SOURCE: Office of Technology Assessment.







Ch. 2—Summary q 2 9

IMPACT OF DISPERSED GENERATING TECHNOLOGIESON SYSTEM OPERATION

As the participation in U.S. electric power sys-tems of non utility owned and operated dispersedgenerating sources (DSGs) increases, the impli-

cations for system operation, performance, andreliability are receiving increased attention by theindustry. For the most part, however, the tech-nical aspects of interconnection and integrationwith the grid are fairly well understood and mostutilities feel that the technical problems can beresolved with little difficulty. State-of-the-artpower conditioners are expected to alleviate util-ity concerns about the quality of interconnectionsubsystems. A number of nontechnical problemsremain, though, which could inhibit the growthof DSGs.

Nonutility Interconnection StandardsMore utilities are developing guidelines for in-

terco nnec tion of DSGs with the g rid. A numb erof national “model” guidelines are being devel-oped by standard-setting committees for theIn-stitute of Electrical and Electronic Engineers, theNational Electric Code, the U.S. Department ofEnergy, and the Electric Power Research Institute,although none has yet released final versions and

REGIONALA particularly important factor affecting the

relative advantages of new electric generatingstorage, and load management technologies isthe region in which a utility or prospective non-utility power producer is located. U.S. regions dif-fer markedly in industrial base, demographictrends, and other factors affecting electricity de-mand; the age and composition (particularly fueluse) of existing generating facilities; the natureand magnitude of available indigenous energy re-sources; regulatory environment; transmission in-frastructure and prospects for bulk power trans-fers; and other factors affecting the selection ofelectric power technologies.

widespread utility endorsement is still uncertain.As a result,DSG owners are likely to face differ-ent and sometimes conflicting interconnection

equipment standards well into the 1990s. Thesedifferences may hamper both the use of DSGsas well as the standardized manufacture of in-terconnection equipment.

Interconnection Costs

The c osts of interconne c tion have d ec lined dra-matically in recent years, particularly for smallerDSGs. Typical costs range from $600/kW for 5kW units to less than $100/kW for 500 kW orlarger units. The interconnection costs for multi-megawatt DSGs are only a small fraction of the

total cost of the facility. While future technologi-cal advances in microprocessor controls and lesscostly nonmetallic construction could bring costsdown even further, the major cost decrease is ex-pected to come from volume product ion ofequipment. As mentioned above, though, thisvolume production may be delayed until nationalmodel interconnection guidelines are agreed onfor interconnection equipment.

DIFFERENCESExisting Generation Mix

The regional mix of existing generating facil-ities is likely to profoundly affect the relative at-tractiveness of new generating capacity. Whilemost electric utility systems with substantial oiland gas capacity are expected to decrease useof these fuels over the next decade,reliance onthese fuels is expected to be strong enough insome areas, i.e., New England, the Gulf andMid-Atlantic States, the Southeast, and the West,that the economics of competing technologieswill remain particularly sensitive to the price andavailability of oil and gas. This will apply even




more strongly in the few States such as Floridawhere, due to e xpe cta tions of high de ma nd growthand continued decreases in (or stabilization of)oil prices, utility systems are actually forecastingincreased use of oil.

in California oil- and gas-fired generation, while

declining, is projected to remain above 33 per-c ent o f the tota l elec tric ity ge neration in the Statethrough the end of the century (oil alone will beIs percent). Similarly, if present trends continuein Texas, oil and ga s is projec ted to a ccount fo r35 percent of total generation and about so per-cent of total capacity over the same time period.In both States, high avoided cost rates resultingfrom continued reliance on oil and gas enhancesthe attractiveness of cogeneration, in particular,whiIe the favorable tax climate in California en-hances the attractiveness of renewable powergeneration projects initiated under PURPA.Insome States where oil and gas are the dominantfuels, especially California, Louisiana, andTexas, cogeneration may constitute a significantfraction of total installed capacity by the endof the century. Some utilities in Texas, for exam-ple, are already planning for cogeneration con-tributions of as much as 30 percent.

The a ge of existing po we r generating fa c ilitiesvaries widely among U.S. regions. As a result, theprospects for life extension and plant rehabilita-tion vary as well. For example, Texas, the South-east, and the States west of the Rockies will have

the highest percentage increases in plants thatwould be logical candidates for such options be-tween now and 1995, i.e., those generating unitsthat will have been in operation more than 30years. in terms of total installed capacity, the op-portunities for life extension will be greatest inthe Mid-Atlantic, Southeast, Gulf, and WesternStates. Site-specific economics will determine ac-tual implementation levels.

Interregional Bulk Power Transactions

It appears that existing interutility and inter-

regional transmission capabilities are beingnearly fully utilized in the United States. Hence,the prospects for large increases in bulk powerpurchases among utilities using existing transmiss-ion capabilities will be limited.Some regions,

however, such as portions of the West and Mid-west, are continuing to expand generation andtransmission facilities in anticipation of servingthe bulk power markets. In addition, major trans-mission projects are underway in New York, NewEngland, the upper Midwest, and the PacificNorthwest to allow these regions to purchaselower cost hydroelectric power generated in Can-ada from existing and proposed facilities.

Load Management

OTA has found that the prospects for in-creased load management in future utility re-source planning vary by region. Perhaps moreimportantly, they also vary significantly by utilitywithin reliability council regions. Moreover, util-ities’ objectives for pursuing load managementvary as well. For example, utilities with very highcurrent or anticipated reserve margins (many inthe Midwest), are interested in load managementto better use existing base load capacity, i.e., tostimulate increased demand in off-peak periods.Other utilities with very low current or anticipatedreserve margins are pursuing load managementprimarily to reduce peak demand and defer theneed for new capacity additions. Municipal util-ities and rural cooperatives, which accounted formost of the points controlled by load manage-ment in 1983, are expected to continue to pro-vide a strong load management market in all re-gions through the 1990s.

Reliability Criteria

An important indicator of a region’s need fornew generating capacity is reflected in measuresof projected power system reliability. Such meas-ures include the reserve margin—i. e., amount ofinstalled capacity available in excess of the peakload, traditionally expressed as a percentage ofthe total installed capacity. Reserve margins, aswell as other reliability measures, are sensitiveto demand predictions, scheduled capacity ad-ditions and retirements, and other factors suchas scheduled maintenance and adjustments forforced outages or firm power purchases and salesfrom other utilities.

The anticipated reserve margins over the nextseveral decades vary considerably by region. Un-




der medium demand growth (2.5 percent aver-age annual growth through 1995), reserve mar-gins are expected to dip as low as 15 percent (inthe upper Midwest in the early 1990s) and peakas high as 47 percent (in the West in the mid-1980s). Under higher demand growth, power

pools in all regions may fall below acceptablereliability levels in the early 1990s. Under low de-mand growth (less than 2 percent), reliabilitylevels are likely to be adequate in all regionsthrough the early 1990s.

Renewable Resources

Increased use of solar, wind, and geothermalresources in U.S. electric power generation willvary regionally due to both the relative cost ofalternative generation and the availability of high-

quality renewable resources. For example, whilewind regimes are promising for wind turbines inmany areas across the country, they are currentlybeing deve!Gped mostly in California where highutility avoided cost and a favorable tax climatehave encouraged their development in nonutility

power production applications under PURPA. Inaddition, a State-sponsored wind resource assess-ment program has spurred development. A simi-lar situation exists for photovoltaics and geother-mal power, although geothermal developmentis much more regionally limited to the West. So-lar thermal power generation, for the next sev-eral decades at least, may be viable only in theSouthwest and perhaps the Southeast where so-lar insolation characteristics may be sufficient tomake projects competitive and where land avail-abiIity is not a major constraint on development.

UTILITY AND NONUTILITY INVESTMENT DECISIONSPrior to the 1970s, maintaining power system

reliability was treated as a prescribed constraintand utilities had little difficulty earning their reg-ulated rate of return on investment while achiev-ing steady reductions in the cost of electricity bybuilding larger, less capital-intensive powerplants,Hence, utility decision making objectives of main-taining service reliability, maximizing corporatefinancial health, and minimizing rates could gen-erally be pursued simultaneously.

Because of the complex and uncertain invest-ment decision environment that has evolvedsince the 1970s, utilities have begun to consideroffering varying levels of service reliability andto more sharply weigh trade-offs between stock-holders’ and ratepayers’ interests in making newplant investment decisions.In many instances,utilities are avoiding making large-scale plantcommitments and, indeed, are considering thehost of options cited earlier that can defer theneed for such commitments.

Utility Investment

of particular interest to many utilities are thepotential benefits of increased planning flexi-bility and financial performance offered by

small-scale, short lead-time generating plants.For example, OTAmodeling studies indicate thatwith uncertain demand growth, the cash flowbenefits of such plants can be considerable. Thisis true, in some cases, even when the capital costper kilowatt of the smaller plants is as much as10 percent more than for large plants. In addi-tion, the corresponding revenue requirement un-der a small plant scenario can be lower over a30-year period.

Electric utility efforts to exploit these financialbenefits and nonutility interest in exploiting po-tentially attractive investment opportunities un-der PURPA have already stimulated considerableinterest from both types of investors in smallerscale generating technologies.Other benefits areimportant as well, including less environmentalimpact, less “rate shock” to consumers by add-ing generating units to the rate base in smallerincrements, increased fuel diversity, and re-duced transmission requirements if generatingunits can be sited closer to load centers.

Most of the generating technologies consideredi n this assessment offer the small-scale moduIarfeatures attractive to many utilities as a means ofcoping with financial and demand uncertainties.This is likely to make the long-term prospects of




these technologies very bright,Despite this long-term promise, however, in most regions for thenext 10 to 15 years most of the new generatingtechnologies are not likely to be competitivewith other often more cost-effective strategic op-tions cited earlier–life extension and rehabili-tation of existing generating facilities, increasedpurchases of power from other systems, and in-tensified conservation and load managementefforts.

Nonutility Investment

Nonutility interest is likely to continue to belimited for the most part to more mature tech-nologies that can be implemented in cogenera-tion applications or can qualify for favorable tax

treatment, e.g., combustion turbines, wind, andmore recently AFBC.

Investors in nonutility power projects seek tomaximize the risk-adjusted return on their in-vested capital. Depending on the type of inves-tor, other considerations are important as well

including tax status, timing of the investment,cash flow patterns, and maintenance of a bal-anced portfolio of investments with varying risk.In order to finance a new nonutility project, themajor risks (technology, resource, energy price,and political) must either by mitigated or incor-porated in contingency plans. Common risk re-duction techniques used to date include vendorguarantees (or having the equipment vendor takean equity position in the prospective venture) ortake-or-pay contracts with utilities.

CURRENT AND FUTURE STATE OFALTERNATIVE TECHNOLOGY INDUSTRY

Many of the new generating technologies con-sidered in this assessment are being developedby a much wider range of firms than has tradi-tionally dealt with the electric utility industry.Moreover, many firms involved in deployingsome new technologies, to the extent that theyare being deployed, are small independent firms,less than 3 years old. For example, the wind in-dustry’s equipment sales have for the most partbeen to third-party financed wind parks sellingpower to utilities under PURPA; many of theseparks have been developed by the wind manu-facturers themselves. Other developers are largeaerospace, petroleum, or other companies thathave also not traditionally dealt with electric util-ities, and many of them are only beginning to de-velop working business relationships with them.

Most of the technologies considered in thisassessment are in a transition phase of their de-velopment, i.e., between pilot- and commercial-scale demonstrations or early commercial units.

Some of these technologies are progressingthrough this transition aided by the existence ofauxiliary markets (in many cases foreign) otherthan the grid-connected power generation mar-ket. For example, small-scale AFBC technology

has matured in the industrial marketplace, pri-marily in process heat applications. Similarly,while the PV technology that will ultimately beginto penetrate grid-connected power generationmarkets is not yet clear, the various candidates(flat plate, amorphous silicon, concentrators, etc.)are maturing in other markets such as consumerelectronics or remote power applications.

As most of these technologies mature and therelationships of vendors and manufacturers withutilities and nonutility power producers de-velop, the nature of negotiated agreements be-tween the parties initiating commercial demon-strations or early commercial units may dictatethe pace of commercial deployment of the tech-nologies. In particular,the allocation of risks inthe form of performance or price guarantees orother mechanisms will be especially importantfor the electric utility market. For example, anequipment manufacturer’s agreement to hold anequity posit ion in early commercial projectsmight be viewed by many utilities as an adequateperformance guarantee.

One of the problems facing increased deploy-ment of some new generating technologies in the




1990s, as mentioned earlier, was that of poten-tial delays in lead-times of early commercialprojects. While the features of smaller scale andmodular design for many of these technologiesoffer ultimate promise for very short lead-times,experience to date indicates that the rate of de-

ployment of some new generating technologiesis being lowered because lead-times being ex-perienced by early commercial projects havebeen longer than anticipated, partially due tothe time needed to complete regulatory reviews.As regulatory agencies become more familiarwith the technologies, the time to complete suchreviews should decrease, although this is by nomeans guaranteed as evidenced by the historyof other generating technologies.

The pressures of competition from foreign ven-dors, many of whom are heavily supported by

their governments, as well as the current lack ofU.S. demand for some of these new technologiesin grid-connected power generation applications,and the pending changes in favorable tax treat-ment throw into doubt the continued commit-ment of U.S. firms who are currently develop-

ing these technologies. For some technologies,such as wind turbines, solar thermal-electric tech-nologies, and photovoltaics (at least those focus-ing on concentrator technologies), the survivalof some domestic firms may be at stake. Manydomestic firms may not be able to compete inworld markets over the next decade. However,in some cases foreign markets are considered tobe interim markets for technologies as they ma-ture to the point where they can compete in theU.S. grid-connected power generation market.

FEDERAL POLICY OPTIONSAccelerated demand growth, coupled with cur-

rent problems in building conventional, centralstation powerplants, could lead to serious diffi-culty in meeting new demand in the 1990s.A sa result it may be prudent to ensure the avail-ability of an array of new generating technol-ogies. Then, the buyers in the market for gener-ating technologies will have a broader range oftechnologies from which to choose. To ensure

this availability will probably require a sustainedFederal involvement in the commercialization ofnew electric power generating, storage, and loadma nag ement tec hnologies. The most log ica l go alsfor the Federal initiatives are:

q

q

q

q

reduce capital cost and performance uncer-tainty,encourage utility involvement in developingtechnologies,encourage nonutility role in commercializ-ing developing technologies, andresolve concerns regarding impact of decen-tralized generating sources (and load man-agement) on power system operation.

The first three are primary goals while thefourth is less critical although still important. Therelative importance of these goals as well as the

efforts to achieve them are at the center of thedebate over future U.S. electricity policy. A rangeof possible initiatives is summarized in table 2-4along with the Federal actions that would mostlikely be required to implement them.

Research, Development,and Demonstration

Perhaps foremost among the options necessaryto accelerate technology development is a sus-tained Federal presence in research, develop-ment, and demonstration of new electric gener-ating and load management technologies. Whilemost of these technologies are no longer in thebasic research phase, development hurdles arestill formidable and the importance of research,development, and demonstration remains high;if these hurdles are overcome the result couldbe a quick change in competitive position formany of these technologies. For example, proofof satisfactory reliability during a commercial

utility-scale demonstration of AFBC could sub-stantially accelerate its deployment among elec-tric utilities. As noted, the technology already isbeginning to be deployed very quickly in smallerscale commercial cogeneration applications.




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 demonstrationShorten project lead-times and direct R&D to near-termcommercial potentialIncrease assistance to vendors marketing developingtechnologies in foreign countriesIncrease resource assessment efforts for renewableenergy and CAES resources (wind, solar, geothermal,and CAES-geology)Improve collection, distribution, and analysis ofinformation

Encourage nonutility role in commercializing developing technologies: 1. Continue favorable tax policy2. Improve nonutility access to transmission capacity3. Develop clearly defined and/or preferential avoided

energy cost calculations under PURPA4. Standardize interconnection requirementsEncourage increased utility involvement in developing technologies: 1. Increase utility and public utility commission support

of research, development, and demonstration activities2. Promote involvement of utility subsidiaries in newtechnology development.3. Resolve siting and permitting questions for developing

technologies4. Other legislative initiatives: PIFUA, PURPA, and

deregulationResolve concerns regarding impact of decentralized generating sources on power system operation: 1. Increase research on impacts at varying levels of

penetration2. Improve procedures for incorporating nonutility

generation and load management in economicdispatch strategies and system planning


A critical milestone in utility or nonutilitypower producer acceptance of new technologyis completion of a successful commercial dem-onstration program. The utility decisionmakingcaution cited earlier confers added importanceto advanced commercial demonstration proj-ects, While there is considerable debate in theindustry over what constitutes an adequate dem-onstration, two basic categories are often distin-guished: One is a proof-of-concept phase whichprovides the basic operational data for commer-cial designs as well as test facilities designed toprove the viability of the technology under non-Iaboratory conditions and to reduce cost and per-formance uncertainties. The other involves mul-tiple applications of a more or less maturetechnology designed to stimulate commercialadoption of the technology. Generally, activities

in the first category are necessary for demonstrat-ing commercial viability and activities in the sec-ond category are necessary for accelerating com-mercializat ion.

The length of the ap prop riate de mo nstrationperiod will vary considerably by technology.However, adequate demonstration periods (per-haps many years for larger scale technologies) arecrucial to promoting investor confidence.More-over, the nature of the demonstration program —i.e., who is participating, who is responsiblefor managing it, and the applicability of the pro-gram to a wide variety of utility circumstances

—is of equal importance. Among the most suc-cessful demonstration ventures have been andare likely to continue to be cooperative venturesbetween industry (manufacturers and either util-ities or nonutility power producers) and the Fed-eral Government, with significant capital invest-ments from all participants in the venture. Thecurrent AFBC, IGCC, and geothermal demonstra-tions are good examples. In particular,for largerscale technologies in utility applications, coop-erative industry-government demonstration ef-forts, managed by the utilities, have a good trackrecord. For accelerated deployment, similarprojects would be required for fuel cells, CAES,advanced battery technologies, and central re-ceiver solar thermal powerplants.

The relationship between utilities and publicutility commissions in early commercial applica-

tions of new generating and load managementtechnologies is an important factor that will af-fect the deployment of these technologies in the1990s. In particular, increased research, devel-opment, and demonstration activity will requireutilities and utility commissions to agree onappropriate mechanisms for supporting suchactivities. Direct support alone from the rate basefor research activities (e.g., as the allowance forcontributions to the Electric Power Research in-stitute) may be desirable and important, but theyare not sufficient to assure extensive deploymentof these technologies by the 1990s.Much largercommitments that involve large capital invest-ments such as major demonstration facilitiesmay only be justified by a sharing of the risk be-tween ratepayers, stockholders and, if other util-ities would benefit substantially, taxpayers. One



Ch. 2—Summary Ž 35

mechanism for supporting such projects is to fi-nance a portion of a proposed project with anequity contribution from the utility and the restthrough a “ratepayer loan” granted by the pub-lic utility commission. The public utility commis-sion might argue that a candidate demonstration

project is too risky for the ratepayer to be sub-sidizing it, particularly if other utilities could ben-efit substantially from the outcome if successfuland are not contributing to the demonstration,i.e., sharing in the risk. In such cases, there couldbe a Federal role; for example, the ratepayer con-tribution to the demonstration could be under-written by a Federal loan guarantee.

Other Policy Actions

In addition to maintaining a continued pres-ence in research, development, and demonstra-

t ion and implementing environmental policyaffecting power generation,several other Fed-eral policy decisions affecting electric utilitiescould influence the rate of commercial devel-opment of new generating technologies over thenext several years. These include removal of thePowerplant and Industrial Fuel Use Act (PIFUA)restrictions on the use of natural gas, and mak-ing PURPA Section 210 benefits available toelectric utilities. These steps could increase therate of deployment of developing generatingtechnologies, but their other effects will have tobe carefully reviewed before and during imple-

mentation.A more liberal power generation exemptions

policy under PIFUA or an outright repeal of theAct could, in addition to providing more short-term fuel flexibility for many utilities, be an im-portant step toward accelerated deployment of“clean coal” technologies such as the IGCCwhich can use natural gas as an interim fuel.Some new technologies such as CAES and sev-eral solar thermal technologies use natural gasas an auxiliary fuel and would require exemptionfrom PIFUA.

Permitting utilities to participate more fullyin the PURPA Section 210 benefits of receivingavoided cost in small power production is likelyto result in increased deployment of small mod-ular power generating technologies, particularly

cogeneration. For example, utilities are currentlylimited to less than 50 percent participation inPURPA qualifying cogeneration facilities. In ad-dition, with full utility participation in PURPAratepayers likely would share more directly in anycost savings resulting from these kinds of gener-

ating technologies. Allowance of full PURPA ben-efits for utilities, however, could cause avoidedcosts to be set by the cost of power from the co-generation unit or alternative generation technol-ogy. Such avoided costs would likely be lowerthan if they were determined by conventionalgenerating technologies as now is the case. Loweravoided costs would reduce the number of co-generation and alternative technology powerprojects started by nonutility investors. Expandedutility involvement, though, may more than com-pensate for this decrease.

In relaxing the PURPA limitation potential prob-lems require attention, including ensuring thatutilities do not show preference for utility-initiatedprojects in such areas as access to transmissionor capacity payments. Moreover, project ac-counting for PURPA-qualifying projects wouldprobably need to be segregated from utility oper-ations and non-PU RPA qualifying projects in or-der to prevent cross-subsidization which wouldmake utility-initiated projects appear more prof-itable a t the rate pa yers’ e xpense. These c onc ernscan be allayed through carefully drafted legisla-tion or regulations, or through careful State re-view of utility ownership schemes.

Finally, as perhaps a logical next step to PURPA,a number of proposals for deregulation of theelectric power business have been proposed inrecent years, ranging from deregulation of bulkpower transfers among utilities, to deregulationof generation, to complete deregulation of theindustry. While OTA has not examined the im-plications of alternative deregulation proposals,such proposals, if enacted, would almost certainlyhave an impact on new generation technologies.The experiences of PURPA and the SouthwestBulk Power Transaction Deregulation Experimentwill be important barometers for assessing the fu-ture prospects and desirability of deregulatingU.S. electric power generation.It is important tonote that allowance of full PURPA benefits for util-ities 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 forsmaller generating units.

Renewable Energy Tax Credits

Along with direct support for research and de-velopment and joint venture demonstrationprojects, an important component of the Federalprogram for new generating technology commer-cialization has been favorable tax treatmentthrough such mechanisms as the RenewableEnergy Tax Credits (RTCs), the Investment TaxCredit (ITC), and ACRS depreciation allowances.The RTC, in particular, coupled with recoveryof full utility avoided costs (under PURPA) bynonutility power producers have been crucialin the initial commercial development and de-ployment of wind and solar power generatingtechnologies. With declining direct Federal sup-port for renewable technology development, theRTC has supported development of advancedand innovative designs as well as commercialdeployment of mature designs. Without con-tinued favorable tax treatment, deployment ofsolar, wind and geothermal technologies is likelyto be slowed significantly—certainly in nonutil-ity applications. Without existing tax incentives,many of the mostly small firms involved in de-velopment projects will lose access to existingsources of capital. Even large, adequately capital-ized firms may lose their distribution networks,making industry growth more difficult.

With favorable tax treatment, some new tech-nologies, such as geothermal and wind, have be-come important sources of new and replacementgenerating c ap ac ity in the West a nd Southwest.However, they must compete with more mature,modular technologies, e.g., conventional cogen-eration technologies. And these modular tech-nologies will continue to account for an impor-tant share of the new generating capacity, in theform of both utility and nonutility owned (andperhaps joint) ventures.

Figure 2-1 shows the cumulative effect of tax

benefits, including accelerated depreciation al-lowances (ACRS), ITCS, and RTCs on the real in-ternal rate of return for technologies considered

in this assessment under the condition of non-utility ownership. (IGCC is not included in thisfigure since it is unlikely to be developed in non-utility power projects.)The figure shows that theRTC may be crucial to the commercial survivalof the renewable technologies with the possi-

ble exception of wind which may be matureenough to survive without these credits. Thenumber of firms involved in wind technologydevelopment, however, would probably de-crease markedly without these credits.

The role of the RTC in accelerating commer-c ial de velopment seem s to ha ve c hange d. Theoriginal Federal policy was to provide direct re-search support to develop the technology and theRTC to ac ce lerate c omm ercial de ployment.Withdecreased Federal research and developmentsupport, the RTC appears to be supporting re-search and development in the field; this mightpartially explain the wide variation in perform-ance of wind projects in recent years.

A frequently proposed alternative to the RTC,in order to ensure performance of projects claim-ing a credit, is a Production Tax Credit (PTC)which provides benefits only with electricity pro-duc tion. OTA a na lysis of the PTC shows that ge o-thermal and wind technologies benefit most froma PTC. others such as CAES and the direct so-lar technologies are aided only by a very largePTC. Similarly, tax benefits tied to productiondiscourages producers from testing innovativedesigns since, if the design does not perform asexpected, no benefits will be realized. Anotherpotential problem with the PTC is that monitor-ing electricity production may be difficult, par-ticularly in applications that are not grid con-nected .

Other actions cited earlier for stimulating de-velopment in new technology within electric util-ities may be more effective than tax preferences.For example, the decrease in the Ievelized perkilowatt-hour busbar cost for the renewable tech-nologies considered in this assessment, with a 15

percent tax credit over and above the existing taxbenefits currently afforded to utilities, is less than10 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 Return a

1

,

.

voltaics turbines thermal cells”Atmospheric

fluidized-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 FiguresFigure No. Page

3-1. Utility Investment Alternatives . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 413-2. Alternative Power Generation in California . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 433-3. Projetions of U.S. Electric Load Growth . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 453-43-53-63-73-83-9

3-1o3-113-123-133-14

3-15



Chapter 3

Electric Utilities in the 1990s:Planning for an Uncertain Future

INTRODUCTIONOverview

In the early 1970s, the U.S. electric power in-dustry entered a new era. Long a stable force inthe U.S. economy, the industry as a wholeemerged in the 1980s under considerable financialstress and uncertainty, precipitated by skyrocket-ing fuel prices, escalating capital and construc-tion costs, and a declining and erratic demandgrowth.

Even as utilities recovered from the shocks ofthe 1970s, it was clear that they would not re-turn to business as usual, circa 1960s. The highlyuncertain decision environment has forced util-ities to reexamine their traditional business strat-egies as they look to the 1990s and beyond. in-deed, the basic procedures traditionally used byutilities in making future investment decisions

have, in many cases, been drastically changedby the utilities themselves as well as by securityanalysts, investors, regulators, and ratepayers.

In this chapter we examine the strategic optionsbeing considered by utilities over the next twodecades and, in particular, focus on the circum-stances under which investment in new gener-ating technologies might play a significant rolefor electric utilities through this period, comparedwith other strategic options. These other cptionsinclude continued reliance on conventional sup-ply sources, life extension and repowering of ex-isting plants, increased purchases of power fromneighboring utilities, or diversification to othernonutility lines of business (see figure 3-1). In ad-dition, we review the arguments for and againstthe use of alternative technologies under differ-ent planning scenarios.

Figure 3-1 .—Utility Investment Alternatives

q

q Financial impact: — Cash flow — Coverage ratio — Return on equity — Capital requirements — Percent of rate

capitalized — Internal cash generation — AFUDC percent of

earnings — Construction costs

q Cost/benefit of reliability. Risk:

— Fuel availability — Operational securityq Financial exposure:

— Construction delays — Licensing uncertainties — Rate base asset



The extent to w hic h new g enerating tec hnol-ogies might play a role in electric utilities in the1990s depends on how favorably such technol-ogies compare with capital investments in con-ventional generation alternatives. It also dependson the managerial skills and financial resourcesof individual utilities. The role of nonutility pro-ducers of electricity is discussed later.

A number of1982 surveysl suggested that util-ities are not very interested in investing in newgenerating technologies. A variety of contingen-cies—such as persistent cost-control problemswith large, central-station coal or nuclear plantsnow under construction or increased environ-mental control requirements, e.g., to reduce acidrain—however, are beginning to make suchinvestments look much more appealing to utili-ties in the 1990s.

Currently, much of the investment in new elec-tric generating technologies in the United Statesis not being undertaken by utilities at all, but bynonutility owners generating power under theprovisions of the Public Utility Regulatory PoliciesAct of 1978 (PURPA) (see box 3A). To date, muchof this investment has gone into cogeneration.in some utility service areas, e.g., in California,the rate of growth of new generating technologiesis steadily increasing (see figure 3-2).2 Hence, thedegree to which nonutility investment in newgenerating technologies (and load management)affects the total generation mix is also an impor-

tant ingredient in the future of the U.S. electricpower system.

The ultima te p enetration of new tec hnologiesover the next two decades in many regions maywell hinge on the relationship which evolves be-tween uti l i t ies and nonutil i ty owners. I t willdepend on the stringency of the utilities’ inter-connection requirements and on the rates the

1“Plans and Perspectives: The Industry’sView, ’’EPR/ journal, Oc- tober 1983; Douglas Cogan and Susan Williams,Generating FnergyAlternatives: Conservation, Load Management, and Renewable

Energy at America’s E/ectric Uti/ities (Washington, DC: InvestorResponsibility Research Center, Inc., 1983);A Review of Energy Supply Decision Issues in the U.S. Electric Utility Industry (Wash-ington, DC: Theodore Barry & Associates, September 1982).

ZTh is rate of growth has been so fast in California that the Statedeclared a temporary moratorium oncogeneration projects in late1984; the figure shows both utility andnonutility involvement inalternative technoloev Droiects.

nonutility electricity producers receive for theirelectricity from the utilities. At present, these re-quirements and rates vary greatly across theUnited States (see chapter 7).

“, , J



Ch. 3—E/ectric Utilities in the 1990s: Planning for an Uncertain Future q 43

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. Perhapsthe most important feature of this legislation wasnot so much its guidelines for standardization,but more its general mandate for the industry:

Provide an abundant supply of electric powerwith the greatest possible economy and with re-gard to proper utilization and conservation ofna tu rat resourc es.

In practice, this mandate was interpreted as re-quiring the provision of power at any time of dayand in any quantity demanded.4 As a result, the




primary objective of electric utility operations inthe United State s is to m eet the c ollec tive d ema ndpresented by all of its customers. The FederalPower Act required that this demand be met inan economically efficient manner both in dis-patching generators to meet the daily load as wellas in developing plans for new construction.

Until the late 1960s, electric utilities had beenable to reliably and economically plan additionsto their installed generating capacity to meet fu-ture demand while retiring aging plants. Until thattime, demand growth forecasts had been reason-ably accura te , powerplant const ruct ion leadtimes had been reasonably predictable, and con-struction as well as fuel cost changes had beensmall. Construction costs (per kilowatt installed)in fact decline as power-plants are scaled up insize. Electric utilities were viewed as sound in-vestment opportunities by the capital markets.Thus, ca pita l was ava ilab le at relatively low c ost.

Since the late 1960s, however, several factorshave combined to create problems for the elec-tric utilities. Both their financial performance andability to make system planning decisions usingthe planning tools of the past have deterioratedas a result. Among these factors (discussed inmore detail in the next section) are: 1 ) the grow-ing difficulty of making demand forecasts—theindustry as well as nearly all interested partiesconsistently underestimated the potential for con-servation, i.e., the price elasticity of demand; 2)

the dramatic increase in environmental protec-tion costs resulting from the public’s growing con-cern over the environmental effects of electricpower production, especially air pollution fromcoal; 3) the unprecedented and escalating costof new powerplants, especially nuclear power-plant construction due to unexpected delays, in-flated capital costs, stricter safety standards (espe-cially after Three Mile island), unpredictableregulation, and uneven projec t ma nage ment; and4) high as well as uncertain fuel prices and sup-plies. The leg ac y of this trauma tic p eriod has beenan industry in which both investors and utility

managers are acutely aware of the industry’s fi-nancial fragility and uncertain demand outlookand are therefore more cautious about commit-ting their capital to large new coal and nuclearplants.

The prognosis for the power industry is uncer-tain. While it is possible that demand growth ratesmay increase once again over the next decade,it is also possible that changing industry fuelchoices, saturation of electricity use in buildings,and improved efficiency of electricity use in allsectors of the economy as well as other conser-vation measures may moderate demand growthto less than 2 percent per year. Most current esti-mates range from 1.5 to 5 percent per year (seefigure 3-3). The issue o f unc erta inty in dema ndgrowth is discussed in more detail in a previousOTA assessments

In the following, the impact these interrelatedfinancial, regulatory (including environmental),and cost escalation stresses have had on the deci-sionmaking environment in the electricity indus-try are sketched in more detail.

Increasing Fuel Prices andSupply Uncertainty

Figure 3-4 shows the national average fossil fuelprices paid by electric utilities in the United Statesover the last decade; weighted average fossil fuelprices more than tripled between1970 and 1980.Those utilities relying on significant levels of oiland natural gas (principally the East and South-west—see figures 3-5 and 3-6) are shifting theirgeneration mix to more capital-intensive nuclearand coal generation due to the uncertain futurecosts and supp ly of oil and natural ga s. The re-

cent stabilizing of oil and natural gas prices andexcess supply of natural gas has only added tothe uncertainty about future supply and prices.b(The reg iona l variations in ge neration mix, fuelsand other factors are discussed in chapter 7.)

Increasing PowerplantConstruction Costs

Increased attention to environment and safetyissues over the last decade has contributed toboth extended lead times in the siting, permit-

w,s. congress, officeof Tec hnolog y Assessme nt, Nuclear Powerin a n Age of Uncertainty (Washington, DC: U.S. Government Print-ing Office, February 1984), OTA-E-216,c h. 3.

%ee U.S. Congress, Office of Technology Assessment,U.S. M t-

ura l Ga s Avai/abi l l ty : Gas Supply Through the Year 2000 (Wash-ington, 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 projectionscomparison of annual 10-year forecasts

(contiguous United States)

Net energy projectionscomparisons of annual 10-year forecasts

(contiguous United States)

.

1 I I I 1 1 1 1 174 76 78 80 82 84 86 88 90

Average annualgrowth rate (o/o)

projecting 10-years1974 -7.61975 -6.91976 -6.41977 -5.71978 -5.21979 -4.71980 -4.01981 -3.41982 -3.01983 -2.81984 -2.5

Average annualgrowth rate (o/o)

projecting 10-years1974 -7.51975 -6.71976 -6.31977 -5.81978 -5.31979 -4.81980 -4.1

1981 -3.71982 -3.31983 -3.21984 -2.6




Fiqure 3-4.—National Average Fossil Fuel Prices

7An investor-owned electric utility today requires about $2.86 ofinvestment per dollar of annual revenue compared with a dollaror less of investment per dollar of revenue for manufacturing in-dustries; the electric utility industry (investor-owned) in the United



Ch. 3—E/ectric Utilities in the 1990s: Planning for an Uncertain Future q 47

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

I1

100

90m

\

,

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

Installed capacity

F

1983 1984Year

Key:

1993

I Total net electricity generation

1982 1984 1993Year



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

1971 1978 1982-84Year

Key:

tion has been permitted by some utility commis-sions. The issue of allowing CWIP in the rate baseis discussed in more detail in chapter 10. Today,over a half of the total earnings nationally byinvestor-owned utilities is AFUDC (see figures 3-11 and 3-12).

The g eneraI de terioration o f financ ial perform-ance of utilities has strained stockholder confi-dence. Indeed, in an effort to maintain this con-fidence many utilities have actually borrowed atshort-term high interest rates to pay out dividends

to shareholders.lo Likewise, the consistently highloperhaps a Milestone irl recent utility history wa s Consolida ted

Ediwn’s missed dividend payment in 1974 (see Foley, op. cit., 1983);more recently missed dividends by Public Service of New Hamp-shire, Consumers Power, and Long Island Lighting Co. are signal-ing concern to investors.



Ch. 3—E/ectric Utilities in the 1990s: Planning for an Uncertain future q 4 9

Figure 3-8.–Capital IntensityUtilities, 1982

I

of Electric

“

Electric Fabric Primary Telephone Petroleum Motor Aircraft

3-1 3). Again, these ratings have increased since1983, but remain below the 1960s’ levels. And,it did not go unnoticed by investors that thelargest municipal bond default in American his-tory occurred within the electric power industryin 1983, when the consortium of utilities knownas the Washington public Supply System de-

faulted on $2.25 billion of bonds on two nuclearpowerplants. Many of the important financial in-dicators are summarized in table 3-2.

Financial Impacts of theNuclear Experience

Beginning in 1983, the difference in financialperformance between utilities involved in nuclearconstruction programs and those who are not hasbecame particularly apparent. It is reflected, forexample, in stock price—see figure 3- I 4. Sinceearly 1983, the market-to-book ratio for the in-

dustry as a whole has risen substantially, but util-ities involved in major nuclear projects havelagged behind. For nearly half of the industry cur-rently involved in nuclear construction programs,the status of these p rojects and t he ec onomic reg-

Figure 3-9.— Electric Utility Market to Book Ratios, 1962-84

, .O 2 . 5 3 mU.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 ’83Year



50 q NewElectric Power Technologies: Problems and Prospects for the 1990s

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

Number of ra te Amounts Amounts PercentYear increases filed requested approved approved






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

19

18

17

1615

14

13

12

11

10

9

8

7

6

5

4

3

2

1

0

Net incomeAFUDC

37 ”/0

49 ”/0420/o

54 ”/ 0

50%0

54%0

ulatory response to cost overruns, plant abandon-ments, and excess capacity if the plants are com-pleted, will weigh heavily on these utilities’financial performance over the next decade. De-spite the fact that some utilities have demon-strated that the difficulties with nuclear technol-ogy are not insurmountable,11 OTA conc ludedlast year that:

Without significant c hang es in the tec hnol-ogy, manage ment, and the level of public ac -

— .1 ITle 85 nuclear plarrtsoperating in the United States today gen-

erally have an economical and reliable operating history; this is rein-forced by the 227 nuclear plants now operating in foreign coun-tries (a total of 531 plants are now operating, on order or underconstruction worldwide); see E. Meyer, et al., “Financial Squeezeon Utilities: Who Really Pays, ”Public Utilities Fortnight/y, vol.114,No. 12, Dec. 6, 1984, pp. 31-35.

ce pta nc e, nuclea r powe r in the United State s isunlikely to be expanded in this century beyondthe reactors already under construction.lz

Moreover, if utility commissions consider gener-ating reserve margins excessive, they may not in-clude all or part of expenditures in the rate basefor some plants currently under construction.

The c onseq uenc es of ec onom ic regulato rytreatment of such plants could range from utilitybankruptcies to large rate increases, often re-ferred to as “rate shock” for customers. Such de-

cisions will bring the issue of the ratepayers’ versusstockholders’ interests into sharp focus over thenext decade; indeed many alternative proposals

12oT_A, NUC/ear p o w e r in 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, fo rexample , National Science Foundation, Division of pol-icy Research a nd Analysis, “ Workshop on Alternative Elec tric Pow erPlant Financing and Cost Recovery Methods, ” Washington, DC,May 7, 1984.

And finally, management of nuclear power-plant construction projects in the utility industryhas been very uneven. Problems have occurredin all phases of nuclear construction programsfrom project design through quality control andcost control .14

Summary

The current state of affairs in the electric util-ity industry is one of considerable uncertaintyover future demand growth, powerplant costs,and cost of capital. As a result, few utilities arewilling to increase their investment risk and manyhave canceled or at least deferred large-scale,long lead-time construction programs. And inter-est by the industry in alternatives to the traditionalstrategy of building conventional large-scale gen-eration plants is growing.In particular, these aker-natives include intensified load management andconservation (either through direct load controlor indirectly through the rate structure); rehabili-tation of existing generating plant; and increasedi n t e r c o n n e c t i o n w i t h n e i g h b o r i n g u t i l i t i e s .Another alternative being considered is construc-tion of smaller, and possibly decentralized, gen-eration facilities that permit more flexible track-ing of demand growth and reduced exposure toinflation and capital market fluctuations; more-

lqsee, forexample, 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 1973-75Ratio of internally generated funds to capital

expenditures. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0.8 0.5 0.3Interest coverage ratio (pretax) . . . . . . . . . . . . . . . . . . . . >5.0 3.0 2.4Interest rate ( 0 /0). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . < 4.6 6.0 8.5Inflation rate ( 0 /0) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.25 4.5 8.0Common stock price (o/o of book value) . . . . . . . . . . . . 250 150 95Construction activity initiated . . . . . . . . . . . . . . . . . . . . . Average Heavy Cutbacks

Electric rates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Decreasing Steadily AcceleratingincreasingAverage return on equity (o /o ) :

IncludingAFUDC. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13 12 11Excludina AFUDC . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12 9 7.2

“Recovery” “Present”1980 1984

0.423.0

15.2713.573

IncreasedcutbacksIncreasing

0.423.38

10.793.5

95VerylittleStill

increasing11.4 13.97.4 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.




Figure 3-14.—Stock. Price Performance of Nuclearand Nonnuclear Utilities

130

over, the smaller facilities enter the rate basemore quickly. Also, utilities are increasingly in-

terested in the potential contribution of new gen-erating technologies which use both conventionaland renewable energy resources. The questionis how utilities will incorporate the characteris-tics of these new technologies into both theirplanning and operations, because they are gen-erally quitegeneratingowners arerole in the

different from those of conventionalalternatives. In addition, nonutilitylikely to play an increasingly crucialapplication of these technologies.

The ne xt sec tion reviews the t rad itiona l d ec i-sionmaking process in the electric utility indus-try and the forces that are changing that proc-ess. Of particular importance to the industry overthe next two decades will be the ability of anygiven utility’s management to answer the follow-ing questions:

q

q

q

Are the benefits of smaller scale, shorter lead-time plants—their lower financial risk, short-term financial sustainability, and greater flex-ibility in filling unpredicted demand—com-pelling enough to consider them more care-ful ly as an a l ternat ive to convent ionallarge-scale, long lead-time plants?If the benefits of smaller, shorter lead-timeplants are considered sufficient along withother benefits such as increased efficiencyor reduced emissions, what conventionalsmall-scale alternatives and what unconven-

tional new technologies will be considered?To w hat de gree w ill use o f c onventionalalternatives preclude significant use of newtechnologies?If unconventional new technologies are per-ceived as potentially important in a utility’sfuture resource plan, what ins t i tu t ionalchanges might be necessary to accommo-date these technologies? Will nonutilityownership 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 Reliabilitytives of utility decisionmakers are to: 1) ensurethat system reliability is maintained, 2) minimizetheir ratepayers’ burden over time, and 3) main-tain the financial health of their companies. Anydecision analysis of investments must addressthese objectives. Of increasing importance, par-ticularly in evaluating the potential for new tech-nologies, is the degree of uncertainty affecting thecompany’s future demand, cost of service, andperformance. Accounting for this uncertainty isbecoming a much more important componentin the decision making process of most utilities.

I Sother measures are reported in General Electric CO .,17e/;ab;/-ity /nd;cesfor Power Systems, final report prepared for ElectricPow er Resea rch Institute (EPRI) (Palo Alto, CA:EPRI, March 1981),EL-1773, RP1 353-1.



analyze peak demand predictions, at full as wellas partial outage estimates of their generation andmajor transmission facilities, in order to projectreserve margins required to meet the LOLP con-straint.

The critical uncertainties in this reliability anal-ysis include: 1 ) the annual peak demand forecast,2) scheduled and forced outage occurrences ofneeded generating units, 3) the power output ofneeded generating units, 4) the on-line dates ofany new generating c apa city that ma y be plannedfor the period in question, and 5) the availabilityof purchased power. Other factors such as loadmanagement or conservation efforts and dis-persed sources of generation, e.g., cogeneration,add an additional element of uncertainty to theutility’s reliability analysis. (See chapter 6.) Thisis because there is uncertainty regarding the ex-tent to which conservation will moderate elec-tricity demand and load management will alterdemand patterns. Further, there is uncertaintyabou t the marke t pene t ra t ion tha t wi l l beachieved by load management devices and bydispersed sources of generation. There is also un-certainty about their reliability.

In recent years, the traditional treatment ofreliability as a fixed constraint—the prescribedLOLP level described earlier–is being called intoquestion. In particular, the trade-off between totalcost and quality of service is becoming an increas-ing concern.16 The a rgume nt be ing a dva nced isthat electricity should be treated more as a com-modity in a segmented market (different customerclasses), one aspect of which is quality of serv-ice which should be reflected in the commoditypric e. The c urrent deb ate , therefore, c entersaround whether electricity should be availableat a uniformly high level of reliability or at increas-ing degrees of reliability for increasing pricelevels.

Minimizing Electricity RatesThe 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 forElec tric G ene ration System s, ”Bell Journal of Economics, vol. 5,No. 2, autumn 1975, pp. 679-694.

applications for changes in rates to State publicutility commissions. Generally accepted ratemak-ing practices are discussed in chapter 8 (box 8A).The objective of minimizing rates is often meas-ured in terms of revenue requirements or the totalcost per kilowatt-hour of electric energy gener-ated . The p rinc ipal cost eleme nts to b e c onsid-

ered when meeting this objective are:1.

2.

3,

In

fixed costs associated with the recovery ofcapital invested in generation, transmissionand distribution facilities;fixed and variable production costs associ-ated with operation, maintenance and fuelexpenses for supply facilities; andoverhead costs associated with generaladministrative expenses and working capi-tal allowances.

order to compare lifetime rate requirementsof different generating technologies, utilities pro-

ject, over the lifetime of each plant, each com-ponent of cost–return on capital, debt servicecost, fuel and operating cost, and share of over-head–and then they apply a discount rate toeach year’s costs to calculate a Ievelized annualcost. Utility decision making is complicated by thefact that pIants with the same Ievelized cost canhave very different year-to-year costs, and thatutility rates are not set according to Ievelized costbut projected actual costs. During times of highinflation and high interest rates, the return on cap-ital and the cost of capital-expensive plants is con-centrated in the early years of a plant’s life. Forfuel-expensive plants the opposite is true–theyear-to-year cost is initially low but increases overtime. The implications of such trade-offs are dis-cussed in more detail in chapter 8.

Maintaining Corporate Financial HealthThe third objective of utility decision makers—to

maintain the financial health of their compa-nies—is typically assessed in terms of some keyparameters such as growth in earnings, debt serv-ice co verage ratios, and return on c omm on eq uity,System planning decisions which satisfy the two

objectives discussed earlier (i. e., maintaining sys-tem reliability while minimizing ratepayers’ bur-den) are also evaluated in terms of their impact,over time, on these measures of corporate finan-cial health.

38-743 0 - 85 - 3



Since the electric utility business is so capital-intensive, it relies heavily on its ability to raisecap ital from de bt and equity sources. The a vail-ability and cost of this capital depends, to a largedegree, on a utility’s financial health as evaluatedby security analysts and investment houses.

When evaluating a utility’s financial health,these analysts weigh a wide range of qualitativeand qua ntitative fa c tors (see tab le 3-3). Theyseem, though, to emphasize five quantitative fac-tors:

1.

2.3.

4.

5.

earnings protection—debt coverage,leverage–equity share of total capitalization,cash flow and earnings quality—share ofAFUDC in total earnings,asset concentration—shares of generating ca-pacity compared to shares of the rate base,andfinancial flexibility .17

In addition, they generally consider five qualita-tive

1.

2.3.4.5.

factors:

prospects for demand growth in the serviceterritory,diversity of fuel supply,quality of management,operating efficiency, andregulatory disposition.

Variations Among Utilities andConflicting Objectives

Prior to the early 1970s, maintaining reliabil-ity was treated as a prescribed constraint and util-ities generally had little trouble earning theirallowed rate of return while achieving steady re-ductions in the cost of electricity, as discussedearlier. In other words, the three investment objectives could in effect be simultaneously pursuedwith little conflict, and the process just describedgenerally explained utility investment decisionsquite well, at least with respect to technologychoice. —

I ~homas Mock le r (Standard & Poor’ s), “ Workshop on InvestmentDecisionmaking in Elec tric Utilities,” sponsored b y U.S. Co ng ress,Office of Technology Assessment, Washington, DC, Apr. 17-18,1984.

Table 3.3.—Elements Considered in the UtilityFinancial Rating Process

Economic analysis of service territory: PopulationWealthEmploymentSize of service area and outlookHistoric and estimated load growth

Demand and energy salesType of system: Self generationDistributionCombinationWholesale and bulk powerFacilities: Fuel mix, cost, availability, and priceCapacity and reserveOperating costOperating ratioDispatching strategiesCapital improvement plans: Realistic construction cost estimatesAlternatives to own constructionRate structure:

Likely regulatory climateComparative ratesAbility to adjustBond security:RevenuesDebt service reserveContingency fundCapitalized interestRate covenantAdditional bonds covenantPower contractsAsset concentrationKey ratios: Environmental concernsNet take-downInterest coverageDebt service coverageDebt service safety marginDebt ratioInterest safety marginPercentage AFUDCPercentage 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 a ctua l imp leme ntation of a de cisionma k-ing process varies across utilities, but there ap-pears to be little difference among utilities in thegenerally accepted practices for making deci-sions. The differences, rather, are mostly incharacterizing the alternatives to be considered.A recent survey of utility decision making18 re -ported that, in spite of the wide diversity of typesof firms in the industry (see box 36),

there is a high degree of uniformity in thePlant investme nt d ec ision ma king prac tices fol-lowed by U.S. electric power firms, both publicand private, as well as other regulated utilities.

In chapter 8 the analytical tools routinely usedby utilities in making investment decisions are dis-cussed. Also discussed are the differences amongutilities, particuIarly with respect to differencesin cost of capital (considerably different, for ex-ample, between public and private utilities), indiscount rates, and in attitudes toward and meth-ods for dealing with risk.

How utilities account for risk is important be-cause it explains in part what might otherwise bea noneconomic choice in selecting a new tech-nology. For example, uncertainty about demandgrowth, long-term financing conditions, or other“state of the world” factors may prompt moresevere discounting for long-term risk against longlead -time p rojec ts. This ha s c erta inly b ee n thecase in recent years in the industry. Similarly, ofparticular relevance to this assessment, concern

over a specific technology may swing a close in-vestment decision one way or the other. The Edi-son Electric Institute19 has classified the critical,supply-option, technology risks facing utility deci-sionmakers, these are summarized in table 3-4.

In addition, and reflected in some of these risks,factors relating specifically to regulatory approvalare of increasing concern and have promptedutilities to carry out what is often termed “short-period analysis. ” In such an analysis, plannersexamine how specific areas of uncertainty, suchas future environmental regulations or fuel avail-

113G. Corey, “ Plant Investme nt Dec ision-MakingIn the Elec trlcPow er Inc iustry, Discounting fo r Time an d Risk in Energ y Policy (Washington, DC: Resources for the Future, 1982), pp. 377-403.

19 Ed i~on E led rlc 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 inthe early years of a project’s life.

This new, more complex investment decisionenvironment of the 1980s has brought with it thepossibility of conflicting objectives in making in-vestment decisions. It has become possible that

utilities could decide not to pursue the lowestprojected lifetime cost option (minimizing rates)for future investments because of its implicationsfor short-term financial performance (maintain-ing financial health). In the long run, maintain-ing financial integrity does indirectly affect theratepayers’ burden, but the relationship is lessclear.

Perhaps to avoid such conflict, some utilitiesin recent years have made substantial changesin the way they make future investment decisions.For example, Pacific Gas & Electric’s (PG&E) key

corporate planning goals published in 198320

statean “adopted direction” including:

q operation within revenue and expense levelsprovided by rate case decisions,

q minimize capital expenditures, andq avoid major commitments of capital to new

energy supply projects.

For PG&E, this meant that “the company willnot be com mitting c apital to any major new elec-tric supply projects, although minimal capital ex-penditures may result from efforts to keep optionsopen .“ Variation in how a utility sets its basic

direction for resource planning depends on reg-ulatory pressure, financial position, and, perhapsmost importantly, the character of utility manage-ment. Some utilities have substantially modifiedtheir “decisionmaking” mechanisms to better ac-commodate uncertainty and trade-offs in invest-ment decisions, e.g., the “short-period” analy-sis described earlier.

The tra d e-offs a mo ng fut ure investm ent s arelikely to be a fundamental issue of debate overthe next decade, and this debate’s outcomecould profoundly affect the deployment of newtechnologies as they mature. Another recent in-dustry survey, cited earlier21 reports that, for the

‘Zopacific Ga s A EleCtriC CO., L o n g Term P/a rming l?ewks: 1984-2004, May 1984.

jlTheo c fore Barry & Associates,Op. cit., ? 982.





Ch. 3—E/ectr/c Utilitiesin the 1990s: Planning for an Uncertain Future q 5 9

Table 3-4.—Technology Risks for ElectricUtility Decisionmakers

1.

2.

3.

4.

5.

6.

7.

8.

.

Technical risk: the probability that a new generator will failto come on-line at its anticipated capacity rating.Lifetime risk: the probability that a new generator’s life-time will be significantly shorter than anticipated due eitherto technical problems or regulatory decision problems.

Cost risk: the probability that a new generation technolo-gy will cost significantly more to construct or operate thananticipated.On4ime completion risk: the probability that a technolo-gy will not come on-line when anticipated because of tech-nical or regulatory problems.Lead-time risk: the probability construction end time willbe longer than planned. One problem is that events changesuch that the probject will no longer be needed or econom-ically viable.Obsolescence risk: the probability that a given technolo-gy will be economically obsolete prior to its planned life-time. This is analogous to the lifetime risk and could resultfrom fuel cost changes or new technologies being in-troduced, etc.Third-party ownership risk: the probability that a genera-tor owned by a third party will become unavailable toproduce electricity for any reason related to the ownershipby a third party, e.g., bankruptcy of the corporate entityowning a cogeneration facility so that the steam no longerexists and the facility is uneconomic without the steamdemand,Reliability and performance risk: the probability y that a par-ticular technology will be significantly less reliable thanplanned.

As utilities emerge from the financially stressedperiod of the 1970s and early 1980s, the trade-offs between financial performance and the rate-payers’ burden will be a subject of continuing de-bate that may affect the structure of the industryitself .22

The Current Context forAlternative Investments

Most utilities have been forced by economicand regulatory uncertainties to broaden the scopeof their analysis of future investments, but this hasnot yet led, in most cases, to investment in newgenerating technologies.

——zz~n on e hancf, some economists argue that a solution to the

utilityind ustry’s financial problems over the long term rests inderegulating portions O( the power generation side of the business:on the other hand, others (e.g., U.S. Department of Energy (DOE),Repo rt of the Elec trlclty Policy Project ,The future otE/ectrlc Power In America: Eco nom ic Supp ly fo r Economic Growth (Washington,DC: National Technical Information Service, June 1983), DOE/PE-0045) argue that agglomeration of existing firms into larger regionalentities addresses the financial problems more efficiently.

A 1982 EPRI survey of member utilities23 posedthe question of what strategic options were con-sidered likely in the event of limited capital avail-ability over the next decade. Options involvingnew technologies fell well down the list of pri-orities, behind strategies such as increased con-servation, deferral of retirements, rehabilitationof existing plant,24 and increased participation in

joint ownership of large conventional plants, Thesurvey did suggest, however, that utilities are con-sidering new technologies as an option to pur-sue in the event of unexpected contingencies andthat “utilities revealed an increased willingnessto consider a host of new technologies for gen-eration before the end of this century. ”

Some utilities25 think that there are three major contingencies that could more or less signifi-cantly affect the relative attractiveness of new sup-ply technologies over the next decade:

q

q

q

Sudden increases in demand growth.–Demand growth in the United States in1983was 1.9 percent and in 1984 it was 4.6 per-cent; demand predictions for the next dec-ade vary from 1.5 to 5 percent.Major reductions in allowable pollutionemissions.—Acid rain and other legislativeinitiatives could alter the kinds ofcoal-bu rn-ing technologies and fuels used over the nextdecade .Limited availability of petroleum.–Whilethe shortages and price increases of the

1970s prompted considerable shifts awayfrom oil in U.S. electric power production,over 10 percent of the Nation’s installed ca-pacity is still oil-fired (see figure 3-7 earlier).Any dramatic changes in oil availability willaffect the rate at which oil use declines i npower generation. This issue is discussed ind ep th in a rec ent OTA a ssessme nt.26

. . —ZjTaylor Moore, eta!., ElectricPower Research Institute (EPRI),

Planning a nd Eva luation Division, “ Plans and Perspe ct ives: Thein-dustry’s View, ”EPR/)ourna/, vol. 8, No. 8, Oct ob er 1983, pp . 14-19

2 4 A l t h o u g h AFBC retrofits of existing unitsI nvolvf?s a new tech-

nology; this option is being pursued aggressively by manyutillties,~sFo r example , Southern Company Services, Inc., Researcha nd

Development Department, “Assessment o f Technologies UsefulInResponding to Alternate Planning Contingencies, ” unpublished,Dece mb er 1983.

ZGU .S. c o n g r e s s , O f f i c e of Technology Assessment, U.S. v’u/ner-abi / i fy to a n O i/ / m p o r r Cur fa i /menf (Washington, DC: U.S. Gov-ernment Printing Office, September 1984), OTA-E-243.




In the more distant future three additional con-tingencies could change utilities’ investment deci-sionmaking priorities:

q

q

q

Natural gas availability .–There is still con-siderable uncertainty in the domestic re-source base for natural gas, although opti-

mism is growing.27 If reserves are significantlygreater than previous estimates suggest, thennatural gas might once a gain bec ome a n at-tractive fuel for electric power generation,although this would require modifications tothe Fuel Use Act.Dramatic changes in interest rates.–As dis-cussed earlier, due to the industry’s capitalintensity, high interest rates have causedelectric utilities much financial stress. Dra-matic decreases in interest rates coulddampen the current interest in short lead-time, modular design technologies relativeto larger central station plants; however, itcould stimulate the interest of non utility pro-ducers in such technologies.Significant technological advances.–Al-though much less Iikely than in other indus-tries such as communications or computers,breakthroughs in technology could improvethe likelihood of utility adoption of new tech-nology o ver the ne xt several dec ad es. Theopportunities for advances in the technol-ogies considered in this assessment are dis-cussed in chapter 4.

In addition, changes in Federal policies suchas the tax system, PURPA, and the Powerplantand Industrial Fuel Use Act could have a signifi-cant impact on investment decisions as well; suchchanges are discussed in chapter 10.

While at the current rate of development ex-tensive deployment of new technologies underany circumstances is unlikely in the 1980s, thefirst three contingencies are likely to affect util-ity decision making with respect to new supplydecisions; the latter three contingencies are notlikely to affect utility decisions until the 1990s.

2 7 0 T A , (-/.s. ~ a t u r a / Ga S Availability: GasSupply Through theYear 2000, op. cit., 1985.

Tradeoffs in Allocated Investmentsand Strategic Planning

In light of economic and regulatory uncertain-ties surrounding the industry, many utilities arenow considering, along with traditional centralstation powerplants (including joint ventures insuch plants with other utilities), such options asdispersed generation, increased levels of pur-chased power, load management (or other end-use related actions), diversification into entirelynew businesses (see figure 3-1 earlier), and newgenerating technologies as possible investments.

With an expanded spectrum of investment al-ternatives along with an uncertain decision envi-ronment, the problem then becomes one of com-paring options that differ considerably in termsof production characteristics as well as in termsof financial risk and return; La for example, howdoes one compare a kilowatt of peak-load reduc-tion achieved through load management to a kilo-watt of new capacity from wind power?

If, for the moment, one takes the quality of serv-ice to be provided by a given utility as a pre-scribed constraint, as utilities have traditionallydone, investment decisions hinge on the relativeimportance of the remaining objectives, namelyminimizing the ratepayers burden and maintain-ing financial health. In recent years in the elec-tric utility industry, as implied in the last section,the latter objective has taken on added com-

plexity.Generally, a utility strives to earn a rate of re-

turn at lea st equa l to its cost o f c ap ital. There-fore long-termprofitability could be defined asthe difference between the return on eq uity (ROE)and the cost of capital29 (k). Short-term cash flowimplications of new investments have emergedas important concerns for many utilities in recentyears, i.e., a utility must generate enough cash

zBDiscUSSecj in Cjetail in D. Geraghty, “Coping With ChangingRisks

in Utility Capital Investments, ”unpublished paper, Electric PowerResearch Inst i tute , February 1984.

2glf a utility’s rate of return equals its cost of capital, stockholdersstill earn a competitive return; see D.Geraghtv, “Coping With Riskin the Electric Utility Industry:The Va lue of A lternative InvestmentStrategies, ” Sec ond International Mathem atics and Com pute r So- ciety (IMACS) Symp osium on Energy M o d e / i n g and Simulation ,Brookhaven National Laboratory, New York, Aug. 27, 1984.






rameters that relate either directly or indirectlyto sustainability and profitability. These parame-ters include the debt service coverage, return onequity, percent internal cash generation, andgrowth in earnings.

For example, an important parameter used inevaluating future cash flow implications is thedebt service or interest coverage ratio which re-flects the ability of the utility to repay its debt obli-gations and is a crucial factor in determining autility’s bond rating. s” Table 3-s demonstratesrelationships between interest coverage ratios,utility bond rating, and average cost of thesebonds. In this connection, year-to-year cash flowwill fluctuate least when new generating plantsare built in small increments and with short lead-times. Therefore, a utility aiming for a stable debtservice coverage ratio could choose not to buildlong lead-time, large powerplants even when

their cost per unit power may be less than thesmaller plants because of engineering economiesof scale (see chapter 8).

Prior studies give some insights into the trade-offs between short lead-time, smaller scale addi-tions to generating capacity and long lead-time,large powerplants. Ford and Youngbloodsl show

JOThe interest coverage ratio accounts for as much as 80 percentof a bond rating decision; see Rand Corp.,E/ectric uti/ity Dec ision 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 a nd Annette Youngblood, “simulating the plan-ning Advantages of Shorter Lead Time Generating Technologies, ”Energy Systems and Po/icy, vol. 6, No. 4, 1982, pp. 341-374; andAndrew Ford and AnnetteYoungblood, “Simulating the Spiral ofImpossibilityin the Elec trica l Utility Industry, ”Energy Po/icy, March1983.

Table 3“5.—Electric Utility Debt Cost and CoverageRatio Relationships

Coverage ratio Bond ratina Averaae vield3.0-3.5 AA 1 1.0%02.5-2,75 11 .3’?/0

2.0 B#B 12.1 YoSOURCES: 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-timescan maintain a lower ratio of capacity under con-struction to installed capacity, when year-to-yearchanges in demand growth are very unpredicta-ble. A lower ratio of capacity under constructionwould, in turn, allow a higher debt service cov-erage ratio. (Short lead-times for purposes of this

analysis were defined as 1 to 2 years planning andpermitting and 3 to 4 years construction.)

32Carl E. Behrens, “Economic Potential of Smaller-Sized NuclearPlants in Today’s Economy,”Co ngressional Resea rch Service pa -per prepared at the request of the Honorable Paul Tsong as, Wash-ington, DC, Jan. 20, 1984, 83-621 ENR.

~JEEI, Strategic / r np / i ca t i onsof AlternativeGenerating Tec hnologies, op. cit., 1984.

JoThe scenario employed assumed a utility witha 5 GW peak demand, 6 GW of installed capacity, a load factor of 65 percent,total embed ded ca pital (excludingCWIP) of $9.6 billion (averageyearly cost of 10 percent–real discount rate) and embedded oper-ating costs of 3cents/kWh. The large plant was 1,000 MW witha 7-year lead-time at a cost of$2,000/ kW (1980 d ollars inc ludinginterest during construction); small plants were 100 MW with in-stalled costs of $2,200/ kW.



Introduction

The spectrum of alternative investments cur-

rently available to many utilities was briefly out-lined in the last section. This section highlightsthe most important considerations in each ofthese options. As mentioned earlier, to the ex-tent that new generating capacity is planned atall over the next decade, the industry as a wholeappears to prefer traditional conventional powergeneration technologies (e.g., pulverized coal-burning technologies and combustion turbines)as the mainstay for strategic planning. The EPRIAnnual Industry Survey for 1982, compared withthe corresponding survey for prior years, did in-dicate, however, that more efficient use of energyhas emerged more prominently in utility strate-gic plans than in previous years.

The EPRI survey also revealed an increased will-ingness to consider new generating technologiesbefore the end of this century, particularly in lightof the future contingencies (see previous section)that could affect the viability of conventionalalternatives. In some utilities where availablerenewable resources are particularly attractiveand plentiful, alternative technologies such as so-lar, geothermal, and wind may contribute signif-icantly to future resource plans, but continued

development of these technologies was viewedby the survey as benefiting only a handful of util-ities over the next several decades.

Strategic options such as rehabilitation of ex-isting plant and increased purchases of energyfrom neighboring utilities have emerged as im-portant alternatives for utilities in the next dec-ade, particularly where capital is in short supply.

Overall, therefore, in considering alternativestrategic options for utilities, it is important tokeep in mind that new generating technologiesnow appear to fall well down the list of priorities

for most utilities, though interest in them is in-creasing as utilities plan for dealing with futureuncertainty.

The business strategies of U.S. utilities, whileactually a continuum, can be classified roughlyinto four basic, but not exclusive, categories:35

q

q

q

Modified grow and build strategy .-A num-ber of utilities have continued to view com-pletion of large nuclear and coal plantsinitiated in the 1970sas their best option. Al-lowing for changes in the fuels used in gen-eration, this is a continuation of the strategyof virtually the entire industry since its be-ginning. Some utilities, confident of reneweddemand growth in the 1990s,are planningfor continued expansion.Capital minimization.–Many utilities in theUnited States are now reacting to the cur-

rent regulatory and financial climate in theindustry with a strategy of minimizing capi-tal expenditures by canceling plants bothplanned and currently under construction,increasing use of purchased power, partici-pating in joint ventures if construction is nec-essary, selling existing capacity, rehabilitat-ing existing plant, and increasing attentionto load management. This strategy is de-signed to minimize corporate risk.Renewable and alternative energy supply.–A few utilities have embarked on a strategyof significantly increasing reliance on renew-

able energy sources as well as cogenerationfrom conventional sources in an effort to usesmall, modular pIants to better track uncer-tain demand growth and reduce construc-tion lead-times (other reasons are discussedlater). The two large utilities (PG&E andSouthern California Edison) that have madereliance on these sources an announced partof their strategy both come from Californiawhere renewable resources are relativelyabundant and avoided energy costs are high.Many more utilities have initiated increasedresearch 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).




q

technologies (discussed later). How many ofthese will go on to base a significant part oftheir strategic planning on alternative sourcesis uncertain.Diversification.–A majority of investor-owned utilities have begun to diversify their

business interests by investing revenues inpotentially more profitable ventures outsidethe electric utility business (see table3-8).While the level of expenditures in such activ-ities is as yet very small, a large number ofutilities are exploring new business ventureson 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 overthe next decade and if emissions requirementsare not tightened, conventional pulverized coalsteam plants are generally the preferred invest-ment op tion for future generation. The future ofnuclear power remains clouded by managementand regulatory problems as well as by technicaland financial uncertainties. The EPRI surveyfound that “business decisions on new nuclearplants will remain clouded’ ’until such uncertain-ties are resolved. This conclusion is supported bythe recent OTA assessment on the future of nu-clear power as well as by others.36

As discussed earlier, the cash-flow drawbacksof the long lead-time, large, conventional coaland nuclear plants as well as the potential costsof overbuilding due to uncertain demand growthhave prompted utility interest in designs for theseconventional technologies that permit installationof smaller, modular units (200 to 500 MW ratherthan 800 to 1,200 MW), even at a significant cap-ital cost premium. In addition, in planning for cir-cumstances such as increased regulation of pol-lution emissions, other utilities have also becomeinterested in other modifications of conventional

coal technologies. These include limestone injec-tion, advanced coal cleaning techniques, im-proved scrubbers, and others.37 Such modifica-

MOTA, NUC/ear Power in an Age o f Unce r t a in ty, 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 thecurrent study, could significantly affect the rela-tive attractiveness of new technologies under allthe possible future contingencies cited earlier.Considered in this assessment are advanced coalconversion processes such as fluid ized-bed com-

bustion and integrated coal gasification/com-bined-cycle units.

Load Management and Conservation

One of the surveys cited earlier38 found that72 percent of the utilities they surveyed had ini-tiated formal conservation programs and overtwo-thirds have started formal load managementprograms (see table 3-6). Fifty percent of theseload management and conservation projects haveap p ea red sinc e 1980. Tot al investm ent in suc hprograms is expected to increase dramatically

over the next decade, particularly in load man-agement. The survey suggests that “virtually theentire industry will have incorporated such activ-ities in a formal way” (see table 3-6). Conserva-tion options are not considered in this report butload management is discussed in chapter S.

Plant Betterment

Many utilities have found it useful to considermeasures of rehabilitating existing generation ca-pacity or improving maintenance to extend theiruseful lives.39 Indeed, some studies have found

a high correlation between maintenance expend-itures, unit availability, and adjusted return onequity, i.e., the difference between the earnedreturn and bond yields. @ Moreover, as life ex-tension options are reviewed more carefully,many units operating at derated capacities, sincethey 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 andoverall efficiencies.41 Some current researchaz

3Kogan & Williams, Investor Resea rch Responsibility C ente r, op .cit., 1983

39 Lee Catalano, “ Utilities Eye Unit Life Extension, ”Power, vol.128,

No. 8, August 1984, pp. 67-68.4oA. C o r i o , N a t i o n a l E m n c m i c Research Associates, research sum-marized 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 Availablefo r oldT/G’s”and Boilers,”E/ectrica/ World, vol. 197, No. 5, May 1983,pp. 87-96.

qzsummary of ongo ing resea rch b y Tem ple, Barker &Soane, Inc.given in “Optimum Use of Existing Plant, ”Uti/ ity /nvestrnents Risk



Ch. 3—Electric Utilities in the 1990s: Planning for an Uncertain Future q 65

Table 3-6.—Conservation and Load Management Programs of Leading Utilities a

Projectedannual

Generating increase Program Projectedcapacity in demand adoption Program costs megawatts saved

Company 1982 through 1992 date(s) in 1982 (000) through 199232,07614,52612,86516,3198,085

12,96615,345

5,8999,023

03,3719,1942,7366,7495,3596,1622,1447,9049,4583,5222,7742,4956,470

10,5642,751

197719751980

1976/771981

1978/8019721980198219801980197619731976198219791980

1977/811968/81

197719821980198319751977

4,0002,9942,1001,8711,7501,7001,5001,500

956802800800671601600600485465450420412400390370318

ity has been built since 1970. In addition, theseprospects vary considerably by region (see chap-ter 7).

Increased Purchases

Interconnection among utilities has alwaysbeen common in the electric power industry butin recent years buIk power transfers have in-creased dramatically. I n fact, the total volume ofbulk power transfers increased by a factor of30between 1945 and 1980 while total electricityproduction increased only by a factor of 10.43 Ingeneral, bulk power purchases are undertakenby a utility if the marginal cost of production inan interconnected utility is less than it would costfor the b uyer to p roduc e tha t p ower itself. Themost significant increases began to occur in theearly 1970s as oil prices forced many utilities

43 u S Depa flrnen[Of E n e r g y, Energy Information Ad WI i n Istratlon,

/nterutl/ity Bu/k Po \ ~e r Transac (lons, (Washington, DC: U.S.G o v -ernment Prlntlng Off i ce , October 1983), DOE/EIA-0418.




Table 3.7.—Replacement of Powerplants:Selected Options

Cumulative replacement capacityGW needed by:

1995 2000 2005 2010If existing powerplantsare retired after:

30 years. . . . . . . . . . . .40 years. . . . . . . . . . . .50 years. . . . . . . . . . . .

If all oil and gas steamcapability is retired asfollows:

All . . . . . . . . . . . . . . . . .Half . . . . . . . . . . . . . . .All oil and gas

capacity above 20percent of region(3 regions). . . . . . . .

If average coal andnuclear availability slipsfrom 70% to:

About 650/o . . . . . . . . .About 600/0 . . . . . . . . .

15555 —

15276

55

2142

230 395105 15520 55

152 15276 76

55 55

21 2142 42

510230105

15276

55

2142

SOURCE: US. Congress, Office of Technology Assessment,Nuclear Power in an Age of Uncertainty (Washington, DC: U.S. Government Printing Of-fice, February 1984) OTA-E-216; this analysis shows the sensitivity toNorth American Electric Reliability Council data projected from 1983,

highly dependent on oil to seek lower cost powerfrom less oil-dependent neighbors and, as a re-sult, the ratio of power purchases and wholesalepower sales to total electricity sales among utili-ties varies by region as discussed in chapter 7.

While there are many different types of bulkpower transactions, most fall into one of threecategories:

1.

2.

3.

economy transactions that reduce operatingcosts by displacing the buyer’s own highercost power with lower cost power from aneighboring utility;capacity transactions which permita utilityto claim additional generating capacity froma neighboring utility to supplement its ownfor a specified period of time (sometimescalled firm power transactions); andreliability and convenience transactions thatare negotiated to improve system operationand reliability—e.g., emergency support.

Some utilities will clearly benefit over the nexttwo decades from increased reliance on pur-chased power from neighbors that have excesscoal-fired and hydroelectric capacity and ade-quate transmission capabilities, and this option



Ch . 3—Electric Utilities in the 1990s: Planning for an Uncertain Future . 67

Table 3-8.—Edison Electric Institute BusinessDiversification Survey a

Venture Percent of total

Developing Supply and StorageTechnologies

The range of technologies considered in thisassessment that may show promise in electricpower generation through the 1990s are includedin table 3-9. A detailed evaluation of the prob-able costs and performance of these technologiesis given in chapter 4. Considered here are someof the generic characteristics of these technol-ogies that might affect a utility’s decision to adoptthem or might encourage nonutility investmentin them.

Table 3-9.-Developing Technologies Considered in

OTA’S Analysisa

Photovoltaics:Flat plate systems (tracking and nontracking)Concentrators

Solar thermal electric:Solar pondsCentral receiversParabolic troughsParabolic dishes

WindGeothermal:

Dual flashBinary (large and small)

Atmospheric fluidized-bed combustorsIntegrated gasification/combined-cy cleBatteries:

Lead acidZinc chlorideCompressed-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 intable 3-9 are small in scale relative to conven-tional alternatives; hence they generally haveshor ter lead- t imes and offer the fol lowingbenefits:

q

q

q

Modularity.–Modularity of units, both in

construction and in duplication of plants ata single site, means that decisions to initiatenew capacity additions can be made closerto the time the units are actually needed. Asa result, there is more flexibility in both track-ing highly uncertain demand growth and inbringing new capacity on line to correct fortemporary undercapacity. Several of the newtechnologies considered in this assessment(see table 3-9) lend themselves to modulardesign–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 newtechnologies .48 Combustion turbines havetraditionally been used by utilities to reducetheir exposure to risk during periods of un-certain demand growth, but they involvevery high operating costs and use of pre-mium oil and gas fuels. The gas industry is,however, very optimistic about the future ofcombined-cycle plants using natural gas.Less “rate shock. ’’–Rate increases can bemoderate with small plants or units comingon line and entering the rate base. If demandgrowth is very large, however, many small

plants or units will be required and “rateshock’ ’could be even more severe sincesmall plants or units of alternative technol-ogies generally come at a capital costpremium. A similar rate shock through fueladjustment clauses might be experiencedwith a strategy of using combustion turbinesto meet such unpredicted, large demandgrowth.Increased reliability.–Generally speaking,smaller units permit maintenance of asmaller reserve margin since individualforced outages of smaller units have less im-pact, although if the system is mixed, i.e.,

4SW. Gould,1‘Deve lopmen t o f Renewable/AlternativeResou rcesof Electric Energy, ” unpublished, Southern California Edison Co.,Rosemead, CA, 1983.



with some large and small generators, thereserve margin must cover the possibility ofa forced outage of the large units. Moreover,the potential of this benefit is complicatedif the small units are dispersed source gener-ators as discussed in chapter 6.Improved financial flexibility.–The amountof capital tied up in construction is substan-tially reduced by employing short lead-timetechnologies. Security rating agencies areconcerned when a utility incurs a significant“ asset c onc entration risk, ” e.g., placing alarge amount of capital at risk on a singleproject which could ultimately account for50 to 60 percent or more of the utility’s ratebase but only 10 to 15 percent of its installedcapacity.Improved quality of earnings.–Less capi-tal tied up in construction translates into alower level of AFUDC reported in a utility’searnings. This, in the eyes of investors, raisesthe quaIity of earnings since AFUDC is con-sidered a “paper” earning.Technology and fuel diversity .–Diversity offuel types and technologies employed by autility reduces not only technological risk butalso institutional risks such as the impacts ofa coal strike or an oil supply disruption,

addition, many new technologies offer envi-ronmental benefits as well as adv~ntages of fuelflexibility, increased efficiency, the potential ofreduced fuel transportation costs and, in many

cases, the possibility of cogeneration. Moreover,if a small-scale technology is suitable for dispersedsiting near load centers, additional benefits arepossible:

q Reduced transmission requirements. -Sitingcloser to load centers reduces the need fortransmission; large plants generally must besited much further aw ay. The pote ntial leve lof transmission “credit” possible in small dis-persed generating units has been the subjectof much research. 49

q Improved quality of service.-–Outages can

generally be serviced more quickly with dis-d gsee , for example, S. Lee,et al., Systems COntrOl, Inc., /mPac t

of Transmission Req uireme nts ot Dispe rsed Stora ge and Genera -tion (Palo Alto, CA: Electric Power Research Institute), December1979, EM-1 192.

q

persed generation ava ilab le to be dispa tchedlocally.Improved area control.–lf decentralizedsources can be coordinated with energy con-trol ce nters (where pow er flow to load c entersis controlled), the result will be better regu-lation of area control error and hence im-proved efficiency and quality of power (seechapter 6).

While all of these potential benefits are in manycases sufficiently attractive to warrant interest onthe part of utilities, alternative technologies alsopose complications for utility planners in addi-tion to the risk of relying on new technology.These include:

q

q

q

Load dependence.—The uncertainty associ-ated with impact on the system load curveof dispersed generating sources is com-pounded by the fraction of this generationcoming from intermittent alternative energysources such as wind, solar, and low-headhydroelectric systems. Unlike conventionalsources or fossil-based dispersed sourceswhich are largely independent of load char-acteristics, alternative sources are often in-terdependent with load due to such factorsas wind speed, solar energy flux, tempera-tures, steam flow, etc.Nondispatchable generation and utilityoperations.—As mentioned earlier, nonutil-ity or customer-owned equipment (actuallyfor both new as well as conventional tech-nologies) operating under the provisionsestablished by PURPA are not generally in-cluded in a utility’s economic dispatch sys-tem. Most utilities have treated nondispatch-able generation as an expected modificationof the system load curve in the same manneras load management. As penetration of non-dispatchable sources grows, however, utili-ties will need to account for them more ex-plicitly in dispatching strategies.Nonutility generation and capacity plan-ning.—As mentioned earlier, nonutility gen-

eration has traditionally been treated as amodification to the system load curve. If sig-nificant penetration of such generation isconsidered a possibility, as might be the casein 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 af-fec ted . The a ttitudes of utilities tow ard non-utility generation varies markedly amongutiIities in terms of interconnection require-ments and conventions for establishing ofavoided cost rates. Interconnection require-ments such as insurance, control and safetyequipment, meters, and telecommunicationsequipment can all vary according to size ofgenerating plant, approved design specifica-tions or other factors (see chapter 6). Simi-larly, avoided cost rates vary according toprocedures for capacity and energy credits,and availability of “payment tracking mech-anisms” that permit nonutility generators toreceive higher revenues in early years of theproject, as is the practice at Southern Cali-fornia Edison. The ultimate contribution ofnonutility generation to the overall U.S.

power generating capacity depends on notonly the performance of the technology andadequate financial incentives, but also on theevolving attitudes of utilities, especially asthey apply to rates and interconnection withnonutility generation.Indeed, interconnec-tion requirements alone can increase nonu-tility generation cost by over $1,000/kW forsmall systems. so Some work is now beingdone to incorporate nondispatchable tech-nologies into long-term generation plan-n i ng. 51

q Rate inequities .—The possibiIity of rate in-

equities also presents a potential problem inthe case of encouragement of a large pene-tration of nonutility generation. Rate require-ments are estimated for various customerclasses, e.g., residential, commercial, heavyindustrial, etc., based on the total revenuerequirements of the utility and the forecasteddemand of each customer class (includingtime of day and cost of service considera-

~Oseeu .s. Congress, Office o f Technology Assessment, /ndus-tria/ and Cornrnercia/ Cogene ra t ion (Washington, DC:U.S. Gov-ernment Prlntlng Off i ce , February 1983), OTA-E- 192; and U.S. De-partment of Energy (DOE),Survey of Uti/ity Cogene ra [ ion

/nferconnect/on Pro/t@s a nd Co st–F/ na/ Report (Washington, DC:DOE, June 1980), DOE/RA/ 29349-01.5 1 A s d i s c u s s e d In M , G r a r n a r l i s , et a l,, “ The Introduct iono f Non-

dlspatchable Tec hno log ies as Dec ision Va riable s in Long -Term G en-eration Expansion Models, ”/nstitute of f /ect r icd/ and Electronic Engfneers (/ EEE) Transac tion s, vol. PAS-101, No. 8, August 1982,pp. 2658-2667.

q

tions). A situation could arise whereupon thedemand of a particular customer class is re-duced by the implementation of end-use de-vices or third-party generation pIants and,consequently, customer rates must be in-creased to meet f ixed revenue require-ments. 52 Potential rate inequities may result,particularly to those customers in an affectedrate class who do not use the demand-reduc-ing device.Research and development and regulatorytreatment.–As we will see in chapter 4,most new generation technologies, today,are not yet cost competitive with conven-tional alternatives. For promising new tech-nologies, part of the difference betweencurrent and mature costs represents theamortization of R&D expenditures. An often-used operational rule among many utility

commissions, however, is to permit plantsinto the rate base only if they can generatepower at less than full avoided cost.53 Theissue then becomes clear: to what extent willthe less than full avoided cost benchmark in-hibit the commercialization of new technol-ogies? If such a benchmark is relaxed, towhat degree should ratepayers share withthe stockholders the burden of higher perunit capital costs, greater risk of lower relia-bility, possibility of complete plant failure,and possibility of shorter plant life associatedwith new technologies? Some studies suggest

that relaxed treatment of the full-avoidedcost benchmark is a prerequisite to signifi-cant penetration of many new technologies(at least for demonstration and early com-mercial units) in utilities over the next twodecades . 54 This issue is discussed in more de-tail in chapter 10.

52Thls phenomenon occurredin 1973-74In San Franc isc o withlocal water utilities. Regional droughts motivated the utilities to sub-sidize advertising campaigns and various end-use devices for water

co nservation. The resulting d rop in de ma nd w aso f such magni-tude that the utilities were putin a position of having to fncreaserates to meet their revenue requirements.

“L. Papay, “Barriers to the Accelerated Deployment of Renew-able and Alternative Energy Resources, ” unpublished, SouthernCalifornia EdisonCo,, December 1982.

$~lbld



70 • New Electric Power Technologies: Problems and Prospects for the 1990s

Current Activities and Interest inAlternative Technology

Power Generation

The Edison Electric Institutesshas observed fourdegrees of current involvement (not mutually ex-

clusive) in alternative technology power gener-ation by U.S. utilities:q

q

Use of alternative technologies as a substan-tial contributor to future resource plans.–Some utilities which are historically highlydependent on premium fuels (and hencehave a very high avoided cost rate), have sig-nificant demand growth, and have severeenvironmental and regulatory constraints onusing conventional technologies have an-nounced significant plans for reliance onal ternat ive technologies . As ment ionedearlier in the discussion, only two such U.S.utilities, namely Southern California Edisonand Pacific Gas & Electric, have done so todate .Use of alternative technologies as a re-sponse to uncertain load growth.—Somemedium demand growth utilities, in re-sponse to environmental and regulatorypressures, have included alternative technol-

JJEd ison Ele~ric Institute, op. cit.,1984.

ogies as “an important but small” buffer infuture resource plans.Use of unregulated subsidiaries for equityparticipation in cogeneration.-Some finan-cially sound utilities—e,g., Houston Lighting& Power–in areas with cogeneration poten-

tial have been permitted by utility commis-sions to invest capital in cogeneration ven-tures with industry to avoid loss of load,revenue, and earnings. This strategy istermed “reactive diversification” as opposedto “proactive diversification” which is aimedat improving stockholder return on equity.Active research and development.–Manyutilities, are involved in long-term researchand development with alternative generat-ing technologies as a possible response tovarious contingencies discussed earlier thatcould limit the use of conventional generat-

ing technologies.So far, the penetration of new technologies has

been very small. A great deal has happened inthe last several years, however, particularly in co-generation. Most of this cogeneration is usingconventional technology, but some are new tech-nologies such as AFBC. In addition, wind, low-head hydroelectric, and biomass technologies arealso contributing. For the technologies consid-ered in this assessment we discuss the historicalrate of development in detail in chapter 9.

SUMMARY AND CONCLUSIONSThe 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 ex-to declining electricity demand growth; dramat- pand the scope of strategic options they are will-ically increasing fuel prices, construction costs, ing to consider over the next several decades toand capital costs and heightened public demand include such strategies as rehabilitation of exist-for better control of air and water pollution and ing plant, increased purchases from neighboringnuc lear saf ety. The ind ustry eme rged from th is utilities, increased conservation and load man-period of stress with significant uncertainties, agement efforts, diversification of investments toespecially about future demand growth, and nonutility lines of business and, finally, a rangefinanc ially wea kened. While utilities’ financ ial of new generating technologies. Most utilities arehealth appears to be improving markedly, they only beginning to consider such alternatives toare not returning to their pre-1970s business traditional large-scale, central-station, power-strategies. plants. In particular, conservation and load man-



Ch. 3—Electric Utilities in the 1990s: Planning for an Uncertain Future 7

agement are beginning to attract more attentionin utility resource plans; and many utilities haveplant life extension or rehabilitation projectsunderway. Similarly, in response to uncertain de-mand growth, mature smaller scale technologiesare under close scrutiny. For the most part,smaller scale new technologies are under con-sideration primarily as a possible response to fu-ture contingencies such as oil supply disruptionor imposition of stricter environmental controlson coal burning. There are a few exceptions,notably Southern California Edison and PacificGas & Electric in California. They have includedsubstantial commitments to new technologies intheir long-term resource plans.

To d ate , nonconventional technologies ac co untfor only a tiny fraction of the Nation’s overall elec-tric generating capacity, the new technologies’penetration of the market is likely to growthroughout the remainder of this decade andthroughout the 1990s.

Non utility involvement in new technologies isincreasing steadily under the provisions of PURPAand the rate of development of new generatingtechnologies over the next two decades may wellhinge not only on the performance of these innonutility applications but also on the evolvingrelationship between utilities, nonutility gener-ators of power, and regulatory agencies.



Chapter 4

New Technologies for Generatingand Storing Electric Power

Advanced Batteries . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Summary occurrent Activity . . . . . . . . . . . . . . . . . . . . . . . . . . . .

List of TablesTab le No.4-1. Developing TechnologiesConsidered in OTA’s Analysis . .4-2. Selec ted Alternat ive Generating and Storag e Tec hnologies:

Typical Sizes and Applications . . . . . . . . . . . . . . . . . . . . . . .

P’l<qt’ . . . . . . . . . . . . . . 7.5

. . . . . . . . . . . . . . . . . . . 764-3. Advantages and Disadvantages of Solar Thermal Electric Systems. . . . . . . . . . . . 884-4. Developing Technologies: Major Electric Plants Installed

or Under Construction by May 1, 1985 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .129





Chapter 4

New Technologies for Generatingand Storing Electric Power

INTRODUCTIONA number of new technologies for generating

and storing electricity are being developed asalternatives to large-scale, long lead-time conven-tional powerplants. Of increasing interest aretechnologies which are small scale and highly ef-ficient, which are capable of using alternativefuels, and/or which impose substantially lowerenvironmental impacts than conventional gen-erating options.

This c ha pt er foc uses on ne w te c hnolog ieswhich, while generally not fully mature today,could figure importantly in the electric-supply technologies insta//ed in the 7990s.Not exam-ined in detail are those technologies which al-ready are considered technically mature or thosewhich are very unlikely to achieve wide deploy-ment during that time. Only grid-connected ap-plicat ions are c onsidered. The c hap ter also d oesnot examine closely technologies which recentlyhave be en c overed in other OTA repo rts.1

The ne w te c hnolog ies c ove red in this repo rtare summarized in table 4-1. In table 4-2, thetechnologies are grouped according to size andapplication, along with their primary competitors.They range in size from units less than 1 MWeto units greater than 250 MWe. The technologiescan be divided between those in which the elec-trical power production is available upon utilitydemand (dispatchable) and those where it is not.In the table, dispatchable applications are furtherbroken down according to base, intermediate,and peak load applications. Among applicationswhere the utility cannot summon electrical poweron command are intermittent technologies (e.g.,wind turbines and direct solar equipment), when

1 These include nuclear power, convent io na I technologiesusedIn cogeneratlon, an d conventional equ Ipment which uses biomass;see p. IV of this report.

Table 4-1 .—Developing Technologies Considered inOTA’s Analysis a

Photovoltaics:Flat plate systems (tracking and nontracking)Concentrators

Solar thermal electric:Solar pondsCentral receiversParabolic troughsParabolic dishes

Wind turbinesGeothermal:

Dual flash

Binary (large and small)Atmospheric fluid ized-bed combustorsIntegrated gasification combined-cycleBatteries

Lead acidZinc chloride

Compressed-air energy storage (large and small)Phosphoric-acid fuel cells (large and small)

75




Table 4-2.—Selected Alternative Generating and Storage Technologies: Typical Sizes and Applications

Typical configurations in the 1990s

GENERATING TECHNOLOGIESSolar Technologies

Introduction

In seeking ways to directly exploit the Sun’senergy to produce electric power, two alterna-tives are being pursued. Solar thermal-electrictechnologies rely on the initial conversion of lightenergy to thermal energy; the heat typically isco nverted to me cha nica l energy and then to elec-tric power. Alternatively, photovoltaic cells maybe used to directly convert the light energy intoelectrical energy. Between the two technologies,many variations are being developed, each withits own combination of cost, performance, andrisk, and each with i ts own developmentalhurdles.

Most solar electric technologies promise note-

worthy advantages over conventional technol-ogies.2 These include:

1. Free, secure, and renewable energy source: These are especially important attributeswhen contrasted with price and availabil-ity uncertainties of oil and natural gas.

2. Widely available energy source: Figure 7-11 in chapter 7 illustrates the distributionof the solar resource in the United States.

~Note that some solar technologies mayuse a su pplernental fuelsuch as oil, gas, or biomass. In such instances, the hybrid systemwillno t have some o f the advantages and disadvantages listed; andthe system will possess some advantages and disadvantages no tlisted.






verts sunlight directly into direct current (DC)electricity by way of the photoelectric effect, Cellsare grouped into modules, which are encapsu-lated in a protective coating. Modules may beconnected to each other into panels, which thenare affixed to a support structure, forming an ar-

ray (see figures 4-1 and 4-2). The array may befixed or movable, and is oriented towards theSun. Any number of arrays may be installed toproduce electric power which, after conversionto alternating current (AC), may be fed into theelectric grid. I n a PV installation, all the compo-nents other than the modules themselves are col-lectively termed the balance-of-system.

At present, PV systems are being pursued inmany different forms. Each seeks some particu-lar combination of cost and performance for themodule and for the balance-of-system. In a con-

centrator moduIe, lenses are used to focus sun-Iight received at the module’s surface onto amuch smaller surface area of cells (see figure 4-2); all available concentrator systems follow theSun with two-axis tracking systems. A flat-platemodule is one in which the total area of the cells

used is close to the total area of sunlight hittingthe exposed surface of the module. Variousmechanisms such as mirrors can be used to di-vert light from adjacent spaces onto the exposedsurface of the modules. Flat-plate systems maybe fixed in position or may track the Sun with

either single or two-axis tracking systems.The p arallel developm ent o f these tw o typ es

of PV modules and systems reflects a basic tech-nological problem: it is difficult to produce PVcells which are both cheap and highly efficient.Cheap cells tend to be inefficient; and highly ef-ficient cells tend to be expensive. Some PV sys-tems which are being developed for deploymentin the 1990s are emphasizing cells which are rela-tively cheap and inefficient; such cells are usedin flat-plate modules. Others are using a smallernumber of high-cost, high-efficiency cells in con-

centrator systems.In either case, if PV systems are to compete

with other grid-connected generating technol-ogies in the 1990s, their cost and overall risks willhave 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 disagree-ment over which particuIar PV system is thestrongest contender for this market. Marketpenetration will depend on the current state ofthe particular variety of PV system; the potentialfor cost reductions and performance improve-ments; and on the reduction in risk perceptionamong prospective investors in grid-connectedinstalIations.

At present, two types of modules appear to bethe leading contenders. One is the flat-plate mod-

ule based on tandem cells made from amorphoussilicon; the other is the concentrator module,probably using crystalline silicon.

There are a numb er of reasons why the con-centrator module could be the photovoltaic tech-nology of choice in central station applications

in the near term. The crystalline silicon cell isrelatively well understood, as are the techniques forma king suc h c ells. The c ells have be en m anufa c -tured for many years, and information on cell per-formance after extended exposure to the ele-ments is rapidly accumulating. Concentratormodules may offer a favorable combination ofcost and performance in the Southwest, whereearly central station deployment probably will begreatest. And the prospec ts are go od that c ost a ndperformance improvements can be made duringthe balance of the century. Many of the improve-

ments do not appear to require basic technicaladvances but rather incremental improvementsand mass production.

Flat-plate modules using amorphous siliconmeanwhile 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 willoc cur. The c urrent tec hnology is too ineffic ient.Efficiencies must be improved, and the perform-ance of the improved modules must be estab-lished over time and under actual conditions. Thiscombination of technical improvements and theneed to establish a clear, long-term performancerecord will take a substantial period of time. Be-cause of this, amorphous-silicon flat-plates maynot offer a superior choice for central station ap-plications until the latter part of the 1990s or later.There is a small possibility, however, that rapidimprovement in the cost and performance ofamorphous modules is likely and that they willcompete successfully with concentrators duringmost of the 1990s.

Regardless of technology, the commercial pros-pects for PV systems will depend heavily on con-tinued technical development and the volume

of production. Factors influencing either techni-cal development or production levels thereforewill strongly affect cost and performance in the1990s.

The Typical Grid-Connected PhotovoltaicPlant in the 1990s.—ln the 1990s, central stationapplications probably will be favored over dis-persed applications. Indeed, by May 1985, ap-proximately 19 MWe of PV power in multimega-watt central station installations were connectedto the grid in the United States—this was mostof the grid-connected PV capacity in the coun-try. This cap ac ity was divide d roughly equa lly be-tween concentrator and flat-plate modules. By1995, as much as 4,730 MWe could be locatedin such installations nationwide.b Capacity prob-ably will be concentrated in California, Florida,Hawaii, Arizona, and New Mexico.7

In this analysis, it is assumed that the typicalgrid-connected photovoltaic system in the 1990sis a centralized photovoltaic system (see figure4-3). Unless otherwise stated, the numbers re-

bThis IS the range pro~’lded by Pieter Bos (Polydyne Inc.), as esti-mated in a submission at theO TA Workshop on SolarPhotovol-

talc Power (Washingto n, DC, June 12, 1984) and discussed by May-c o c k a n d Sherlekar (Paul D. M a y c o c k and Vic S. Sherleka r,Photo\ wltaic Tec hnolog y, Performance, Cost and Market Forecast to 1995. A Strate gic Tec hnolog y& 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, vegetationcontrol efforts, and periodic cleaning of themoduIes.

The lead -time req uired to d ep loy a PV plantis potentially quite short, perhaps 2 years—in-cluding planning, licensing, permitting, construc-tion, and other elements. Construction itselfshould be quick and simple. Licensing and per-mitt ing should proceed very rapidly becausemany of the environmental impacts are low rela-

tive to those associated with conventional tech-nologies. However, large PV plants will be newto most areas in the 1990s; and the land-extensivecharacter of the technology raises problemswhich could engender controversy, leading toregulatory delays.

System Cost a nd P e r f o r m a n c e . – O p e r a t i n gavailabilities of 90 to 100 percent are anticipatedfor the multimegawatt PV installat ion of the1990S.10 This will be affected primarily by thenumber of PCSS required and their quality. Mostoperating large PV systems today are charac-terized by operating availabilities below this—between 80 and 90 percent–usually as a resultof problems with the PCSS. I n order to reach theexpected range of operating availabilities, PCSSmust be developed which can operate reliably.

I (Ioperat ng a y a la bl Ity of Ind Ivld ua I arraysk~I I be be tween q 5and 100 percent, depe nding mostly on the performanc e o f trw ker~,if they a re used. Recent experwrwe with tra( kers su~ges[~ that theirope ra t l ng avai lahl I Itles shou Id not ta I Ibelow that ra nm .








has been found to be an effective cleaner, butoften the best areas for photovoltaics have littlerain. With flat-plate systems, dirt does not seemto be as much of a problem as with concentra-tors. The second problem is wind damage. Mostexisting photovoltaics and solar thermal plantshave suffered damage from wind blown sand,though methods to prevent this are being de-veloped.

Solar Thermal= Electric PowerplantsTechnology Descriptions. -Solar thermal-elec-

tric plants convert radiant energy from the Suninto thermal energy, a portion of which subse-quently is transformed into electrical energy.Among the systems, there are four which, withsome feasible combination of reduced costs andrisks and improved performance, could be de-

ployed within the 1990s in competition with

other technologies and without special and ex-clusive Government subsidies. They are centralreceivers, parabolic troughs, parabolic dishes,and solar ponds. Brief descriptions of these tech-nologies are provided below.

Centra/ Rece;ver.–A central receiver is charac-

terized by a fixed receiver mounted on a tower(see figure 4-6). Solar energy is reflected from alarge array of mirrors, known as heliostats, ontothe receiver. Each heliostat tracks the Sun on twoaxes. The receiver absorbs the reflected sunlight,and is heated to a high temperature. Within thereceiver is a medium (typically water, air, liquidmetal, or molten salt) which absorbs the re-ceiver’s thermal energy and transports it awayfrom the receiver, where it is used to drive a tur-bine 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 q 85

ce iver mounted a t the foc al point. The c onc en-trated heat may be utilized directly by a heat en-gine placed at the focal point (mounted-engineparabolic dish); or a fluid may be heated at thefocal point and transmitted for remote use (re-mote-engine parabolic dish). Each dish/receiverapparatus includes a two-axis tracking device,support structures, and other equipment (seefigures 4-7, 4-8, and 4-9).

Solar Troughs.–With a parabolic trough, theconcentrators are curved in only one dimension,forming long troughs. The trough tracks the Sunon one axis, causing the trough to shift from eastto west as the Sun moves across the sky. A heattransfer medium, usually an oil at high tempera-ture (typically 200 to 400° C), is enclosed in atube located at t he foc al line. The typ ica l insta l-lation consists of many troughs (see figure 4-1 O).

The oil-carrying tubes located at their focal linesare connected on eac h end to a network of larger

pipes. The oil is circulated through the tubesalong the focal lines, flows into the larger pipes,and is pumped to a central area where it can bestored in tanks or used immediately. In eithercase, it ultimately passes through a heat ex-changer where it transfers energy to a workingfluid such as water or steam which in turn isrouted to a turbine generator. At the Solar EnergyGenerating units in southern California, the onlylarge trough installations in the United States, theoil’s heat is supplemented with a natural gas-firedcombustion system to obtain adequate steamtemperatures to drive the turbine. After passingthrough the steam generator. The oil is used topreheat water destined for the steam generator;the oil may be returned to the trough field.

So/ ar Pond.–In an ordinary body of openwater, an important mechanism which influencesthe thermal characteristics of the reservoir is nat-ural convection. Warmer water tends to rise to



the surface; and if the water is warmer than theambient air, it tends to lose its heat to the atmos-phere. A solar pond (see figure 4-11) is designedto inhib it this na tural p roc ess. The c reat ion o fthree layers of water, with an extremely denselayer at the bottom and the least dense layer atthe top, interferes with the movement of warmer

bottom waters toward the surface. Salt is usedto increase the density of the bottom layer, form-ing a brine, to the point where its temperaturec an go as high a s 227° F. The heat in this bo t-tom layer can then be drawn off through a heatexchanger, where the brine transfers its heat toan organic working fluid which in turn can drivean engine to produce electric power.

General Overview. –Within most of the abovementioned technologies, many variations nowexist or could exist. The discussion here is con-fined to those variations which appear to affectprospects for solar thermal-electric systems in the1990s. The discussion is intended to be a briefsurvey rather than exhaustive examination of thetechnologies.

Each technology is characterized by a particu-lar set of advantages and disadvantages (see ta-ble 4-3) which together define its prospects thiscentury. All of the technologies share a principaldisadvantage in that costs and performance arecurrently unce rta in. The level of unc ertainty canonly be reduced sufficiently as commercial-sizedunits are deployed and operated. In some cases,research and development hurdles must still besolved before commitments are likely to be madeto early commercial units, Until this occurs, thechances for widespread commercial applicationfor any one technology during the 1990s are quitesmall, regardless of the technology’s ultimatepromise. At least one operating system is requiredto reduce cost and performance uncertainty toa level where it no longer is a primary impedi-ment to extensive investment; and perhaps sev-eral units—including early commercial units—would be necessary. The time and expense asso-ciated with these early demonstration and com-mercial units are critical elements in determin-ing the commercial prospects of the solar thermaltechnologies in the 1990s.





88 New Electric power Technologies: Problems and Prospects for the 1990s

Figure 4-il.—Solar Pond Powerplant Concept

Condenser1 4

Y

Generator

Pump

ry

1982).

Table 4-3.—Advantages and Disadvantages of Solar Thermal Electric Systems

Technology

Parabolic dishes Parabolic dishes CentralCharacteristic Solar ponds Solar troughs (mounted-engine) (remote engine) receiverYes (+ )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 5q (moderate advan/disadvan) o 1 0Total, categories 3-10:

+ (major advantages) 5 3 4 – (major disadvantages)q (moderate advan/disadvan)

3 4 40 1 0

Yes (+ )Yes (+ )

Yes (+ )low ( –)low (+)low (–)no (–)

yes (–)no (+)med (0)—

5

41

3 41

No (–)No (–)

Yes (+ )med (0)low (+)low (–)no (–)

yes (+)no (+)med (Ž)

5

42

422

SOURCE: Office of Technology Assessment




cial units quickly enough to sufficiently reduceuncertainty about cost and performance. Further-more, the expense of such early units is highenough that it is very unlikely that any entity orgroup of entities outside of government presentlywould invest in such units without special gov-ernment incentives. In short, the time and ex-pense associated just with reducing risks for thesetwo technologies strongly mitigate against theprovision of sizable amounts of electric powerby the technologies within the 1990s.It is likelythat only a sizable and immediate governmentintervention to encourage rapid deployment ofdemonstration units and subsequent units couldreduce uncertainty to the point where it no longeris a major impediment to commercial investmentin the 1990s.

Should such intervention occur and if the po-tential advantages of the solar ponds and central

receivers are realized, both technologies offerfavorable balances of advantages and disadvan-tages which could stimulate considerable privateinvestment in the 1990s. Between the two tech-nologies, the central receiver probably would bemost widely deployed. Solar ponds must be lo-cated in areas where land, water, and salt areplentiful. Such sites are far less common than thesites available to central receivers, which requireconsiderably less land, less water, and do not re-quire such large quantities of salt. Siting optionstherefore are greater with the central receiver.19

Furthermore, the central receiver is a more ma-ture technology. A10 MWe (net) pilot facility,Solar One, has operated successfully in southernCalifornia since 1982; and a small experimentalfacility, rated at 0.75 MWe (gross) has been oper-ated in New Mexico .*” Small central receiversalso have been built and operated overseas, butno solar pond has ever produced electric powerin the United States. However, a 5 MWe unit isin operation in Israel and several ponds have——

lgFOr a ~lscussion Of t h e so[a r pond’s prospects in California, andof the II m Itat Ions regard I ng sites, see Marshal F. Merriam, E/ectri-cl ty Generation from Ncm-Corrvectlve Solar Ponds in Ca/lt’ornia(Ber-keley, CA: Universitywlde Energy Research Group, December1983), UER-109,

20john T. Holmes, “The Solar Molten Salt Electric Experiment, ”Ad van ce d Energy System s–Their Role in Our Future: Proce ed ings of th e 19th /ntersociety Energy Co nversion Engineenng Conference,Aug. 19-24, 1984, (San Francisco, CA: American Nuclear Society,1984), Paper 849521,

be en built and ope rated in the United Sta tes andelsewhere for applications other than the produc-tion of electricity. The solar pondconcept h o w -ever is considered to be well established and thesuccessful commercial deployment of the tech-nology is not expected to require any major tech-nical breakthroughs. *1

Parabolic Troughs and Dishes.– Unlike theponds and central receivers, parabolic dishes andparabolic troughs already have been deployedin commercial-scale units. Indeed, commercialinstallations financed by private investors assistedby the Renewable Energy Tax Credits now areoperating. Further demonstration and early com-mercial units are being planned over the next 5years, though the extent to which the plans arerealized depends heavily on Government tax pol-icies or funding, As current units continue tooperate, and as new units are added, the level

of uncertainty and risk associated with the tech-nologies will continue to drop.

At present, the parabolic trough is the mostmature of the solar thermal electric technologies,with commercial units operating, under construc-tion, and planned. Nearly 14 MWe (net) of pri-vately financed capacity already is operating insouthern California at the Solar Electric Gener-ating System-1 (S EGS-I); an additional 30 MWe(net), the Solar Electric Generating System-n(SEGS-11), now is being built. Additional capac-ity— 150 MWe or more—may be added by early

1989. if the energy tax credits are extended insome form. Whatever the case, by 1990 morecommercial experience will have been loggedwith this technology than any other solar thermal-electric alternative. The resultant low level of riskwill constitute an important advantage for thistechnology. Other important advantages will bethe technology’s inherent storage capacity andthe relatively wide variety of markets to whichit could be applied—including industrial process-heat applications.

21 See: I ) N4assach usetts I nstltute of Technology, A state-o~-fhe-

Art Stud y of N o nc o n \ w c t i\ e So/ ar Ponds fo r Powe r Generation (PaloAlto, CA: Electric Power Research Institute, January 198S), EPRI AP-3842. 2) Edward I.H. Lln, A Retlew ot’the Sa/t Gradient So L~r Pond Tec hnology, op. cit., 1982,



90 Ž New Electric Power Technologies: Problems and Prospects for the 1990s

But the troughs are saddled with several seri-ous disadvantages which to some extent will con-strain dep loyment. The tec hnology’ s low e ffi-ciency is its most serious disadvantage. Anotheris the need by the SEGS units for a supplemen-tary fuel such as oil or gas, and for considerablevolumes of water. Finally, the system of conduitsthrough which the heat-absorbing oil flows maydevelop problems or the oil itself may degradeat an excessive rate; these potential problemshave not yet materialized at the SEGS-I installa-tion, but further operating experience is requiredbefore long-term performance can be proven.

Two types of parabolic dishes may be de-ployed in the 1990s: the mounted-engine para-bolic dish and the remote-engine parabolic dish.Each offers many design options. The p rima ry a d -vantages of the mounted-engine units are theirhigh efficiencies, low water consumption, and

ab ility to op erate without supp lementa l fuel. Thesmall size of the basic electricity-producing mod-ule also carries with it advantages. The systemmay be installed in many sizes, and multi moduleinstallations may produce electric power long be-fore the full installation is completed; individualmoduIes or groups of moduIes may begin oper-ating while others are being installed. Togetherthese advantages provide the technology withconsiderable siting flexibility and potentially veryshort lead-times.

The large st disad vantag e of the mo unted -engineunit is the relatively high level of uncertaintyabout its performance, and the possibility that theengines may require an excessive amount ofmaintenance. Only three commercial-scale dem-onstration units—at about 25 kWe (net) each—had been deployed by May 1985, and few arescheduled to be deployed by 199o; no commer-cial installation yet exists, or is under construc-tion. Other disadvantages include the lack of stor-age capacity and the inability to readily adapt thetechnology to cogeneration or nonelectric appli-cations.

The remote-engine dishes, like the troughs, enjoy the advantage of being used at present in acommercial installation. A 3.6 MWe system, builtby LaJet, Inc., now is operating in southern Cali-fornia. Also, like the troughs, the remote-enginetechnology may use as few as one or two engines;

engine-related O&M costs therefore could bemuch lower than those of the mounted-enginepa rab olic dishes. The remote-eng ine tec hnologyin addition may be easily used for nonelectric ap-plications. The LaJet design at present does notrequire a supplemental fuel.

But the remote engine technology is inefficient;much heat is lost as the heat transfer fluid ispumped from the collector field to the turbines.Also, the system has little storage capacity; elec-tricity production therefore cannot be deferredfor very long. And unlike the mounted-engineunits, the remote-engine technology consumessizable volumes of water.

Both dishes and troughs suffer from the sameserious problem—they lack the cost and perform-ance certainty which can only be gained throughmore commercial-size operations. This mitigatesagainst private sector investment which is not insome manner accompanied by government sup-port. At the current pace, it is uncertain whetherthe situation will change over the next 5 to 10years.

Generally, capital costs will have to be reducedand performance improved if the technologiesare to b e dep loyed. To som e extent this c an b efostered by research oriented towards incre-mental improvements of the commercial-scalesystems now operating. The most useful researchwould concentrate on low-cost, durable, andhighly reflective reflector materials and inexpen-sive, long-lasting receivers and engines. But if thetechnologies are to be extensively deployed inthe 199os, the greatest overall need is to reduceuncertainty and thereby increase demand to thepoint where economies of scale can drive costsdown.

By virtue of the fact that commercial-scale sys-tems now are operating for troughs and dishes,the level of cost and performance uncertaintyamong the troughs and dishes will be consider-ably lower than the uncertainty associated withthe central receiver and ponds in the 1990s. Be-tween troughs and dishes, uncertainty will belowest for troughs, highest for the mounted-engine dishes, and somewhere in between forremote-engine dish systems.






Wind Turbines

Introduction

A wind turbine converts wind into useful me-chanical or electrical energy. Wind turbines maybe classified according to the amount of electri-city they generate under specified wind condi-tions. A small turbine generates up to 200 kWe,an intermediate-sized turbine can deliver from100 to 1,000 kWe, and a large system may pro-duce more than 1 MWe.

Since the early 197os, the development of windtechnologies for electric power production hasfollowed two relat ively dist inct paths–one di-rected towards small turbines and the othertowards the large machines. As the efforts relat-ing to the large turbines bogged down with tech-nical and economic problems, the small turbines

—aided by State and Federal tax incentives—

progressed very rapidly. In the early 1980s, windturbines were extensively deployed, mostly inCalifornia, where 8,469 turbines were operatingby the end of 1984. The to tal c ap ac ity of theseunits was approximately 550 MWe. Almost allwere erected at windy locations, in clusters called“wind farms. ”By the end of 1984, many thou-sands of wind machines, with a total installed ca-pacity of over 650 MWe, were producing elec-tric power in the United States, and almost allwere small turbines (see figure 4-I 2).

As operating experience accumulated with the

small machines, both manufacturers and inves-tors began to gravitate towards intermediate-sizedmachines. By the end of 1984, intermediate-sizedmachines were being deployed in small numbers.It is widely believed that if large numbers of windturbines are to be manufactured and deployedin the 1990s, in free competi t ion with othergenerating technologies, intermediate-sized ma-chines probably will be favored over both smalland large machines. Only the intermediate-sizedmachines promise sufficiently cheap power with-out imposing unacceptable risks (figure 4-13 il-lustrates a intermediate-sized vertical-axis wind

turbine).While it appears that the total installed capac-

ity of wind turbines in the United States may ex-ceed 1,000 MWe by 1985, the rate of subsequent

Figure 4-12.—Maintenance Crews Performinga Routine Inspection of a Small Wind Turbine

SOURCE: U.S. Windpower, Ed Linton, Photographer

deployment is a matter of speculation. Given theshort time within which a wind farm can be de-ployed and operated–from 1 to 2 years, exclud-ing wind data gathering—growth u rider favora-ble circumstances could be extremely rapid. itis possible that the market potential for wind tur-bines could be as high as 21,000 MWe for the1990-2000 period.24

The areas most favored for wind farms are thosewith good wind resources, heavy reliance on oilor gas, and with an expected need for additionalge nerating ca pa city. They are loca ted mostly inCalifornia, the Northeast, Texas, and Oklahoma.There are, however, less extensive but neverthe-less promising opportunities elsewhere in thecountry, especially in parts of the Northwest,Michigan, and Kansas.25 Most–though not al l–

Zqscience Appl ica t ionsInternational Corp.,Ear/ y Market Potef?-tial fo r Utility Applications of Wind Turbines, Preliminary Dratl(PaloAlto,CA: Electric Power Research Institute, December 1984), EPRIResearch Project 1976-1.

ZSlb ld ,



Ch. 4—New Technologies fo r Generating and Storing Eleclric Power q 93

Figure 4-13. —A 500 kW Vertical”Axis Wind Turbine

SOURCE Southern California Edison Co.

turbines probably will continue to be installed inrelatively large wind farms rather than individu-ally or in small clusters. Figure 7-10 in chapter7 indicates the distribution of the wind resourceand the areas of the United States where winddevelopment is most favored.

A Typical Wind Farm in the 1990s

The reference wind farm used in this analysisis summarized in appendix A, table A-4. A typi-cal wind farm in the 1990s may consist of up toseveral hundred, 200 to 600 kWe wind turbines;the reference wind farm consists of 50 turbines

with ratings of 400 kWe each. Installations couldvary widely in the number of turbines deployedor in their exact ratings. But based on current projections, the important cost and performancecharacteristics would be common to the average

faci l i ty considered by investors dur ing thatdecade .

In addition to the turbines themselves, relatedequipment will be necessary at the site, includ-ing power conditioning equipment, system pro-tection devices, security fencing, metering devicesfor measuring turbine output, wind measuringequipment for monitoring site conditions andequipment performance, control buildings, anda fabrication yard where equipment is stored andassembled .26

The turbines of the referenc e w ind fa rm w ouldbe distributed over an area of anywhere from 300to 2,OOO acres, depending on the topography,prevailing wind direction, the shape and orien-tation of the property on which the farm is lo-cated, and the size of turbines being used. Theturbines are spaced to avoid excessive interfer-ence with each other. Because installation andmaintenance of the turbines requires vehicularac ce ss, at least one road lead s to a wind farm a ndto each individual wind turbine (see figure 4-14)unless topography, surface characteristics, andregulations allow access without roads. Since theperformance of the turbines and the cost of theirpower depends directly on wind exposure, allmajor obstructions such as trees would be re-m o v e d .27

It is evident that the major environmental im-pacts of wind farms will result from their initialconstruction as well as from their high visibility,

their extensive road networks, and from the activ-ities of maintenance crews on the roads andaround the turbines.28 Among the other impacts,the severity of which may be assessed less read-ily but which nevertheless are considered poten-tially serious, are those associated with the noisecreated by turbine operation.

Concern over environmental impacts couldseriously delay the deployment of wind turbines.

zbsanl sa~l~r, @ al,, t~fl~~} Lanci O \ ~ m e r\ ~ u l d f ? [ % k m , O R: ~ ~ K -

gon Department o f Energy, 1984), p. 17,ZTt shou Id be noted that manyp rl m e MI nd sites, b el ng expoied

to frequent h Igh veloci ty wind s, are In hospitable en~)ronrnents for:rees and therefore treq uently are devoid of large, upright treesw h Ich C O UId be c on fdered serious obstructions.

“’’Wind Farms, Timber Logging May Have Similar En\ i ronmentalImpacts, H a r\ a r d ’s Turner Says, ” So/,?r / n t e / / i gence Report, Not .26, 1984, p . 375,



94 q 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





96 New Electric Power Technologies: Problems and Prospects for the 1990s

model structural dynamics; to better predict noiseproblems; to accurately model wind farm costand performance; and to develop, test, andcharac terize ma terials and com po nents. The de-velopment of cheap, reliable, and accurate windmeasurement instruments as well as better un-

derstanding and prediction of the wind’s char-ac teristics also are need ed. Deta iled and ac curateassessments of the wind resource nationwide arenecessary too.35

Geothermal Power

moderate temperature range (1 50 to 250o F).37

Geothermal development has in the past focusedon the high-quality, vapor-dominated reservoirs,which are confined to limited areas of the UnitedStates,

The equipm ent required to e xploit these high-quality resources is commercially available, andno major changes in the basic characteristic ofthe technology is likely during this century. Thereare available improved technologies, however,which not only could more economically exploitthe high-quality resource, but also may economi-cally tap the much more plentiful resources oflesser quality. Among these are single-flash, dual-flash, binary, and total flow systems.

The single-flash technology has been commer-cially deployed in the United States. Because thisanalysis focuses on technologies which are not

already technologically mature, the single-flashtec hnolog y will not be examined here. The to talflow systems also will not be discussed, since theyeither require considerable further technical de-velopment, or will be applied only to a smallnumber of high-quality sites i n the United States.The total flow systems therefore are unlikely toconstitute more than a small fraction of geother-mal capacity additions in the 1990s. The dual-flash and binary systems will constitute the mostimportant new technologies applied to the liquid-dominated geothermal resource in the 1990s,and, therefore, are the subject of this analysis.

Geothermal Power Technology

Before the resource is exploited to producedelectric power, it must be located and assessed.This itself is a time-consuming, expensive proc-ess involving its own particu tar set of technologiesand problems. Ultimately, resource assessmentrequires building roads, transporting dril l ingequipment to the site, constructing the rigs anddrilling. Once the resource has been satisfactorilymeasured, the thermal energy next must bebrought to the surfac e w here it ca n be used . This

too involves particular technologies and difficul-~7M. Nathenson, “High-Temperature Geothermal Resources in

Hydrothermal Convection SystemsIn the United Sta tes, ”Proceed-ings otthe Se~enth Annu,il Geotherm,j l Conference and workshop,Altas Corp. (cd. )(Palo Alto, CA:Electrlc Power Research Institute,1983), EPRI AP-3271 , pp. 7-1 to 7-2.




ties. An especially important technological hur-dle which remains to be satisfactorily overcomeis the development of cheap, reliable "down-hole” pumps capable of moving the brine fromthe underground reservoir, and subsequentlyreinfecting it. While the brine is at the surface,a portion of its thermal energy is drawn off andused to produce electric power.

Dual-Flash Systems.–Figure 4-15 illustrates thetypical dual-flash unit. When liquid-dominated,high temperature brine–300 to several thousandpounds per square inch (psia) and 410 to 6000 F

—reaches the surface, a portion of the brine“flashes” into steam. First, a high pressure flash-tank processes the geothermal brine into satu-rated stea m a nd spe nt b rine, The stea m entersone inlet of a dual-inlet turbine, while the un-flashed brine goes on to a second, lower pres-

sure flash-tank. The second-stage flash-tankproduces further steam which is routed to theother inlets of the turbine. The remaining un-flashed brine then is reinfected underground.

After exiting the turbines, the steam passesthrough a condenser, where it transfers its heatto a strea m o f c ooling w ate r. The c ooling w ateris then routed to a cooling apparatus. Current de-signs use “wet cooling” devices in which the hotwater is sprayed into the air and discharges itshea t mo stly throug h eva po ration, The rema iningwater is recirculated to the condenser to repeatthe cycle, along with “make-up” water requiredto compensate for evaporative losses. The con-densed steam from the turbine is reinfected intothe geothermal reservoir to help maintain reser-voir pressure.

The make-up w ater req uirements ma y be ex-tremely large. The 50 MWe reference plant usedin this analysis would require about 3 million gal-lons of make-up water daily, roughly six times theamount of water required by an atmosphericfluid ized-bed combustor of comparable net gen-

erating c ap ac ity. The wa ter req uirem ents couldbe reduced with “dry-cooling” systems; but theseare very expensive and reduce the plant’s over-all efficiency.

Figure 4-15.—Schematic of Dual-Flash Geothermal Powerplant

Turbine-generator

First stage

I

o2flash vessel

(high pressure)

Concentrated

1 I

07




Alternatively, the water requirement could begreatly reduced by meeting it in part with the con-densed steam from the condenser (instead of re-infecting it into the reservoir). This can only bedone, however, to the degree allowed by con-trac tua l agreem ents and regulations. The field de -veloper may require that all or part of the con-densed steam be reinfected into the geothermalreservoir to maintain the quality of the resource.Or regulators may require some degree of rein-fection in order to reduce subsidence problems.

The basic turbine, condenser, and coolingtower subsystem are similar to traditional steampowerplant designs, although there are significantdifferences. An important factor in the use of flashtechnology is the existence of noncondensablegases and/or entrained solids in the brine. Thesecontaminants can cause scaling, corrosion, anderosion within the flash equipment, surface pip-

ing, and reinfection well casing. Development ofhighly saline resources has been slowed by theseproblems. Considerable research has been con-ducted to develop and demonstrate reliableremoval technologies for these resources.

Although, operational dual-flash units abroadtotal 396 MW,38 there is little commercial experi-ence with these systems in the United States.None is now operating, and only one 47 MWe(net) dual-flash unit is under construction (see fig-ure 4-1 6). Nevertl~eless, the dual-flash system willbe used increasingly to exploit moderate to hightemperature hydrothermal resources because itis more efficient than the single-flash system .39

Appendix A, table A-5 contains cost and per-formance estimates for dual-flash units in the1990s. By the reference year 1995, dual-flash geo-thermal units will most likely range in size from40 to 50 MWe. The expense of smaller units

‘8R. Dipippo, “Worldwide Geothermal Power Development:1984 Overview a nd Upda te,”Altas Corp. (cd.), Proceedings of theEighth Annual Ge otherma l 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 O TA staff, Oct. 4, 1984) predictsthat m ost of the p lanned flash plants at the Salton Sea a nd Brawleyresources will use dual-flash technology.





Figure 4-17.–Simplified Process Flow Diagram of Binary Cycle Technology

I

surface condensers (instead of direct contact con-densers).

The major ad vantag es of b inary cyc les relateto efficiency, modularity, and environmental con-siderations. First, working fluids in binary cyclescan have thermodynamic characteristics superiorto steam, resulting in a more efficient cycle over

the sam e tem pe rature differenc e. QB Sec ond , bi-nary cycles operate efficiently at a wide range ofplant sizes. Especially attractive are small plantswhich, in addition to encouraging short lead-times, have many other important advantages aswell. Third, since the brine is kept under pres-sure and reinfected after leaving the heat ex-changer, air pollution, e.g., hydrogen sulfide,from binary plants can be t ightly controlled.There a re also several other cost a nd efficienc yadvantages of binary technology over the clual-flash systems. Nevertheless, the dual-loop designof binary cycles is more complex and costly thana flash design.

~E p B[air, et al,, Geothermal Energy. Investment Decisions and Comrnercl~/ Development (New York: John Wiley & Sons, 1982).

Binary cycle technology is in developmentalstages with few large operational generating units.By the end of 1985, one large 45 MWe (net) bi-nary plant will have been installed near Heber,California (see figure4-1 8); in addition, small bi-nary plants, with a total capacity of about 30MWe, will be operating.49 This will account formost of the binary capacity installed worldwide.Development is expected to proceed, and exten-sive commercial deployment is feasible in the1990s.

The expec ted c ost and performa nce of binarygeothermal plants in the 1990s are summarizedin appendix A, table A-5. Data is provided for tworeference plants, a large plant of about 50 MWe(net) a nd a sma ll plant of a bo ut 7 MWe (net). Thelarge plant could require up to 20 acres of landfor the powerplant and for the maze of pipingrequired for both the brine and the working fluid.The small unit might occupy 3 acres or Iess.so Aswith the the dual-flash technology, very large

‘9 Ronald DiPippo, “Worldwide Geothermal Power Development:1984 Overview and Update, ” op. cit., 1984.

~Opersonal com munica tion between H. Ram(Ormat , Inc. ) andOTA staff, Oct. 6, 1984.



Ch. 4—New Technologies for Generating and Storing E/ectric Power q 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 thedual-flash units. The large plant would requireover 4 million gallons each day. The smaller plantwould need about 0.6 million gallons per day.

Small plants of about 5 to 10 MWe (net) canbe erected and operating on a site in only 100days. But prior licensing, permitting, and otherpreconstruction activities could extend the lead-time to 1 year.5’ Construction of larger binaryunits shouId take only 1 ½ to 2 years.52 But heretoo, overall lead-times will be longer because ofpreconstruction activities, including licensing and

“Wood & Associates, a geothermal energy developer, has hadpermitting problems at the county, State, and Federallevel at Itssite near Mammoth Lakes, CA .

‘zSan Diego G a s & Ele[ trlc also had problems getting theirlargebinary plant through the permitting process, Its problems, howeier,were encountered during th e CaliforniaPubl K Uti Iities Comml+slon’s plant dpp rok al process.

permitting. About 5 years total might be requiredfor the first plant at a resource, and 3 years mightbe necessary for subsequent additions. With bothsmall and large plants, problems about water re-quirements and environmental impacts couldseriously extend the licensing and permittingprocess.

Binary cycle plants are designed to operatecontinually in base load operation. Availabilityis expected to be between 85 and 90 percent,and capacity factors are likely to be in the 75 to80 percent range. Binary pIants should last at least30 years.

The net brine effectiveness of binary cycleplants ma y vary betwe en 7 and 12 Wh/lb of stea mat a 4000 F resource. Advanced binary technol-ogy in the larger sizes should increase present ef-fectiveness values at Heber from 9.5 to 12 Wh/




q

q

q

q

q

q

responsiveness to changes in desired output,short lead-times,easily recovered waste heat,fuel flexibility,off-site manufacturing, andability to operate unattended.

Most of the commercial demonstration plantscrucial to the future of the fuel cell willnot b e -gin operations until the late 1980s, though by May1985, a 4.5 MWe demonstration plant was oper-ating successfully in Japan and thirty-eight 40-kWe demonstration units were operating in theUnited States.ssShould the performance of thedemonstration units be very good, limited quan-tities of commercial fuel cells may be producedat the earliest at the end of this decade or thebeginning of the next.5G 57

The level of dep loyment d ep end s hea vily on

the success of the demonstration units; the periodof time deemed necessary to generate investorconfidence; and the willingness of the vendorsto share the risk and cost of the early units, Theperceptions and decisions of investors, vendorsand buyers cannot be accurately and confidentlypredicted, but current evidence suggests that theearly 1990s may see the beginnings of fuel-cellmass production and the first commercial appli-cations. As much as 1,200 MWe of fuel cell pow-erplant capacity may be operating by 1995.

The low production levels will drive installedcapital costs down somewhat, but they will re-main far above possible costs in a mature mar-ket. High-volume mass production is unlikely tooccur until a sizable market is anticipated—in themid-l990s at the earliest. Such a market may de-velop as investors observe the continued opera-tion of the demonstration units and the initialoperation of the early commercial installations.

Most important to the prospective investors willbe operating and maintenance costs, economic

ssjw staniunas, et al,, United Technologies Corp.,Eo//ow’-On40-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/ysjsof 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 re-pOrt OTA US-84-1 1.

SzBattelle, Columbus Division,Fina/ Repor t on Alternative Gen- eration Tec hnologies (Columbus, OH:Battelle, 1983), VOIS. I and11, pp. 13-11.



Ch. 4—New Technologies for Generating and Storing E/ectric Power q 103

life, and reliability. In particular, investors arelikely to be sensitive to the rate at which fuel cellperformance degrades over time under variousoperating conditions as well as the cost and dif-ficulty of replacing cells when their performancebe c ome s unac c ep tab le. There is unce rtaintyamong investors over these two points, both ofwhich are crucial to the fuel cell’s uItimate com-mercial prospects. ShouId problems be encoun-tered in either area in early commercial proto-types, commercial deployment will be delayed.If powerplant operation is favorable, subsequentmarket growth in the latter half of theI990Scouldbe very rapid.

Basic Description

The typical fuel cell powerplant will consist ofthree highly integrated major components: thefuel processor, the fuel cell power section, andthe power conditioner. The fuel processor ex-tracts hydrogen from the fuel which can be anyhydrogen-bearing fuel, though most installationsin the 1990s are expected to employ natural gas.

The hydrogen is then fed into the fuel-cellpower section, the heart of which are “stacks”of ind ividual fuel ce lls. The o perat ion of a singlefuel cell is schematically illustrated in figure 4-19, The cells are joined in series (the stacks),which, in turn, are combined to form a power-plant. There are several types of fuel cells beingdeve lope d. These a re c ateg orized ac c ording to

the type of electrolyte-the medium in which theelec troche mica l rea c tion oc c urs—they use. Thefirst-generation fuel cells use phosphoric-acid asthe electrolyte. These cells are the most devel-oped and are likely to account for most of thefuel cells deployed in the 199os.

Other less mature, fuel cell designs which em-ploy alternative electrolytes promise superior per-formance; molten carbonate cells are the closestto commercial application, but are not expectedto be commercially deployed until the late 1990sat the earliest. They therefore are not likely to ac-

count for an important share of fuel cell power-plants installed in the 1990s. M w

S8Peter H u nt, AflJ/YSIS Ot Equipment Manufac turers and Vendors In the Elec trlc Power Industry for the 1990s as Related to Fuel Cells,OP. C i t . , 1 9 8 4 .

5gu ,s, Congress, office of Technology Assessment Workshop onFuel Cells, Washington, DC, June 5, 1984.

The elec trical po wer whic h flows from the fue lcell stacks is direct current (DC). With some volt-age regulation, this DC power can be used if theload is capable of operating with direct current.Otherwise, a power conditioner is required totransform the direct current into alternating cur-rent. This allows it to be fed into the elec tric algrid and to be used by alternating-current elec-trical motors.

The c ompo nents of the fuel ce ll plant are tightlyintegrated to reduce energy losses through theproper management of fuel, water, and heat (seefigure 4-20). Various parts of the plant benefitfrom the byproducts of other parts of the instal-lation. Further efficiency gains result when by-product heat from different parts of the plant aretapped for external use. The fullest exploitationof the fuel cell’s heat may yield total energy effi-ciencies of up to 85 percent for the entire plant.The hea t c an be used for dome stic hot wa ter, forspace heating, or to provide low-level processheat for industrial uses.

Typical Fuel Cell Powerplantsfor the 1990s

The expec ted c ost and p erformanc e of typicalfuel-cell powerplants for the reference year 1995are summarized in appendix A, table A-7. Be-cause no complete powerplants identical to thosewhich might be deployed at that time exist today,these values remain estimates.

The units deployed in the 1990s probably willbe built around two sizes of fuel cell stacks. Thelarger stacks are likely to be capable of generat-ing approximately 250 to 700 kWe (gross, DC)each and the smaller stacks about 200 to 250kWe (gross, DC) each. The plants built aroundthe small stacks will be installed mostly in largemultifamily dwellings, commercial buildings, andin light industries; most will probably be used tocog enerate bo th elec tric ity and useful hea t. Thetypical system would consist of at least two com-plete 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 likelywill be deployed primarily by electric utilities, andby industries which would use them in cogener-ation applications. Installation capacities probably




Figure 4-19.—Schematic Representation of How a Fuel Cell Works

1. Hydrogen gas flows over negativeelectrode (anode).

111

Electrons

11

Ieotrone,and o

will range from several megawatts on up. Thereference installation used in this analysis is 11MWe (net) . Many of the major componentswouId be fabricated in factories and shipped tothe site on pallets.

The lead-time of a small fuel cell powerplantsshould be about 2 years. These units are relativelysmall, unobtrusive, and quickly and easily erected.Modules subsequently added at the same sitecould require as little as a few months. Regula-tory delays are unlikely because of relatively mi-nor siting and environmental considerations.

Installations utilizing the larger stacks, however,may encounter more serious regulatory prob-lems, Unlike the approximately 480 to 600 square

feet required by an installation of two, 200 kWeunits, an 11 MWe installation would occupyabout 0.5 to 1.2 acres of land (see figure 4-22).Because the plants frequently may be located inthe midst of populated areas, the opportunity forregulatory conflicts with these larger plants is con-siderably greater. Partly offsetting these factors,though, are the environmental advantages asso-ciated with fuel cell powerplants. Hence, a lead-time of 3 to 5 years is anticipated with the larger

units, considerably longer than the small plant’slead-time, but also much shorter than that of mostconventional powerplants. As with the smallerfuel cell installations, capacity subsequently ad-ded to an already existing fuel cell plant shouldrequire considerably shorter lead-times.



L

Mechanical systems

Water

— — — — — — -

Watertreatment

1

Powerplantcontroller




Figure 40-21.— Design for a 200 kWe Fuel Cell ModuleWhile basically similar to units which might be deployed In the 1990s, this design differs in several important details,

The ope rating ava ilability of large fuel ce ll po w-erplants may range between 80 and 90 percent.Availability is heavily dependent on the qualityof design—its simplicity, the extent to which ithas redundant components, the number of parts,and their reliability—and on the availability ofspare parts and repair people when they areneeded.

The fuel cell c an b e ap plied to a ny duty cyc le.The fuel cell has exce llent load fo llowing cap a-bilities and high efficiency over a wide variety ofoperating levels.

The fuel cell powerplant’s lifetime is assumedto be approximately 20 to 30 years with periodicoverhaul of the fuel cell stacks and other com-ponents. over time, the powerplant’s efficiencydrops. The timing of overhauls will vary; sched-u Ies will be a function of the performance reduc-

tion over time and of other factors such as thecost of fuel .60 I n some cases the stacks must peri-odically be removed and replaced with newones. The o ld unit then is shippe d ba c k to a ma n-ufacturing plant where its catalyst (in the fuelprocessing section) and perhaps other compo-nents are removed, processed, and recycled.While the overhaul schedule and costs are un-certain, it is assumed here that all stacks arereplaced after the equivalent of 40,000 hours ofoperation at full capacity.

60J.R, Lanc e, et al.,WestinghouseElectric C orp., “Econom ics andPerformance of Utility Fuel Cell Power Plants, ”Acf~anced E n e r g y

Systems– The/ r Role In Our Future: Proceedings of the 19th /rrter-soclety Energy Conversion Engineering Conference, August 19-24,/984 (San Francisco, CA: American Nuclear Society, 1984), paper849133.



Ch. 4—New Technologies for Generating and Storing Electric Power Ž 107

co

Figure 4-22.—Typical Arrangement of 11 MWe Fuel Cell Powerplant

Auxiliarypower system \

Powerndi t ioner \ 1

Liquidfuel system\

Naturalgas system

supply

—

/-.

Efficienciesbl for large fuel cell plants are ex-pec ted to b e b etween 40 and 44 percent. Smallplants may have efficiencies of approximately 36to 40 percent. The estimated efficiencies are thosewhich might characterize a plant over its lifetime;efficiencies of new stacks could be higher whilethose of older stacks might be below that level.

The installed capital costs of fuel cell powerplants are expected to range from $700 to $3,000/ kWe for large units to $950 to $3,000/kWe forsmall plants; expected values for 1995 are $1 ,430/ kWe and $2,240/kWe respectively. The low num-bers can be expected where units are commer-cially produced in large numbers; the high num-bers are representative of prototype units and

include nonrecurring costs. By far the largest ex-pense is the fuel-cell power section itself; it is ex-pected to account for about 40 percent of the

‘]’ Based on higher heatln~-~ alue

costs of a mature 11 MWe plant .62 The largestdecrease in capital costs over the next decadewill come from increases in the levels of fuel-cell

production. However, technical improvementsin the fuel-cell plant itself may substantially re-duce costs as well. Already, over the past sev-eral years, design changes have reduced costs byan appreciable amount.

Operating and maintenance costs may rangebetw ee n 4.3 and 13.9 mills/ kWh. The bigg est e le-ment in O&M costs is the cost of periodicallyreplacing cells stacks. For specific applications,the actual O&M costs will depend on the over-haul period for the cell stacks and the materialand 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:UnitedTechnologies Power Systems, Apr. 27, 1981 ), prepared for Tennes-see Valley Authority, contract No. TV-52900A,FCR-2948.




Fuel costs are expected to be approximately27 to 33 mills/kWh, accounting for the major por-tion of electricity costs from fuel cells. Fuel costsalso constitute the fuel cell’s greatest advantageover some of its competitors such as the gas tur-bine, due to the fuel cell’s high efficiency whichyields substantially lower per kilowatt-hour fuel

costs. Major variations in fuel costs per kilowatt-hour will result primarily from fluctuations in fuelprices. Fuel cell efficiency variations, due to tech-nical improvements or maintenance practices(especially stack reloading schedules), also wouldbe reflected in different fuel costs. In the longerterm, post-2000, it is expected that natural gaswill have to be replaced with more abundantfuels. Primary candidates are synthetic fuels–especially methanol—from coal and biomass.

Stacks are of central importance in determin-ing cap ital, O&M, and fue l costs. The d eve lop-ment and extended demonstration of cheap (perkWe) and reliable stacks which can operate athigh efficiencies for extended periods are criti-ca l to the succ ess of the tec hnology. Tec hnologi-cal improvements which could be especially im-portant in this regard are the development ofinexpensive, c orrosion-resista nt cell structuralmaterials and less expensive and more effectivecatalysts to operate at higher pressures and tem-peratures, and improved automated fabricationand handling processes for large area cells. Alsoimportant is the development of cheap, reliableand efficient small-scale reformers (fuel process-ing units) and the improvement of various otherstandard components.

Combustion Technologies

Integrated Gasification/Combined-CyclePowerplants

introduction.-A coal gasification/combined-cycle powerplant centers around two elements.First is a gasification pIant which converts a fuelinto a combustible gas; other equipment purifiesthe ga s, Sec ond is a c omb ined -cycle po werplantin which the gas fuels a combustion turbinewhose hot exhaust gases are used to generatesteam which drives a steam turbine. While thegasification system can be quite separate and dis-tinct from the combined-cycle system, theyc a n

be integrated so that some of the heat dischargedin the gasification sequence is exploited in thecombined-cycle system, and a portion of the heatdischarged by the combined-cycle unit may berouted back for use in the gasification plant (seefigure 4-23). This section focuses on such inte-grated units, commonly referred to as IGCCS.

The primary attractions of the IGCC are its fuelefficiency and its low sulfur dioxide, carbonmonoxide, nitrogen oxide, and particulate emis-sions. The high efficiency allows for fuel savingsand henc e reduc ed op erating c osts. The po ten-tial for very low emissions makes the technologyparticularly attractive for using coal to generateelectric power. Another advantage allowed bythe IGCC is “phased construction. ” Some partsof the plant may be installed and operated be-fore the rest of the plant is completed;63 this canbe financially advantageous and is considered a

major selling point for the technology. The IGCCalso may be very reliable. In addition, the tech-nology requires less land and water than a con-ventional scrubber-equipped, pulverized coalboiler powerplant. Furthermore, its solid wastesare less voluminous and less difficuIt to handlethan those of its scrubber-equipped competitorand of the atmospheric fluidized-bed combustor(AFBC). Current estimates are that solid wastesfrom an IGCC will be 40 percent of a pulverizedcoal boiler and 25 percent of an AFBC of com-parable size.

The evide nce sugg ests tha t the IGCC o ffers afavorable combination of cost and performancewhen compared to its competitors (see also chap-ter 7). Nevertheless, a combination of two fac-tors—lead-times and risk—may mitigate againstits extensive deployment within the 1990s. Be-cause of its modular nature and positive environ-mental features, potentially the IGCC has lead-times of no more than 5 to 6 years. It is likely,however, that the first plants, at least, will requirelonger times–up to 10 years–because of regula-tory delays, construction problems and opera-t ional d i ff icul t ies associa ted wi th any new,complex technology. It may take a number of

GJFOr example ,the gas-turbine/generator setsm a y be installedbefore the gaslfiers and operated off o f natural gas. When the gasl -fiers are co mpleted , the synthetic ga s then ma y be used instead .



Nitrogento atmosphere

IProcess I . Flash I i

Claus Incineratedsteam Effluent ga s sulfur tall gas

treatment - recovery anincineration1

I4

Saturated steam

Po-we/ Generation (Argonne, IL Argonne National Laboratory 1983)

I Plantauxiliary

– Jpower




commercial plants before the short lead-time po-tential of the IGCC is met, unless strong steps aretaken to work closely with regulators and to as-sure quality construction for these initial plants.Such steps may be facilitated if the early plantsare in the 200 to 300 MWe range rather than thecurrent design target of 500 MWe. Should thelonger lead-times be the case, projects must beinitiated no later than the end of 1991 and per-haps as early as the end of 1989 if they are tobe completed within the 1990s.

In addition to these possible longer lead-times,l imited experience with IGCC demonstrationplants may also constrain extensive deploymentin the 1990s. Although there has been extensiveexperience with the gasification phase, currently,there is only one IGCC plant in operation, the100 MWe Cool Water plant in California (see fig-ure 4-24). In addition, there is another demon-stration plant using a different gasifier, under con-struction in a large petrochemical plant (discussedmo re in cha pt er 9). The Co ol Wat er plant ha sbeen very successful in meeting its constructionscheduled and budget, and in its early operation.As a result it has given confidence to utilities intheir consideration of whether to commit to an

b~An interesting discussion of the plannlng and construct ion of

an IGCC can be iound in: Cool Water Coal Gasification Program& Bech te l Power Corp., CoolWater Coal Gasification Program–Sec ond ,4nnua/ Prog ress Rep ort, interim repo rt (Palo Alto , CA: Elec -tric Power Research Institute, October 1983),EPRI AP-3232.

IGCC. Despite this success, however, more oper-ating experience is likely to be required beforethere will be major commitment to the IGCC bya very cautious electric utility industry. The Elec-tric Power Research Institute, a major sponsor ofthe IGCC Cool Water project, anticipates threeto four commitments by the end of 1986. If theseprojects go forward and the shorter lead-time po-tential of the IGCC is proven, then significantdeployment in the mid to late 1990s is quitepossible.

Description of a Typical IGCC in the 1990s.–Plausible cost and performance features of a rep-resentative IGCC are described in appendix A,table A-6. The referenc e year c onsidered in thereport is 1990, at which time two plants, gener-ating altogether approximately 200 MWe prob-ably will be operating in the United States. Thereference plant capacity is 500 MWe, consistingperhaps of five gasifiers,65 though installations assmall as 250 MWe might be preferred. While ca-pable of being built with capacities even smallerthan 250 MWe, such smaller installations wouldbe more costly per unit of capacity.66 The plantwould consist of three types of equipment: thegas production, cooling and purification facilities;the combined-cycle system (including gas tur-bines and steam turbines); and the balance of theplant. Included in the constituents of the latterare fuel receiving and preparation facilities, watertreatment systems, ash and process-waste dis-posal equipment, and in most cases an oxygenplant.

Gszaininger Engi r-reefing CO., capaci ty factors and costs o f Elec-tricity for Conventional Coal and Gasification-Combined CyclePower Plants (Palo Alto, C A: Elect ric Pow er Resea rch Institute , 1984),EPRI AP-3551 .

6 6 A c c o r d i n g t. on e s o u r c e (Electric b A @ ’ Research Institute, Eco-nomic Assessment of the Impact of Plant Size on Coal Gasification—Combined -Cyc /e P/ants (Palo Alto, CA:Elec trlc Pow er Resea rch in -stitute, 1983), AP-3084), theIevellzed cost o f electricity for avari-e ty of IGCCS using Texaco gasifiers increased as plant size de-

crea sed . The ec onom ies o f scale were relatively small among plantsof capacities greater than 250MWe. But as plant size diminishesbelow 250MWe, Ievellzed costs increase very significantly. Selec-tion of a 500MWe module also was favored by participants in aJune 1984 OTA-sponsored workshop onIGCCS, thoug h it wa s sug-gested that installations as small as 250MWe might seriously beconsidered.






combined-cycle system .73 Finally there are accessroads, site preparation, and various civil engineer-ing tasks; together these might represent roughly20 percent of capital costs.

Operating and maintenance costs could rangefrom 6 to 12 mills/kWh, a figure roughly equiva-

lent to the costs characteristic of a conventionalpulverized coal plant. The greatest source of un-certainty in the estimate concerns the perform-ance of the gasifiers, of the syngas coolers (if theyare used) and of the gas turbines.

Fuel costs for the reference plant are projectedto range from 15 to 17 mills/kWh based on 1990coal costs of $1 .78/MMBtu (see “Definitions” inappendix A for discussion of fuel costs). It is herewhere the possible cost advantage of the IGCCover the conventional scrubber equipped plantis greatest. Because of its higher efficiency, theIGCC’s fuel costs would be less than those of itsconventional counterparts. As discussed above,an important determinant of overall efficiency isthe gas turbine’s efficiency. Advanced turbineswhich are expected to be available by the early199os would be much more efficient than presentturbines. Their use could allow fuel costs to fallto the low end of the estimated range. Since fuelcosts account for a large portion of the cost ofgenerating electricity from the IGCC, the antici-pated improvement in turbine efficiency will af-fect the competitive position IGCC significantly .74

Atmospheric Fluidized=Bed CombustionIntroduction.–The AFBC is a combustion

technology which will provide an economic alter-native to conventional pulverized coal plants inthe 1990s. Its relatively low volumes of sulfur di-oxide and nitrogen oxide emissions, great fuelflexibility, small commercially available size ( <100 MWe), easily handled solid wastes, respon-siveness to demand changes, and other features

TIH G Hernphi l l an d M, B, jennings (Raymond Kaiser Engineers,

Inc.) , “Offsites, Utilitles, and General Faci l i t ies for Coal Conver-

sion Plants, o‘Ad va nc ed Ene rgy Syste ms— Their Role in O ur Future: Proceedings of the 19th Intersociety Energy Conversion Engineer-

ing conference, August 19-24, 1984 (San Francisco, CA: Amer i canNuclear Society, 1984), paper 849195.

7qB.M. Bancia, et al., “Comparison of Integrated Coal Gasifica-tion C o m b i n e d Cycle Power PlantsWith Current and AdvancedGas Turbines, ” op. cit., 1984.

offer advantages which may allow it to competesuccessfully with conventional plants, particularlyin areas where high sulfur coals are used. Invest-ment outside the utility industry in AFBC cogen-eration units already is growing rapidly, Greaterinvestment by utilities is likely in the 1990s,though various factors may keep the number oflarge utility-owned AFBCs operating by the endof the century below that which cost alone wouldset (see chapter 9).

There are tw o b asic typ es of fluid ized -bed com-bustors: the atmospheric fluid ized-bed combus-tor (AFBC) and the pressurized fluidized-bedcombustor (PFBC). The PFBC operates at highpressures, and therefore can be much more com-pac t tha n the AFBC. The PFBC a lso may p roduc emore electricity for a given amount of fuel. De-spite these potential advantages, the PFBC hasmore serious technical obstacles to overcome

and is less well developed than the AFBC. It hasnot yet been successfuIly demonstrated on acommercial scale, nor are any commercial-scaledemonstrations now under construction in theUnited States. It is unlikely that more than a fewcommercial units could be completed and oper-ating before the end of the century, though thePFBCs longer term potential is quite promising.

The AFBC, the focus of this analysis, operatesat atmospheric pressures. Small-scale AFBCs al-ready are used commercially around the worldfor process heat, space heat, and in various other

industrial applications; and are producing elec-trical power abroad as well as in very smallamounts in the United States. Three types ofAFBC installations may be important over thenext 15 years: large electric-only plants (100 to200 MWe), cogeneration installations, and non-electric systems. The electric-only units are likelyto be deployed by utilities, whereas the cogen-eration and nonelectric units probably would bebuilt and operated by others.

The cogeneration unit is an installation oper-ated to provide both electricity and usable ther-mal energy, while the nonelectric systems areused to supply usable heat only. Electric-onlyAFBCs may be new “grass-roots” plants builtfrom 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

77 A Cyc l o n e ,s a m e c h a n Ic a I device w h ICh sep a rateS Particles from

ga ses by using c entrifuga l force.78 A ~y~tem o f f a b r i c f l [ t e r s (bags) for dust removal from stack gases.







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 sev-eral year-s by the early 1990s.Also important willbe experience gained from the operation of a fullycom mercia1, 125 MWe cogeneration u nit—alsoa~ retrotit—being installed by a private firm inFlorida. And many hundreds of megawatts of

\ ma ll AFBs will ha ve be en insta lled b y 1990.

The reference AFBC plant considered in theanalysis has a generating capacity of approxi-ma tely 150 MWe (net). The g ross elec trical p ow erproduction of the plant actually would exceednet capacity, because power is required to oper-.~te the equipment which circulates the solids andforces air into the bed. Any commercial units con-sidered in the early 1990s are not likely to ex-ceed by very much the size of the demonstra-tion units; AFBCs are subject to scale-up problems

which probably will inhibit during the 1990s de-ployment of any commercial units much largerthan the demonstration plants.

Many features of the AFBC installations de-ployed in the 1990s, regardless of type, are likelyto b e much the sam e. They will req uire a ccessto coal and limestone supplies; this usually meansrailroad access. A rather sizable piece of land willbe required, not only for the AFBC itself but forcoal and limestone handling and processing fa-cilities, storage areas for the limestone and coal,disposal areas for the solid waste generated bythe plant, and ponds of various sorts. Disposalof spent limestone may be one of the most seri-ous problems for the AFBC. Current estimates arethat about 1,200 tons per MWe year need to bedisposed of for 3.5 percent sulfur, Illinois coal.




For a 150 MWe plant, about 90 to 218 acrescould be required; the exact amount depends onseveral conditions. Access to water also will berequired; the 150 MWe reference plant is ex-pected to require about 1.5 million gallons eachday.

Like any large powerplant, the AFBC is ex-pected to require a considerable amount of timeto deploy. An AFBC in the100 to 200 MWe rangepotentially has a lead-time of no more than 5years because of its smaller size and environ-mental benefits. As with the IGCC, however,lead-times of the first plants are likely to begrea ter, and c ould b e a s long a s 10 yea rs. Thisincludes up to 5 years for design, preconstruc-tion, and licensing activities; and 2 to 5 years forconstruction. Favorable regulatory treatment, andrapid and quality construction could result inlead-times close to the potential.

If in fact large, grass-root AFBC plants take upto 10 years to build from initial commitment,orders for them must be made by 1990 for theAFBCs to co ntribute ap preciab ly to gene rating c a-pacity before the close of the century. Given thefact that the three large demonstration plants andnumerous small cogeneration units will be oper-ating by then, there is a possibility that consider-able numbers of large plants indeed will be i niti-ated by that time.

The operating availability of an AFBC power-plant may be around 85 to 87 percent. But con-

siderable uncertainty surrounds this figure. Dif-ficulties with the fuel feed system in bubbling-bedAFBCs could severely reduce operating availabil-ity. Or erosion or corrosion associated with bothbubbling-bed and circulating-bed AFBCS couldhave similar effects.

AFBCs are expected to be used primarily asbase load plants, though their demand-followingcapabilities will allow their use in intermediateapplications. An AFBC plant is expected to lastfor approximately30 years, and to operate withan efficiency of approximately 35 percent—some-what 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 thatof its main competitors, the conventional scrubber-eq uippe d p lants and the IGCC. The estimate inthis ana lysis is $1,260 to $1,580/kWe. Fuel costsare expected to be approximately 17 mills/kWhassuming coal costs of $1.78/MMBtu. O&M costsare expected to fall between 7 and 8 mills/kWh,but high uncertainty is associated with this esti-mate. Should technical problems be experiencedwith the fuel feed system, or shouId serious ero-

sion or corrosion problems arise, power produc-tion could suffer and expensive repairs and modi-fications could be required. Consequently, O&Mcosts could escalate.

The major opportunities for research whichcou Id yield technical improvements in the AFBCor reduce uncertainty about performance lie i nthe three large demonstration projects which cur-rently are underway. These projects offer thechance to experiment with basically different de-signs and to compare technologies. Of particu-lar importance will be research relating to the fuelfeed systems and to designs and materials whichcan reduce erosion and corrosion of system com-ponents.

ENERGY STORAGE TECHNOLOGIESIntroduction

ing periods when the marginal cost of electricityThere are several tasks that electric energy stor- is high. I n ad dition, storage equipment ca n b e

age equipment , employed by utilit ies, can per- used asspinning reserve, the backup for gener-form. The most common isload-/eve/ing, i n a ting syste ms w hic h fa i1, o r a ssystem regulation,which inexpensive base load electricity is stored the moment-by-moment balancing of the utility’sduring periods of low demand and released dur- generation and load.






Figure 4-27.– First Generation CAES Plant

Exhaust

A f t e rcoo le rI

(Cools alrbefore It

enters cavern

~—.

t

I I Turbines I I

LI

H

— Iair

the turbine pass through a “recuperator” wherethey discharge some of their heat to the incom-ing air from the cavern; this, too, increases theoverall efficiency of the plant.

Three types of caverns may be used to storethe air: salt reservoirs, hard rock reservoirs, oraquifers (see figure 4-28). Each has its advantagesand disadvantages. About three-fourths of theUnited States rests on geology more or less suit-able for such reservoirs (see figure 7- I 2 in chap-ter 7). The salt domes are concentrated mostly

in Louisiana and eastern Texas. Salt caverns are“solution-mined” by pumping water into the de-posit and having it“ d issolve” a c av ern. The re-suIting reservoir is virtually air-tight. These saltcaverns are pressurized to up to 80 atmospheres,have a depth of 200 to 1,000 meters, and a vol-ume of 1,000 cubic meters/MWe.

Rock caverns are located throughout theUnited States. They must be excavated with un-derground mining equipment. A typical CAESplant using a rock cavern would be coupled to

38-743 0 - 85 - 5




Figure 4-28.—Geological Formations for CAES Caverns

Wells

Imperviouscap rock Air shaft

Solutlon-minedcavity I

Salt dome

Compensation

Salt caverns are mined by a techniquecalled solution-mining. A narrow well isdrilled into a salt dome and fresh water iscontinuously pumped in to dissolve thesalt while the resultant brine is pumpedout. The process is continued until thedesired storage volume is reached, The

Hard rock caverns are mined with standardexcavation techniques. A compensationreservoir on the surface maintains a con-stant pressure in the cavern as the com-pressed air is injected and withdrawn. Thisminimizes the volume of rock it is necessaryto excavate.

necessary volume is larger than that need-ed in a hard rock or aquifer systembecause without water present, thepressure of the compressed alr drops as itis withdrawn from the cavern,

SOURCE “Eighty AtmospheresIn Reserve” .E/WJourna/, April 1979

an above-ground compensating reservoir whichwould maintain a constant pressure in the cav-ern as it discha rge s. The ma intena nc e o f co nstantpressure offers several important operational ad-vantages. In addition to maintaining the desiredpressure, the reservoir also allows for a muchsmaller cavern than is the case with salt reservoirs.

Thus, only ab out 600 cub ic me ters/ MWe a re

needed underground, though a pool of about 700cubic meters/MWe of water is required on thesurface.84

M u~ e of ,1 c Onl pen 5at I ng reservoir I 5 less 5u Ita hl e fo r sa It re5er-

vo i r~ because the salt dissolves in the wa ter. Thisc a n o n Iy be pre-vented by the u5e ot’ water saturated Wtth salt, an approa( h whlc h

c o u 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 occurringgeological formations found in much of the Mid-west, the Four Corners region, eastern Pennsyl-vania and New York. An advantage of this kindof reservoir is that it does not require any exca-vation. It consists of a porous, permeable rockwith a dome-shaped, nonporous, impermeablecap rock overlying it. Compressed air is pumpedinto the reservoir, forcing the water downwardfrom the top of the dome. Later, as air is drawnfrom the reservoir, the water returns to its origi-nal plac e be neath the dom e. An important adva n-tage of this kind of reservoir lies in the fact thatthe volume of the reservoir is quite flexible, al-lowing for a variety of plant capacities and oper-ating schedules.

With the exception of the recuperator, thetechnologies required for CAES plants—the tur-bomachinery and the reservoir-related technol-

ogies such as mining equipment—are well-estab-lished tec hnolog ies. The turbo ma c hinery is onlya slight modification of currently used equipmentand there are several manufacturers, Americanand foreign, that offer CAES machinery with fuIIcommercial guarantees, While there are somequestions as to the dynamic properties of the airas it enters and leaves a cavern, there is littledoubt that the technology exists to build andmaintain underground storage facilities. Thesecaverns have been used for years to store natu-ral gas and other hydrocarbons, and the samefirms that supply the oil and gas industry haveoffered to provide utilities with CAES caverns thatcan be warranted and insured. 85

Despite the relative maturity most of the com-ponents which make up the CAES plant, therehas been no experience in the United States withCAES itself–though a CAES plant using a salt cav-ern has been in operation since 1978 at Huntorf,West Germany (see figure 4-29) and has per-formed well. This lack of domestic experiencewith the technology constitutes the largest hur-dle fa c ing CAES. There is a g ene ral reluc ta nc eamong utilities in this country to be the first to

make a commitment to build a plant. While sev-eral 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(Po w t>r R(+e,]rc h Initltut[’) ,lnd OTA \t,ltt, July 2, 1984

Figure 4-29.—The Huntorf Compressed Air EnergyStorage Plant in West Germany

[n the foreground is the wellhead, where compressed airIS Injectedand released The rest of the plant is in the backgroundSOURCE BBC Brown Boven, Inc

studies, the Soyland Electric Cooperative in 11-Iinois is the only American utility that has ordereda plant. This plant, however, was for various rea-sons canceled and no project has been initiatedsince then.

Typical CAES Plant for the 1990s

CAES plants in the 1990s are likely to be avail-able in two modular unit sizes, 220 MWe, com-monly called maxi-CAES, and 50 MWe, mini- CAES. These sizes are determined by the sizesof existing models of turbomachinery—the tur-bines, compressors, generator/motor, and a gear-box which connects them.

A CAES plant must be sited in an area with ac-cess to w ater and fuel. The turbo ma c hinery re-quires about 2,000 ga[lons/MWe of water perday, and a plant with a rock cavern needs addi-tional water for the compensation reservoir. Bothmini- and maxi-CAES plants burn about 4,000Btu/kWh of fuel and emit the standard combus-tion byproducts, such as nitrogen oxide, but atonly a third of the level of a similar size conven-tional gas turbine. CAES plants also have noiselevels similar to those of more conventionalplants. There are several waste disposal problemsinvolved with building the caverns. If a rock cav-ern is used, it is necessary to dispose of a large




volume of waste rock,8b and when a salt cavernis used, the brine pumped out of the cavern mustbe disposed of. Land requirements would rangefrom around 15 acres for a maxi-CAES plant to3 acres for a mini-CAES plant.

The lead-times expected for CAES plants willprobably range from 4 to 8 years. The large plantswould occupy the higher end of the range, whilethe smaller units would fall at the lower end. Theprimary source of uncertainty in lead-time esti-mates concerns licensing and permitting, whichis expected to take 2 to 4 years. Regulatory hur-dles will vary depending on the type of reservoirused. Among the regulatory impediments arethose relating to the disposal of the hard rock orbrine from the mining operation, and relating towater usage and impacts. Also problematic maybe the requirements of the Powerplant and in-dustrial Fuel Use Act of 1978. Even though a CAESplant is an oil and gas saving device, the fact thatit uses these fuels means a utility must receivean exemption from the act to operate one. Aprecedent was established when such an exemp-tion was grante d to t he Soyland Elect ric Coo p-erative, but under the current regulations, exemp-tions would be required for every CAES plant .87

The properties of the two sizes are similar (seetable A-8, appendix A); the mini-CAES turbo-machinery costs somewhat less—$392/kWe vs.$51 5/kWe for the maxi-CAES. The storage cav-erns can be formed out of three types of geologi-cal formations: aquifers, salt deposits, and hardrock. In general, aquifers are the least expensive,followed closely by salt. Rock caverns, whichmust be excavated, are by far the most expen-sive. on a total dollars per kilowatt basis, cavernsfor maxi-CAES plants are less expensive thanthose for mini-CAES.

BGThiS problem is greatly alleviated by the fact that the excavated

material can be used in constructing the compensating reservoiror other facilities (Peter E.Schaub, comments on OTA elect ric p owe rtechnologies November 1984 draft report, op. cit., 1985).

HTp, L, Hendrickson,Lega/ a nd Regulatory Issues ~ffWf/ng COnl-

pressed Air Energy .Storage (Rlchland, WA: Pacific NorthwestLal]-oratory, July 1981 ), PNL-3862,UC-94b.

Advanced Batteries

Introduction

Batteries are more efficient than mechanicalenergy storage systems, but their principal advan-tage is flexibility. Batteries are modular so thatplant construction lead-times can be very shortand capacity can be added as needed. Batterieshave almost no emissions, produce little noise( though because of pumps and ventilation sys-tems, they are not silent), and they can be sitednear an intended load, even in urban areas. Abattery’s ability to rapidly begin charging or dis-charging (reaching full power in a matter ofseconds, as opposed to minutes for a CAES sys-tem) makes it valuable for optimizing utility oper-ations. However, battery-storage installations donot benefit very much from economies of scaleeither in capital costs or in maintenance costs,so that if large blocks of storage are required,CAES may be less expensive. Also, though costeffective and reliable in numerous remote appli-cations, battery technology has not yet achievedthe combination of low cost, good performance,and low risk necessary to stimulate investmentin grid-connected applications.

There a re two typ es of utility-sc a le ba tte rieswhich under some circumstances could be par-ticularly important in the 1990s:advanced lead- acid batteries, and zinc-chloride batteries.Lead-acid batteries are in wide use today mostly inautomobiles and other mobile applications; ad-vanced lead batteries constitute an incrementalimprovement over the existing technology. Zinc-chloride batteries are a newer technology, andconstitute a fundamental departure from the con-ventional lead-acid battery.I n both cases, indi-vidual modules similar to commercial moduleswhich might be deployed in the 1990s, have beentested at the Battery Energy Test Facility in NewJersey. 88 Thoug h neither type of bat tery has be endeployed yet in a multi megawatt commercial in-stallation, plans to do so during the late 1980sare being developed and implemented.

Other battery technologies meanwhile are be-ing pursued. Among these, the most promisingappear to be zinc-bromide batteries and sodium-

~Bsee c h, g fo r further d e t a i Is on this f~c i Iity.



Ch. 4—New Tec hnolog ies for Gen erating and Storing Elect ric Pow er . 123

Typical Battery Installation for the 1990s

If battery technology is deployed in the 1990s

by utilities, the general requirements of a typicalplant, regardless of the battery technology em-ployed, are expected to be a peak power out-put of 20 MWe and a storage capacity of about100 MWh. Such a plant could consist of about10 to 50 factory built modules, along with con-trol and power conditioning equipment, housedin a protective building (see figures 4-30 and q-31). Battery installat ions outside the uti l i ty-industry might be considerably smaller.

The to ta l land nec essary will dep end on boththe so-called “energy footprint” (energy densityi n kilowatt-hour per square meter) of the particu-lar battery technology as well as the amount ofspace necessary for easy maintenance. Each ofthe reference battery installations discussed herewill require about 0.02 to 0.03 acres. There areno fuel and only minimal water requirements.

The lead -time required to d ep loy ba ttery insta l-lations is expected to be very short. Because ofthe comparatively low environmental impacts ofthe installation, licensing could proceed quiterapidly. And since the battery moduIes are fac-tory built, co nstruction c an b e ve ry rapid too . Thelead-time of the plant should be less than 2 years.

There is, however, uncertainty regarding the timerequired for Iicensing and permitting. Concernover possible accidents and disposal of hazard-ous materials, discussed in greater detail below,couId be a source of reguIatory delays particu -




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




Figure 4-32.— Lead-Acid BatteriesThe illustrations below show how a lead-acid battery stores electrlc energy. Advanced lead-acid batteries differ (n the construction of the elec-trodes, etc., but the basic operation is the same as the more traditional designs.

In its fullycharged state, the negative electrode consists of spongylead with a small mixture of antimony (around 10 percent), while thepositive electrode is lead dioxide. The electrolyte is sulfuric acid.

Electron flow.

Fully charged

When fullydischarged, the battery’s electrodes are almost entirelylead sulfate and the electrolyteIS largely water.

electrode electrodePbS0 4 PbS0 4

Negative Positiveelectrode electrode

\ ADischarging

To charge the battery, electrons are driven back into the negative

– Discharged

4 4 .2

Electron flow

l . -

electrode electrode

Charging

4




The safety ha zards of a dva nced lead -acid b at-teries occur primarily if the battery is over-charged. In this instance, it will generate poten-tially explosive mixtures of hydrogen and oxygenwhich must be ventilated. Stibine and arsine canalso be formed from the materials used i n theelectrodes. Finally, there are also dangers fromacid spills and fire. When the battery is decom-missioned, the lead must be recycled, and theacid disposed of. However, there is much experi-ence with lead-acid batteries, and few safetyproblems are anticipated if well-established main-tenance and safety procedures are followed.

Zinc-Chloride Batteries.–The zinc-chloridebattery has been under development since theearly 1970s. It is a flowing electrolyte battery (seefigure 4-33). During charging, zinc is removedfrom the zinc-chloride electrolyte and depositedonto the negative graphite electrode in the bat-tery stack, while chlorine gas is formed at thepositive electrode. The gas is pumped into thebattery sump, where it reacts with water at 10°C to form chlorine hydrate, an easily managableslush. During discharge, the chlorine hydrate isheated to extract the chlorine gas, which ispumped back into the stack, where it absorbs thezinc and releases the stored electrical energy.

A principal advantage of the zinc-chloride bat-tery is that it promises to be ultimately less ex-pensive than the lead-acid battery, due primar-ily to the inexpensive materials that go into its

construction. However, the technology, whichrequires pumps and refrigeration equipment, ismore complex—it is sometimes described as be-ing more like a chemical plant than a battery.94

Since no commercial design zinc-chloride bat-tery has yet been operated, any cost projectionsmust b e ta ken with some c aution. (See ap pen-dix A, table A-9.)

Estimates indicate that at a production level ofabout 700 MWe/year, zinc-chloride batteriescould be sold at a price less that-t $500/kWe, Be-cause zinc-chloride batteries will most likelymake their first appearance in grid-connected use(unlike lead-acid batteries which are already soldin other markets), this price is likely to depend

‘W)TAstatt;nter~ Iew~ with ( 1 ) ArnoldFickett, op. cit., 1984 a ndi2) J.J, KelleY, EXIDE Corp . , Aug. 29, 1984,

strongly on the volume produced. If only 50MWe/year were made, the price could be about$860/kWe; and early commercial units could costas much as $3,000 /kWe.

The zinc-chlorine b at tery may ha ve a long erlifetime tha n the lead -ac id ba ttery. The best cells

have run for 2,500 cycles, and while there havebeen numerous problems with pumps and plumb-ing, no basic mechanisms have been identifiedwhich would limit the lifetime to less than 5,000cycles.95 However, the 500 kWh test module atthe BEST facility has only run for less than 60 cy-cles, and several tough engineering problemshave yet to be overcome before the battery canhave a guaranteed lifetime long enough for com-mercialization. In addition, the AC to AC round-trip efficiency, which is currently in the low 60to 65 percent range for the large battery systems,must be increased to 67 to 70 percent; values inthis range have been attained by smaller prototypes.

The O&M requirements of zinc-chloride sys-tems are even more uncertain than for lead-acidsystems. However, the expected longer lifetimes,and the less expensive replacement costs for thestacks and sumps (estimated to be about one-third the initial capital cost of the battery) shouldlead to Ievelized replacement O&Mcosts in the 3 to 9 mills/kWh range. For lack of better dataon operating experience, the annual O&M costsare estimated to be the same as for lead-acid,Ito 4 mills/kWh, though because of the increased

complexity of the system, they probably will behigher.

Another major advantage of the zinc-chloridebattery over the lead-acid battery is that their re-ac tion rate s are c ont rollable. This is due to thefact that, in a charged zinc-chloride battery, thezinc and the chlorine are separated in the stacksand sumps. The rate at which the battery dis-charges is controlled by the speed at which thepum ps allow the rea c tants to rec om bine. This notonly makes the battery more flexible in its oper-ation, but provides a major safety advantage inthat if a zinc-chloride cell malfunctions, its dis-charge can be stopped by shutting off the chlo-rine pumps. In contrast, the reactants in a

~JOTA stdf~I nter~lew with ArnoldFickett, op. cit. ~ J 984.




Figure 4-33.—Zinc-Chloride Flowing Electrolyte Batteries

H

H

Fully charged

When the battery IS fully charged, the negative electrode IS platedwith zinc and the electrolyte has only a weak concentration of zincchloride. The battery sumpIS filled with chilled chlorine hydrate.

Elefl

Zinc [ / ZnCll(aq) C I1 = H 20’ H20

Charging

Heat

As the battery ischarged, chlorine ions from the electrolyte combineat the positive electrode to form chlorine gas and release twoelectrons. These electrons are driven to the negative electrode bythe charging generator There they combine with zinc being platedonto the negative electrode, The chlorine gas is pumped to the sumpwhich has been chilled to below 10 “C, The gas reacts with the coldwater and forms an easily storable solid, chlorine hydrate.

flow

Discharge

The battery IS discharged by heatingsump, which then releases the chlorine gas. This gas is pumped tothe stack, where it combines with electrons from the positiveelectrodes and breaks into chlorine ions. At the negative electrodethe zinc at oms release electrons and e nter the e lectrolyte as zincIons.

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 samebattery c ase, so t hat short-c ircuited terminalscould lead to a sudden release of the storedenergy.

A major concern of regulatory ofticials consid-ering zinc-chloride plants is likely to be the safety

problems associated with the accidental releaseof chlorine. Since the chlorine is stored in a solidform, there is no danger of a sudden release of

large quantities of the gas. However, the sameprocedures used in industrial plants manufactur-ing or using this gas must be followed. In addi-tion, the sum ps must be sufficiently insulated sothat in the event of a malfunction of the refriger-ation system, the chlorine will stay frozen in thechIoride hydrate phase long enough for repairsto be made.

SUMMARY OF CURRENT ACTIVITYThe ta bles in appe ndix A at the end of this re- i n the U n ited Sta tes. The extent to w hich c ap ac -

port summarize the cost and performance char- ity already has been deployed or is being con-acteristics discussed in this chapter. Table 4- 2 structed provides an additional indication of thesummarizes the information detailed in the ap- cost, performance and risk associated with thepe nd ix. Ta ble 4-4 provide s an o verview o f 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 StatusWind 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 ., . . . . . . . . . . . . .

Larg e . . . . . . . . . . . . . . .

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)f3.6 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’We10 MWe47 MWe (net)32 MWe (net)

2 x 3.5 MWe3 x 0.3 MWe3 x 0.4 MWe

10 MWe1 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 farmsU.S. wind farms outside

of CaliforniaAll U.S. wind farms

Daggett, CA

Albuquerque, NM

Daggett, CADaggett, CAPalm Springs, CA

Various iocationsVarious locations,Warner Springs, CA

SacramentoSacramento, CAHesperia, CACarrisa Plains, CACarrisa Plains, CABorrego Springs, CADavis, CABarstow, CA

Brawley, CASalton Sea, CAHeber, CASalton Sea, CA

Mammoth, CAHammersly Canyon, ORHammersly Canyon, OREast Mesa, CAWabuska, NVLakeview, ORLakeview, ORSuifurviiie, UTSulfurville, UTHeber, CA

NonutilityNonutility

Nonutility

Utility, nonutility, andGovernment

Utility, nonutiiity, andGovernment

NonutilityNonutiiityGovernment

NonutilityNon utilityNonutility

Utility and GovernmentUtility and GovernmentNonutilityNonutilityNonutilityNonutilityNonutilityNonutiiity

Utility lnonutiiityUtilitylnonutilityNonutilityNonutility

NonutilityNonutilityNonutilityNonutilityNonutiiityNonutiiityNonutiiityNonutiiityNonutilityUtility, nonutility, and

Government

InstailedInstalled

Under construction (1986)

installed

Installed

InstalledUnder construction (1986)Installed

InstailedUnder constructionInstalled

InstalledUnder construction (1985)instailedInstalledUnder constructionInstaiiedgInstalledInstaiiedg

InstalledInstalledUnder construction (1985)Under construction (1985)

InstalledInstalledInstaliedh

installedInstaliedInstaiiedh

Instailedh

Under construction (1985)!Under construction (1985)1

Installed





Chapter 5

Conventional Technologies forElectric Utilities in the 1990s





Chapter 5

Conventional Technologies forElectric Utilities in the 1990s

INTRODUCTIONThe financial difficulties faced by utilities in the

1970s and early 1980s have prompted many toinvestigate extending the lives of existing facilitesor even rehabilitating old plants to yield addi-tional capacity. Control of electricity end use hasalso surfaced as another promising alternative tomeeting all or part of future load growth. For mostof these utilities, however, conventional centralstation powerplants still provide the base againstwhich all other supply-enhancing or demand-

controlling investments are compared.This chapter presents a benchmark set of cost

and performance estimates for conventional op-

tions of traditional central station powerplantsand for a variety of options which extend the livesor otherwise improve the performance of exist-ing generating facilities. Since these strategic op-tions are not the principal focus of this assess-ment, these estimates are presented primarily toenable comparisons with the new generating op-tions discussed in chapter 4. These comparisonsare reported in chapter 8. I n addition, load man-agement, one of the strategic options being pur-

sued aggressively by utilities in many regions ofthe United States for controlling end use of elec-tricity, is discussed in this chapter.

PLANT IMPROVEMENT AND LIFE EXTENSIONIntroduction

In the wake of declining demand growth andsoaring costs of new generating capacity, manyutilities have begun to examine the so-called

plant betterment option for improving the per-formance of or extending the lives of existing ca-p a c i t y .1 T h i s o p t i o n i s l i k e l y t o b e c o m eincreasingly important through the end of this de-cade and into the 1990s—a period when the U.S.powerplant inventory will undergo dramaticchanges. For example, since 1975, new plant ord-er cancellations nationwide by utilities have ex-ceeded new plant orders. By the year 1995, ifpresent new plant ordering patterns continueabout a third of the existing fossil steam generat-ing capacity in the United States will be more

‘R. C. Rittenhouse, “Maintenance and Upgrading Inject New LifeInto Power Plants, ”Power Engineering, March 1984, pp. 41 -50;T. Yezerskl, Pennsylvania Electric Association Power GenerationCommittee, “Power Plant LifeExtension Practice at PennsylvaniaPower & Light Co., ”unpublished paper, Sept. 18, 1984; R.Care-Iock, Potom ac Electric Power Co.,“Plant Life Extension: PotomacRiver Gene rating Station, ” unpublished pa per, Septe mb er 1984.

than 30 years old (see figure 5-1 and table 5-1).The age distribution varies considerably byregion, however, as discussed in chapter 7.Moreover, the plants “coming of age” during thisperiod will be considerably more valuable than

those of early vintages. In the 1950s, unit sizesgrew to over 100 MW and heat rates fell to be-low 10,000 Btu/kWh while older units(1920s and1930s vintage) were much smaller with heat ratesof as high as 20,000 Btu/kWh. z While in the past,the benefits of new technology far outweighedpIant betterment options, because of the relativequality of currently existing plants, this situationis rapidly changing.

Traditionally, investments in aging fossil plantsbegan to decline after about 25 years causing re-liab ility to d eteriorate ac c ordingly. The plants

were relegated to periodic operation, reserveduty, and, finally, demolition. For the remainder

2R. Smock, “Can theUtillty Industry Find a Fountain of Youthfor Its Aging Generating Capacity?” E/ectric Light and Power, March1984, pp. 14ff.

133




.

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 plantscome on-line, existing base load fossil units willincreasingly be relegated to cycling duty whichcan significantly shorten plant life. Recent studies,however, show that in many cases, such plants,at least those built in the 1950sand 1960s, canbe refurbished cost effectively for $200 to $400/kW, even in cycling duty applications. 3Thesestudies also indicate that some refurbishmentprojects can include efficiency improvements,and capacity upgrades of 5 to 10 percent. a

Finally, many siting and environmental require-ments facing new capacity can be avoided byrebuilding existing capacity. Table 5-2 shows themarked contrast in these requirements for newversus existing coal-fired units. Current Federalregulations (New Source Performance Standards—NSPS) require that any unit that is more than 50percent rebuilt (defined as 50 percent of the costof a ne w boiler) must reduce sulfur dioxide emis-sions by 90 percent of the uncontrolled level. Itturns out that a great deal of plant betterment canbe accomplished under this 50 percent require-ment. Moreover, an important consideration withthis requirement is that the emissions reduction —. —

3Glbbs & HIII, Inc., “Considerations for Power PlantLife Exten-sion: Prospects for the 1990s, ” contractor report toOTA, October1984.

4R. Smo c k, “O pe rating Unit Heat Rate s Ca n Be Cu t, SaysEPRI;New Units Can Be 10 Percent More Efficient, ”E/ectric Lighf an d

Power, March 1984, p. 24.

Objectives of Plant Betterment Options

It is important to note that plant betterment isonly a substitute for new capacity to the extentplant retirement can be deferred past the timeoriginally scheduled, and the plant’s capacity canbe increased as a result of betterment. Whenthese conditions prevail, plant betterment optionsoffer considerable promise7 relative to other stra-tegic options. However, they present a compli-cated planning problem for utilities. Indeed, aconsiderable investment is often required to de-velop the details of a prospective project and itsexpected cost. For example, in 1984 WisconsinElectric Power Co. commissioned detailed plant— —

SThe regu Iation reads that an existing facility fal Is u rider thesesguidelines provided “it is technologically and economically feasi-ble to meet the applicable standards set forth in this part.”

b “ P o w e r Plant Life Extension Economics, Plans Explored at Amer-ican Power Conference,”E/ectric Lig ht a nd Power, June 1984, pp.27-30.

70ne indication that this promise is already being realized is thataverage plant availability of existing units in the United States hasincreased from 67 percent in 1977 to 76 percent in1984, partiallyas a result of plant betterment activities.

Table 5-2.—Environmental Requirements for Existing and New Plants

Particulate Air emissionsSO, NOX

Existing plants (1980 typical plants): Varies from 0.12 3.2 lb/MMBtu. Com- 1.3 lb/MMBtu.to 0.25 lb/ pliance based on No monitoringMMBtu coal analysis required

New p/ants >73 MW: 0.03 lb/MMBtu 1.2 lb/MMBtu and 0.6 lb/MMBtu20°0 opacity Re- 90°0 reduction ex - and 65°0quires baghouse cept 700/0 if emission reduction.or very efficient <0.06 lb/MMBtu. Complianceelect rostat ic Compliance based on based on con

precipitator continuous monitors. tinuous mo -Requires coal clean- nitorsing or wet scrubber(total capital =$2481kW)

Condensercooling water Ash disposal Wastewater treatment

Thermal l imits Sluicing and Combining wastebased on eco- ponding of streams (coal pile,logical studies combined fly broiler cleaning, etc.)

and bottom ash for cotreatment inash pond

Cooling towers Dry collection Dedicated possibleand reuse or separate treatmentIandfilling of pond(s) may requireflyash. Sluicing artificial liner(s) andand pending of chemical addition

reuse of bottomash

SOURCE W Parker, “Plant Life Extension—An Economic Recycle, ”Power Errg(neerlrrg, July 1984, and Judl Greenwald, U S Environmental Protection Agency, per-sonal correspondence with OTA staff, June 18, 1985




betterment studies on a number of existing fos-sil units, at a cost of more than $1 million perstudy.

In considering plant betterment or life exten-sion programs, utilities need to account for bothsystem level objectives, such as coordination with

existing capacity expansion and scheduled main-tenance plans, and unit level objectives, such asextending the life for a target number of yearsat a specified level of capacity, efficiency, andavailability. Indeed, the overall characteristics ofa utility’s system dictate the timing and level ofinvestment justified in a particular betterment/lifeextension project. For example, a utility with ahigh reserve margin may consider the relativelysimple step of derating an aging unit to lengthenits life, while a utility with a low reserve marginmay consider upgrading the unit to both extendits life and increase its capacity. Although the ageof the unit and the production lost during rebuild-ing may make the latter strategy more costly thanlife extension alone, usually it is still much lessexpensive than building new capacity.

Ultimately, all individual improvements relateto either increased productivity or longevity.Productivity improvements involve increasedefficiency; increases (restoration or upgrading) inrated capacity; reduced fuel costs (e.g., throughfuel switching); reduced labor requirements; in-creased capacity factors; and reduced emissions.L o n g e v i t y i m p r o v e m e n t s include mechanisms for

increasing plant life at specified levels of ratedcap ac ity. This ma y mea n extend ing the life of aunit at full rated capacity or, by contrast, “moth-balling” the unit for use at a later time when allor part of the rated capacity is needed; mothball-ing is sometimes referred to as an extended coldshutdown.

Virtually all life extension/plant improvementprograms begin with a detailed performance testof any candidate plant to determine the currentstatus of the equipment, i.e., how far the currentplant operating parameters are from the originaldesign specifications. Equipment evaluated in theperformance test includes the turbine generator,boiler, condenser, feedwater heaters, auxiliaryequipment systems, flue gas cleaning equipment,and plant instrumentation. Comparison of the

most recent performance test with historical per-formance identifies areas to be investigated inmore detail. A detailed examination of the boilerusually precedes other studies since its results arelikely to control the length of the overall plantbetterment project being considered. Also, otherareas of the overaIl study may be affected if, forexample, the boiler analysis reveals that it mustbe operated at lower pressure to lengthen its life.8

Recommendations resulting from a detailedperformance test and analysis, sometimes termeda design change package (DCP),9 generally fallinto two categories: 1 ) new procedures for start-up, operations and maintenance, training of per-sonnel, update of performance records, andspare parts support; and 2) equipment or com-po nent mod ific ations. The c ateg ory (1) improve-ments are usually relatively low cost and very costeffec tive. The nature of the ca teg ory (2) improve-ments depends on the age of the equipment andthe facility.

Likely plant betterment candidates are middle-age generating units (1 O to 20 years old) which,at some point in their lives, are usually relegatedto intermediate duty cycling where they experi-ence greater load changes, and more frequentstarting and stopping, As noted earlier, thischange in operation can significantly reduce theoperating life of the unit and, as a result, upgrad-ing of middle age units often means adaptingthem for cyc ling d uty. Typical enhanc ements in-

clude full flow lubricating oil systems, automaticturbine controls, and thermal and generator per-formance monitors (newer units will also bene-fit from these improvements). In addition, themiddle-aged units will benefit from turbine mod-ification and temperature control equipment.

Upgrading or life extension of older units (20years or more) usually requires evaluating thereplacement of major components such as tur-bine rotors, shells, and generator coils. While up-rating of components, such as the turbine, maybe possible for older units, it is usually a highly

8S. j. Schebler and R. B. Dean, Stanley Consultants, “ Fossil Pow erPlant Betterment ,” pa pe r presented at Edison Electric Institute PrimeMovers Committee Meeting, New Orleans, LA, Feb. 1, 1984.

9W . O’Keefe, “Planning Helps Make Plant Improvements MoreEffective,” Power, February 1984, pp. 89-90.



Ch. 5—Conventional Technologies for Electric Utilities in the 1990s q 137

customized job. Table 5-3 shows a typical tur-bine generator uprating checklist which gives thepossible limitations on a candidate upgrading pro-gram. Figure 5-2 shows the possible improve-ments in heat rate of an upgraded (uprated andrestored) turbine-generator unit.

The c om plexity of pe rformanc e testing andanalysis has prompted the major equipmentmanufacturers to offer comprehensive plant mod-ernization programs.10 Both manufacturers andarchitect-engineering firms see plant bettermentprojects as a promising market for their goods andservices.

Finally, some plant improvement projects maybe aimed at reducing emission levels or the useof specific fuels. For example, many projects inrecent years have been carried out to convert oil-fired capacity to coal. Such conversions often in-

volve unit derating, but recent studies show thatrecovering as much as two-thirds of the capac-ity lost after coal conversion can be achieved at40 to 50 percent of the dollars per kilowatt coalconversion cost. 11

IO For example , Westinghouse has been marketing turbine-generator upgrades for several years.

‘ 1 P, Mlliaras, et al., “Reclaiming LostCapab l l l t y in Power PlantCoal Conversions: AnIrrnovatwe Low-Cost Approa ch, ”Proceed-ings ot ’ th e joint Power Conference, AmericanSociety o f Mechan -ical Engineers, 1983, 83-J PGC-Pwr.

Figure 5-2.—Heat Rate v. Generator Output forUprated and Restored Turbine-Generator Set

9.000 L

“o 10 20 30 40Output – 1,000 kW

Relative Cost and Performance

The principal effects of fossil powerplant agingare: 1 ) decreased efficiency, i.e., the amount ofelectricity generated per Btu declines as plantheat rate increases, and 2) more and longerforced outages. Figure 5-3 shows the rate of in-crease in heat rate as a function of age for a typi-cal fossil plant; the average is about 0.3 percentper year with average maintenance practices. ’2After about 20 years, the reliability of typicalplants declines dramatically; figures 5-4 and 5-5show typical increases in rate and duration offorced outages as a function of age.

Utility concern about reliability, in particular,prompts the decision to invest in plant bettermentprojects because the cost of lost production dur-ing 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 factorof a 500 MW fossil unit will save the utility about$1.75 million a year. That savings must, of course,be ba lance d aga inst the c ost of a chieving the c a-pacity factor improvement; this trade-off is thec ent ral foc us of p lant b ett erme nt stud ies. Thetrade-off is illustrated in figure 5-6; the total “relia-

bility cost” of operating a generating facility is thesum of the cost of lost production when outagesoccur and the plant betterment investment (or



Ag ew

I

20 I

40



Ch. 5–Conventiona/ Technologies for Electric Utilities in the 1990s . 139

preventative m aintenance allowa nce) c harged tothe plant to establish a given level of reliability.The cost of outage decreases as reliability in-creases and the plant betterment investment in-c rea ses. The ta rget of a p lant be tterment programis 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 power-plant’s forced outage rate increases with age, theaging characteristics of individual plant compo-nents as well as the cost of improving compo-nent reliability may vary widely.

Regulatory and InsuranceConsiderations

Regulation of Plant Betterment Projects

In addition to engineering feasibility, compli-ance with over 50 Federal and State regulationsmay be required in the course of considering aplant betterment program13 These include Fed-eral and State air quality programs, water qual-ity and solid waste programs, environmental im-pact studies, Corps of Engineer rules, exemptionsfrom the Powerplant and Industrial Fuel Use Act,and utility commission approval—see table 5-4.

Perhaps the most important regulatory consid-erations are the major Federal air quality regula-tions of NSPS, mentioned earlier, and the Pre-

vention of Significant Deterioration (PSD) rules.Generally, Federal regulations apply to a plantbetterment program that increases emissions byany amount or costs more than 50 percent of anew boiler. State Implementation Plans and otherState air quality statutes will generally apply toall projects,

Of particular concern maybe the NSPS require-ments which require that, if a fossil plant ( >250MMBtu/hr and constructed prior to 1971) is ei-ther “modified” or “reconstructed” as definedin table 5-4, the plant is subject to the 1978 NSPSprovisions of stringent emissions limitations andpercent sulfur removal. Thiswould in most in-—.———

I ~D , ward and A, MekO,‘‘Regulatory Aspects of power plant Bet-terment, ’ H’orkshop Notebook: Fossil P/a nt Life Exten sion (PaloAlto, CA: Electric Power Research Institute,June 1984), EPRIRP- 1862-3.

Table 5-4.—Powerplant Life Extension Projects:Regulatory Summary

Federal requirements: NSPS (air):

q Standards apply if facility is:1. new:

—replacement of boiler

2. modified: —physical or operational change that results inincreased emissions.

3. reconstructed: —fixed capital costs exceed 50°/0 of the cost of a

new steam generator.PSD (air):

q Permit requirements apply to “majormodification ’’—modification for which net emissionsincrease exceeds de minimis limits (permit may beissued by State).

NPDES (water):q Permit required for point source discharges to

navigable waterways. Modified sources require newor modified permit (permit may be issued by State).

State requirements: Air:

q New or modified construction and operating permitsrequired.q Bubble policy may apply,

Water:q New or modified construction and operating permits

required.Solid waste:

c New or modified construction and operating permitsrequired.

Other requirements: EIS:

. Not required unless major renovation subject toFederal licensing occurs.

Corps of Engineers:. Nationwide permits for construction activity in

navigable waters are available.State PUC:

q Approval requried for modification of powerplant andrecovery 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 facilitywhere few, if any, existed prior to the modifica-tion. The req uirem ents are even more stringentfor plants constructed between 1971 and 1978.It is important to note, however, that under thecurrent regulations a great deal of plant better-ment can be and is already being accomplishedwithout these provisions being invoked.

A PSD p ermit is a lso req uired fo r any ma jormodification to an existing plant; a special set ofprovisions defines and is appliedto such modifi-cations. Finally, if an upgraded existing facility in-creases emissions in a nonattainment area, pol-lution offsets would be required.






Ch. 5—Conventiona/ Technologies for Electric Uti/ities in the 1990s q 141

CONVENTIONAL GENERATING OPTIONSin order to be deployed in significant numbers,

the developing technologies addressed in this re-port must compete successfully with existing elec-tric utility gene rating op tions. The five m ajor c on-

ventional power generation technology types thatwill mo st likely be availab le to elec tric utilities inthe 1990s are: pulverized coal-fired plants, com-bined-cycle plants, combustion turbines, slow-speed diesels, and light water nuclear power-plants.

This section briefly presents the benchmarkcost and performance estimates for these fivetechnologies as well as for life extension of ex-isting coal-fired plants. Cross-technology compar-ison o f these tec hnologies with the de velopingtec hnologies is conta ined in chapter 8.

Table 5-5 conta ins the b enc hma rk set o f costand performance estimates for the five conven-tional technologies. All of the listed technologies,except one—combustion turbines—are capableof b ase load op eration. Three of these te chnol-ogies, pulverized coal-fired, combined-cycle, andslow-speed diesel, are also capable of interme-diate-load ope ration. One major differenceamong the conventional alternatives is plant size.Although there is increasing interest in small,modular plants (see chapter 3), the technologieslisted in table 5-5 are generally large, central sta-tion powerplants. Slow-speed diesels and com-bustion turbines represent the smaller sized cen-tral station technologies.

The Ievelized c ost mo del used in cha pt er 8 wa sused with the cost and performance estimatesshow n in ta ble 5-5 to d erive m ost likely elec tricutility costs. These Ievelized c osts are p resentedin figure 5-7. This figure also includes a Ievelizedcost estimate for existing coal powerplant better-ment. The p lant c osts and the c ap ac ity and effi-

Figure 5-7.—Conventional Technology Costs,Utility Ownership—West

Techno logy

ciency upgrades discussed earlier were appliedto the generic coal plant listed in table 5-5 to de-rive a n expec ted co st for coa l plant b etterment.According to this figure, the lowest cost conven-tional alternative is life extension and plant bet-terment of existing coal units. The next lowestcost c onventional a lternative is pulverized c oa lplants, followed by light wa ter nuclea r plants.

The c ost and pe rforma nc e estima tes for theconventional technologies discussed in this sec-tion represent the present technologies expectedto be available in the 1990s. Additional enhance-ments to these technologies or different designconfigurations may occur prior to 1990 whichcould dramatically change these expected costs.




Table 5.5.—Cost and Performance Summaries

Technologies. —Pulverized Combined- Combust i on 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 . . . . . . . . . . . .

1990500 MWe

6-8 years640 acres5.94 million

galiday

9.5 mills/ kWh

17 mills/ kWh

1990 1990600 MWe 150 MWe

3-4 years 2-3 years5-10 acres 2-5 acres2.9 million Negligible

gal/day

199040 MWe

2 years10-15 acresNegligible

850/o 680/0Base Base

Introduction

The term load ma nag eme nt refers to m anipu-lation of customer demand by economic and/ortechnical means. It involves a combination ofeconomic arrangements and technology typically

direc ted towa rds one of the following o bjec tives:1.

2.

Encouraging demand during off-peak peri-ods: During the valleys of a load curve, alarge portion of generating equipment is idle.Utilities be nefit when tha t c ap ac ity is mo reheavily used. This typically is achieved byeither shifting use to those periods frompe ak-de ma nd p eriod s (loa d shifting) or byencouraging additional use during off-peakperiods (valley filling).Inhibiting demand during peak periods: It

may also be desirable to reduce peak-period

demand. When electricity is purchased fromother utilities, costs per kilowatt-hour dur-ing these periods are high. Or, to meet peak-pe riod de ma nd, a utility ma y have to usege nerato rs which a re more costly to ope r-

ate because they are older and less efficientor they b urn more expe nsive fuel. In a dd i-tion, if growth in pea k-pe riod de ma nd re-quires the utility to invest in new capa c ity,load management may reduce the rate atwhich such expenditures must be made.

In the context of this study, the most impor-tant benefit “of load management lies in the sec-ond o b jec tive which if rea lized a llow s utilities todefer ad ditional pea k-load generating ca pa city.In addition, by reducing the share of the loadserved during the peak period, load managementpermits a higher proportion of demand to beserved by lower cost electricity. other advantagesare also becoming evident as utilities gain moreexperienc e with loa d m ana ge ment, and as so-phisticated models are developed which permitbetter assessment of load management. 18 For ex-

IeFor example, See: I ) John L. Levett & Dorothy A.COnant, “LoadManagement for Transmission and Distribution Deferral, ”PublicUtilities For?nighr/y, vol. 115, No. 8, Apr. 18, 1985, pp. 34-39; 2)Associated Power Analysts, Inc.,Study of Effect of Load Manage- ment on Generating-System Re/iabi/ity (Palo Alto, CA: Electric PowerResearch Institute, 1984), EPRI EA-3575.



Ch. 5—Conventional Technologies for Electric Utilities in the 1990sq 14 3

ample, load management may reduce future de-mand uncertainty. And some utilities have foundit to be an effective means of improving the effi-ciency of power system operation by allowing in-creased flexibility in the hour-by-hour allocationof system resources.19

Load management is only one of many closelyrelated options available to utilities in managingdemand. Other demand management alterna-tives include encouraging conversions to electricpower through new applications, and more effi-cient use such as home insu Iation and electronicmotor controls.In add ition, demand ma nage-ment is also carried o ut indirec tly to the de greethat customers are encouraged to generate theirown p owe r. These other de ma nd ma nag eme ntoptions may be pursued independently of loadmana gem ent, or may be implemented a s pa rt ofan integrated program with load management.Depending on the nature of the demand man-agement strategy, the utility’s daily load curve canbe modified as shown in figure 5-8.

Within load management falls a very widerange of strategies, technologies, and economicarrangements. These typically center aroundsome combination of: 1 ) load management in-centives, 2) advanced meters, and 3) load con-trol equipment, While many other elements maybe present in a load management program, theseap pea r to b e of p ivotal impo rtanc e. Although in-ce ntives will be to uched upon b elow, the em-phasis will be placed on the technologies them-selves: spe c ifically advanc ed meters and loadco ntrol eq uipm ent.

With respec t to the number of custom ers, theresidential sector is by far the most important i nload management. But the fact that the sectorconsists of a large number of relatively small con-sumers ma kes loa d ma nag eme nt q uite difficultto assess and implement. In part, because of this,only a sma ll frac tion of the ma jor electric ap pli-ances in this sector have load management con-trols (see table 5-6). Nevertheless, utilities are

increasingly interested in residential load man-agement, both because the sector uses a large— — —

“B . F. Hast ings, “Cost and Performance of Load Managemen tTech nologies, ” comments presented at O T A Load Managemen tWorkshop, Washington, DC, Aug. 15, 1984.

quantity of electricity (in 1984 it accounted for34 percent of all electricity used) and because itis the largest contributor to the daily fluctuationsin demand (see figure 5-9).

In the industrial and commercial sectors, whileonly a relatively small number of loads have been

managed, the contribution has been significant.These sec tors contain ma jor load s ame nable toload management, and, compared to the residen-tial sector, fewer customers with larger demandsper customer. Hence, load management is al-ready practiced more widely in these sectors.Considerable opportunities remain, however,and industrial and commercial customers likelywill continue to account for a major portion ofloa d m ana ge ment d uring this century.

Current evidence suggests that load manage-ment will provide , in ma ny cases, an e conom ic

alternative to new g enerating c ap ac ity in the1990s, It may be a particularly attractive utilityinvestment when it is part of an integrated sys-tem designed not only to manage loads but alsoto serve other utility or customer needs.

Some o f the potential for load mana geme nt ca nbe met by using existing technologies at currentcosts and performance levels; but considerablygreate r app licat ion w ill req uire the introduc tionof technologies which offer a combination ofcost, performance, and risk superior to currenttechnology. Furthermore, institutional arrange-ments must be developed within which loadmanagement can be more easily deployed. Fi-nally, the costs, benefits, and uncertainties of loadmanagement options must be better understoodand integrated into the thinking of utilities andof others upon whose decisions affect load man-agement deployment.

Major Supply/Demand VariablesRelating to Load Management

Key End-Use Sectors and Applications

Central to loa d ma nag eme nt in the 1990s willbe the electricity demand patterns which developin the united States. What sectors will be mostimportant and ho w will they use elec tric ity? Thesepatterns determine the magnitude of the load atany time, and the shap e o f the load c urve, They




Figure 5.8.— Load Shape Objectives

“Adapted from Clark W,Gellings, Highlights of a speech presented to the 1982 Executive Symposium ofEEI 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




Electric Power Research Ins;ltute May l’9&l), EPRI EM.3529

also strongly influence the selection of load man-agement strategies. For example, managing in-dustrial use of electricity for process heat will bequite different than that of managing residentialelectricity demand for air-conditioning.

Usage patterns will depend on many inter-related variables; precise predictions of futureconsumption are impossible.20 Nevertheless,many useful generalizations can be made bylooking at the conditions which have character-

ized the p ast.In the residential sector, the single most impor-

tant application of electric power is air-con-ditioning, which in 1984 accounted for about 14percent of delivered residential electricity .21Somewhat less important but still sizable quan-tities of electricity were used for water heatingand spa c e he ating. These three a pp lic ations ac -counted for over a third of residential electricityc onsump tion in 1983. These a pp lianc es are p a r-ticularly important in load management efforts

~~F~r example , see: Rene H. Males, “Load Management—TheStrategic Opportunity, ”Workshop Proceedings: Planning and Assessment of’ Load Management (Palo Alto, CA: Electric PowerResearch Institute, 1984), EPRI EA-3464, pp. 3-1 through 3-8.

j I End-use energy consumption excludes the energy used to gen-erate and transmit electricity to the end-use sectors, and accountsfor only the energy used by the consumer.

because they typically are major contributors tofluctuations in overall demand for electric power(see figure 5-9).

In the commercial sector, lighting and air-conditioning are the most important applicationsfor electric power, each accounting for roughly40 percent of electricity use. Much of the rest isused in used in water and spac e heat ing. The useof electric power for air-conditioning and spacehea ting in the c om mercial sec tor is espe c ially im-

po rtant . They ac counted for 12 pe rcent of na-tional electricity use (1 984) and contribute sig-nificantly to daily fluctuations in demand.

In industry, the largest fraction of electricpower—over 50 percent in 1984—is used in ma-chine drives. Electrolysis accounted for about 13percent industrial electricity use; slightly less wasused in generating process heat. Most of the bal-anc e w ent for for spa c e hea ting a nd lighting.While industry uses a large amount of the elec-trical energy, its cyclical variations tend to be lessextreme tha n those in the c ommerc ial and resi-dential sectors.

As table 5-7 suggests, the individual applica-tions which account for the largest portion ofelectricity use is found in the industrial sector,followed by the co mmercial sec tor and then the




Figure 5-9.—illustration of Customer Class Load Profiles—North Central Census Region in the 1970sPeak summer day Peak winter day

5 10 15 20H o u r




electric power rather than generating it them-selves. These characteristics, alone or in com-bination, may encourage load management.Thoug h the se fe a tures va ry from o ne ut ility to thenext, some regional generalizations can be made.(See the sec tion on load m ana ge ment in c hap -ter 7.)

Current Status ofLoad Management Efforts

Because of the large variety of forms which loadmanagement may take, it is very difficu k to ac-curately dete rmine the extent to which it is be -ing exercised by utilities. There are, howe ver, twokey indicators of load management activity which

have be en e xam ined in deta il in surveys by theElectric Power Research Institute (EPRI). First isthe implementation by utilities of innovative ratesdesigned to modify customer electricity demandpa tterns. Sec ond are a c tivities by the elect ric util-ities relating to direc t load c ontrol.

Innovative RatesThe Electric Power Research Institute in 1983

sponsored a survey of elec tric utilities to ga therinformation on innovative rates in the utility in-dustry. EPRI found that at least half of the investor-owned utilities in the United States had imple-mented or proposed innovative rates; and about6 percent of publicly owned utilities had doneso . 23 The most c o m m o n l y a p p l i e d r a t e s w e r etime-of-use rates, rates which are linked to thespecific time at which the power is needed.Figures 5-10 and 5-11 illustrate how a time-of-use

rate can affect electricity demand.Ab out 20 million elec tric ity custom ers served

by utilities which responded to the EPRI surveyare a ffec ted by innova tive rate s. That is ab out 21perce nt of a ll the utility custom ers in the UnitedStates. 24Most of the customers under the inno-vative rates were in the residential sector, though

IJThe estimates are based on information provided by the Elec-tric Power Research Institute(Ebasco Business Consulting Co.,/nno-

vative Rate Design Survey (Palo Alto, CA: Electric Power ResearchInstitute, 1985), EPRI EA-3830).In the responses to a checklist sent to the members of the Amer-

ican Public Power Association and the National Rural Electric Co-operative Association, approximately 175 members reported inno-vative-rate design activity. Since there is a total of about 3,069publicly owned utilities in the United States, this amounts to about6 percent of all publicly owned utilities. This 175-member estimateshould be treated as a low figure, as it does not includeutilitieswhich were not members of the two associations; nor does it in-clude utilities who did not respond to the checklist.

In the case of the investor-owned utilities,EPRI found that 106utilities have either proposed and/or implemented innovative rates.Since there are about 204 investor-owned utilities inthe UnitedStates, this amounts to about 52 percent of those utilities. As withthe publicly owned utilities, this should be treated as a low figure.The number is based on only 123 survey responses–about 60 per-

cent of investor-owned utilities,lqThis is based on an estimate made by the Ecilson Elecrric lnstl-tute that there was a total of 97 million ultimate customers of theentire electric utility industry as of Dec. 31, 1983 (Edison ElectricInstitute, Statistic/ Yearbook of the f/ectric Uti/ity /ndustry (Wash-ington, DC: EEI, 1984),p, 58),




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 ofElectricity Use

V 9 am Noon 3 pm 6 pm 9 pm MidnightHour

there were a substantial number of industrial andcommercial customers as well.25

Unfortunately, very little is known about theprec ise imp ac t o f these rate s on e lectric ity sup-ply and d ema nd na tionwide. To the extent thatassessments have been made, they typically havebeen utility-specific and limited in scope. Theava ilab le e vide nce indica tes that utilities have .in many instances, effectively and economicallymanaged loads by implementing carefully struc-tured rate programs.26 But this has not always

Z5According to a study by the Rand Corp. (Jan Paul Acton, et al.,Time-of-DayElectricity Rates for the United States (Santa Monica,CA: The Rand Corp., November 1983), more than 12,000 com-mercial and industrial enterprises fell under time-of-day rates (themajor form of time-of-use rates) by the early 1980s.

ZGlbid.

been the case. Rates in some cases have beendeveloped and implemented which have had lit-tle or no impact on demand patterns. This is anindication of the difficuIty in understanding cus-tomer demand patterns and in designing and im-plementing rates for load management.

Load ControlUtilities have controlled loads in the United

States for about half a century. The earliest ef-forts in the United States, in the 1930s, involvedthe installation by utilities of timers on appli-ances 27 to inhibit appliance operation during pre-selected periods. But only within the last decadehave utilities seriously considered load controlas a po tentially at tract ive investment.

The 1983 EPRI surve y a lso soug ht to assess ut il-ity activities in load control. *a While, as men-

tioned earlier, numerous objectives could beserved b y load c ontrol, the survey found that ithas been viewed primarily as a means of reduc-ing wholesale p ower co sts and has be en m ostvigorously pursued by utilities which purchasemuch of their power from other utilities. By farthe most active in load control are rural distri-bution cooperatives and municipal utilities. To-gether they ac co unted for one-third of the load scontrolled in 1983.

As is the case with innovative rates, the largestnumber of customers subject to load control fallswithin the reside ntia l sec to r (see t ab le 5-8). Table5-6 summarizes the load management activitywhic h was unde rway a mo ng U.S. residenc es, *gand provides a rough idea of the number ofpoints whic h are a va ilable fo r c ontrol. The ta b lesuggests that only a very small portion-perhapsonly a few percent—of the residential appliancesare subject to load control.

Given the large p ote ntial in the South (see ta -ble 5-6), it is not surprising that in 1983, roughly

Z7Synerglc Resources corp. , 1983 Survey of Utiiity End-useProjects (Palo Alto, CA: Electric Power Research Institute, May 1984),EPRI EM-3529.

z81bid.zgThe table includes only space heating, water heating, andair-

conditioning. It does not include pool pumps and other controlledpoints.




Table 5-8.— Load Control: Appliances and SectorsControlled in 1983 Under Utility ”Sponsored

Load Control Programs

58 percent of the load control points30 nation-wide were located there; 37 percent were i n theNorth Central region, followed by the West, with11 pe rc ent. The Northea st, thoug h it ap pe ars tohave somewhat more controllable points than the

West, accounts for less than 2 percent of thepoints currently controlled.The nationwide imp ac t of the load co ntrol

measures in place in 1983 has not been preciselydetermined. It can be very roughly estimated,

howe ver. The ave rag e p ea k loa d reduc tiona l re-ported in the 1983 EPRI survey of 298 utilities was1 kW for each controlled residential air-con-ditione r and 0.6 (summ er) to 0.9 (winter) kW forea ch co ntrolled resident ial wa ter hea ter. Theseaverages should be interpreted with caution; theresults vary widely from one utility to the next,Since there were 643,910 residential water heatersand 491,695 residential air-conditioners con-trolled in 1983, the peak load reduction mighthave been roughly 880 MWe in the summer (ifall the water heaters were controlled during thesummer) and 580 MWe (if all the water heaterswere controlled during the winter).

While p ositive results we re observed for manyload control projects, utilities often were notwholly satisfied with the performance of the loadmanagement technologies they used. In particu-lar, eq uipment ha s been relatively unreliable. Theproblems resulted from a combination of factors.To som e extent these resulted from inferior prod -uc ts, or othe r supp lier prob lems; but ma ny a lsoresulted from the m anner in which the te chnol-ogy was used. Most of these problems have beenalleviated over time and appear to be the kindof passing difficulties which are to be expectedwith the application of new configurations of tech-nologies to relatively complex circumstances .32

Potential Peak Load ReductionsFrom Load Management

The potential peak loa d reduct ion from loa dmanagement in the 1990s depends on many fac-tors. At the most b asic level, the pe ak load re-duction from any load management program de-pends on: 1 ) the total numbers of customers andelectricity using appliances, 2) the nature of theappliances and the manner in which they are——...—

JIThe p e a k load reductionis the magnitude of the additionalpower which would have been required to meet demand had theappliance not been controlled.

JzAnalysis and Control of Energy Systems, Inc.,Residential Load Management Technology Review (Palo Alto, CA:Electric PowerResearch Inst i tute , 1985) , EPRI EM-3861 .




used, 3) the extent to which customers partici-pate in the load management effort, and 4) thepeak load reduction achieved for each appliance.These va riables in turn dep end on m any othe rconditions, some of which vary greatly from utilityto utility, and even within the territory of a util-ity. Only now are methods being developed andrefined for predicting the results of load manage-ment programs.33

An accurate, reliable, and detailed estimate ofthe nationwide potential of load management re-quires an effort beyond the scope of this report.However, strong evidence suggests that there aremany opportunities for increasing the number ofcustomers and points under load managementprogram s, It is app arent tha t thoug h innovativeelectricity rates are becoming more common inthe United Sta tes, mo st ut ility custome rs do notyet fall under such rates. Likewise, as table 5-6

sugg ests, only a tiny frac tion of custom er loa dsare controlled through load control programs,Evidence suggests that customers in many–

though not a//–instances would be favorably dis-posed towards both special rates and load con-trol.34 The prec ise c ustom er respo nse de pend snot o nly on the c harac ter of the c ustome rs butalso the nature of the load management effort. 35

Where rates and load control are implemented,significant peak load reductions may occur. Con-siderable variation in customer attitudes towardload mana geme nt and in the impa cts of load

JJsee the following: 1 ) Robert T. Howard, “EstimatingCustomerResponse to Time-of-Use Rates, ”Workshop Proceedings: Planning and Assessment of Load Management (Palo Alto, CA: Electric PowerResearch Institute, 1984), EPRI EA-3464, pp. 16-3 through 16-4. 2)T.D. Boyce, “Estimating Customer Response to Direct Load Man-agement and Thermal Energy Storage Programs, ”Workshop Proceedings: Planning and Assessment of Load Management (PaloAlto, CA: Electric Power Research Institute, 1984),EPRI EA-3464,pp. 16-7 through 16-10.

Jdsee: 1 ) Thomas A. Heberlein & Associates,Customer Accept-ance 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 Attitudesand Acceptance of Load Management, ”Workshop Proceedings: P/arming and Assessment of Load Management (Palo Alto, CA: Elec-tric Power Research Institute, 1984),EPRI EA-3464, pp. 4-1 through4-21; and 3) Ebasco Business Consulting Co.,/nnovative Rate De-

sign Survey, op. cit., 1985.Jssee Tom D. Stickels, San Diego Gas & Electric, “AnalyzingCUS-

tomer Acceptance of Load Management Programs, ”Workshop Proceedings: Planning and Assessment of Load Management (PaloAlto, CA: Electric Power Research Institute, 1984),EPRI EA-3464,pp. 16-1 through 16-3.

management likely will characterize different util-ities across the country.

The ma nag em ent of a relatively sma ll numb erof large individual loads, such as those commonlyfound in the industrial and commercial sector,typically will present fewer problems and impose

lower costs than management of a large numberof small loads. A rate structure which encouragesload management may be applied readily and ef-fec tively to large users. The d ep loyme nt b y utili-ties of the technologies required to implementsom e o f the se ra tes among suc h users is gene r-ally inexpensive relative to the potential gains forthe utility. Moreover, once the economic incen-tive is offered, the users themselves (industrial andcommercial) frequently are capable of deploy-ing technologies which are effective in changingtheir demand in accordance with the utility’s in-centives and their ow n ec ono mic interests.36

Where a large number of small users are in-volved such as in the residential sector, thediffic ulties are m ore limiting. In 1983, there w ereover eight times as many residential customersin the United Sta tes than c ommercial and indus-trial customers. And the average residential cus-tomer used less than 9 MWh/year, comparedwith 1,560 MWh/yea r by the ave rag e industrialcustomer and 53 MWh/year by the average com-mercial customer.

Consequently, special rates tend to be lessrea d ily and p rofitab ly ap plied to the reside ntial

sector, and the cost-benefit ratio for the utility foreach load, managed is likely to be larger. In ad-dition, the cost and difficulty of installing, main-taining a nd op erating the eq uipm ent, req uiredas an adjunct to such rates may be consideredexcessive by utilities. Compounding the problemsis the utilities’ uncertainty about future residen-tial electricity use, and the manner in which itwould change under alternative load manage-ment programs.

JbFor an assessment of the possible costs and benefits of load man-agement using incentive rates for seven major industries, see: ChemSystems, Inc., The Potential for Load Management in Selected in-dustries (Palo Alto, CA: Electric Power Research Institute, 1981 ),EPRI EA-1821-SY.



Ch. 5—Conventiona/ Technologies for E/ectric Utilities in the 1990s q 15 1

At present about 1.5 million points are con-trolled,37 which is only a small fraction of thenumb er of reside ntial loa ds that c ould be con-trolled (proba bly less than 1 perce nt). A muc hlarger potential exists in every region of the coun-try, particularly in the South where residentialelectricity demand is high and there are a large

number of all-electric homes. A recent survey ofthe stated intentions of utilities indicates that ifcurrently planned load control programs are im-plemented, at least 5 million new points may becontrolled by 1990. 38 Another report suggests that8 million points will be controlled by 1990 and20 million points by 1995,39 40

The po tential ma gnitude of the imp ac t of loa dcontrol is diffic uIt to ga uge. Evide nce from cur-rent load management efforts indicates that theimpact couId be quite sizable. If, for example,one air-conditioner in each of 5 million homes

were controlled, and if an a verag e p eak load re-duc tion of 1 kWe we re ob tained, a p eak load re-duction of about 5,000 MWe would result. Notetha t nea rly 50 million home s have a ir-co ndition-ing and that many of these have more than oneair-co nditione r. Also resident ial a ir-co nditioningrepresents only one of many loads which couldbe controlled.

Overall, the potential for load management issuch that it is an important strategic option in theU.S. electricity supply outlook in the 1990s.Whether utilities fulfill this potential will dependon the cost, performance, and risk of load man-agement technologies and on the ability of theutilities to m ana ge those technologies and de -velop innova tive rates.

——.——~zsynergic Resources Corp., 7983 Survey of LJtillty End-Use

Projects, op. cit., 1984.’81 bidJgThe La I rd Durham CO., T he United States Market for Res/den-

tia/ Load Contro/ Equipment, 1983-7995 (San Francisco, CA: LairdDurham Co., 1984).

‘$OA recent Frost & Sullivan reportsuggests that 7 mllllOn Pointswill be controlled by 1992 (Frost & Sullivan,E/ectric Utility Cus- tomer Side Load Management Market (New York: Frost & Sullivan,1984), as reported in “Load Management Systems Will ControlSeven Million by 1992, ”E/ectric Light& Power, vol. 62, No. 8,Au-gust 1984, p. 47).

Technologies for Load Management

Given the magnitude of demand in the residen-tial sector, its importance in contributing to thefluctuations in demand for electric power, andthe characteristics of individual residential cus-tomers, it is not surprising that the technology-

related problems of current utility efforts to man-age loads center on sma ll users. This will also bethe emphasis here. Many of the technologies, is-sues, and problems in the residential sector, how-ever, also a re a pp licab le to the o ther sec tors.

Two princ ipa l group s of tec hnolog ies are re-quired in load management:

1. Advanced meters: Meters measure electri-city use; recorders, often integrated into asingle device with the meter, record this in-forma tion for lat er use. The d a ta help in de-veloping load management strategies, in im-

plementing them, and in assessing theirresults. They a lso fac ilitate the applica tionof rates which enco urag e the d eploymentof customer-owned and operated load man-agement technologies.

2. Load control systems: In order to controlloads, utilities may need to be capable ofcommunicating with the customer. Commun- ications systems provide this link, allowingthe transmission from the utility to the cus-tomer, and perhaps vice versa. Required forsuccessful load control systems are decision- logic technologies which interpret informa-tion a nd autom atica lly ge nerate dec isionsnecessary for effective load management,

Advanced Meters 41

The p redo minant resident ial elec tric m ete r andrecorder used in the United States is the single-phase (see chapter 6 for definition of single phaseand other relevant terms) electromechanical watt-hour mete r which requires pe riodic reading b yan individual on location. A variety of solid-statemeters, “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 deviceswhich not only perform the measuring function, but also recordand perhaps even manipulate the data.

4ZA hybr id m e t e r is on e which couples the common meter ’s rotat-

ing sensing-element to a solid-state m Icroprocessor.

38-743 0 - 85 - 6




equipment (including communications technol-ogies) are ava ilab le a nd b eing developed to a s-sist in meeting the rising information needs ofload management. Among the equipment beingdeveloped is hardware which can be retrofittedto existing equipment to enhance the capabilitiesof c omm on m eters.

Advanced meters can perform many moretasks. For example, they may provide the cus-tomer not only with data on current and past use,but also information on p resent c osts and o thermatters; that additional information could bewholly or partly generated by pre-programmedequipment on site or transmitted from a remoteloca tion. Where time-of-use rate s were b eing a p-plied as part of a load management program, theinformation is essential for the consumer. Alter-natively, the meter could provide direct and auto-matic input to the load control system. For ex-

ample, a “demand-subscription service” meterwill auto ma tica lly trigger a seq uenc e of eve ntsdesigned to curtail load when the meter indicatesthat demand has exceeded a specified level.

Currently available advanced meters, however,often are expensive, unreliable, and short-lived,relative to conventional meters. Considerable evi-dence indicates that the technical problems couldbe resolved relatively easily, but developers ap-pear reluctant to do so without assurances thata major market exists. Similarly, costs can onlybe reduced sufficiently through mass productionand deployment.

Another consideration is that the conventionalmeter is a long-established fixture in U.S. utilityoperations. It performs the task expected of itwithout imposing inordinately large operatingand maintenance costs. While new meter designscould in the long run be superior, they wouldrequire 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 beneeded, and operating procedures would haveto be modified to accommodate the new tech-

nology.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 unresolvabletechnological barriers impede the deployment ofadvanced meters. Rather, the problems appearto be related to the development of an early mar-ket among utilities and to the need for changesin utility prac tice s. The evidenc e indicates tha tunless conc erted efforts are m ad e to eliminatethese imp ed iments by stimulating d emand , thede ployment of ad vanc ed meters will be a slowprocess. Their conventional competitors likelywill predominate we ll pa st the c lose o f this cen-tury, though their position will be eroded slowlyby the new er techno log ies.

Load Control Systems

Load control systems vary in the extent towhich c ontrol is c onc entrated on e ither side o fthe meter (customer or utility); in the extent towhich information from the customer side-of-the-

meter is used and in the nature of that informa-tion; and in the degree of automation on the cus-tom er side-of-the -mete r. Som e req uire relativelyactive customer participation and a low level ofautomation. For example, the utility may simplycall up the customer and ask that his load be re-duced as much as possible; the customer couldrespond by turning va rious app lianc es off, bas-ing his actions on a multitude of considerations.Other systems, however, may be more auto-mated and are capable of operating with little orno customer intervention.

Load control systems are classified into threecategories—local, distributed, and direct con-trol—according to the degree to which decisionsare centralized and the extent to which the util-ity and customer interact before the load is ma-nipulated . In a dlirec tcontrol system , the load iscontrolled by the utility without any immediateinput in any form from the customer’s side of theme ter (see figure 5-1 2). This in the past ha s bee nthe d ominant form o f load co ntrol.

In a loca / c ontrol system, the load is controlledfrom the customer’s side o f the me ter, withoutimmediate input from the utility (see for exam-ple figure 5-1 3). With local control systems,manipulation of the customer’s load is basedsolely on immediate input from only the custom-er’s side of the meter. Utility involvement is re-



Ch. 5—Conventional Technologies for Electric Uti/ities in the 1990s q 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 heatercontrols




Figure 5-13.— A Local-Control Load ManagementTechnology: Temperature-Activated Switches

Time and temperatureswitch

Percentagetimer

Outdoortemperature

sensor

stricted to indirect inputs such as incentive rates.Loc al co ntrol devices have b een enc ourag edwhere appropriate rates have been instituted. Buttheir application has been limited in the residen-tial sector, in part because such rates may requirerep lac ement of c onventiona l me ters with moreadvanced meters.

ity-sponsored load control p roject s— 1.2 millionpoints–utilized direct control systems, while278,000 points were controlled by distributedcontrol systems, and 10,000 points fell underutility-sponsored local control programs. Manymore points are locally controlled without theutilities’ direct sponsorship, but with indirect util-ity support, usually through direct incentives andrate structures.44

The key p rob lem e nc ounte red in all c ontrol sys-tems is the management of loads in a mannerwhich is satisfactory to the customer yet whichprovides an acceptable degree of control and pre-dictability to the utility. The greater the utilities’direct control, the greater the risk of customerdissatisfaction. Conversely, systems which givethe utility less direct control over the load—whileperhaps alleviating communications and cus-tomer problems—risk reducing the utility’s capac-

ity to effec tively mana ge the load . While direc tcontrol has dominated in the past, utilities are in-creasingly moving towards distributed and localcentrol.

Discussed be low a re the two key tec hnologi-cal components of load control: “decision-logic”technologies and central controllers and commu-nications technologies.

Central Controllers and Communications Tech-nologies.– Direct and distributed control systemsuse technologies which fall into three categories:central controllers, transmission systems, and areceiver/switch at the customer’s end of the sys-tem.45If the system c ommunica tes in tw o direc -tions, a “transponder,”which both receives andtransmits, is required on the customer side of themeter; and a receiver must be in place on theutiIity’s side of the meter to receive the informa-tion sent from the customer’s transponder.

The c ontroller ge nerates com ma nds whic h a reencoded and dispatched through some transmis-sion system, and received by the receiver whichtranslates the encoded message and accordinglymanipuIates the load. While the hardware com-

ponent of modern computerized controllers is

QQSynergic Resources Corp., 198 3 Survey of Utility End-useProjects, op. cit., 1984.

451bid.



Ch. 5—Conventional Technologies for Electric Utilities in the 1990s q 155 .—

Cooling

Peak period

Heating

tI Indoor temperature

I

01

e

well developed and readily available commer- The c ommunications system–which includecially, the software is not. Rec ent utility experi- the transmission system a nd the rece ivers—hasences indicate that software deficiencies are the been subject of greatest discussion among util-primary cause of difficulties in the implementa- ity op erators. A va riety of system s are availabletion of load management programs. Current evi- to choose from:denc e sugg ests tha t softwa re-problems are sur-

q

mountable, but that effective software is likely torequire considerable time to develop and refine,and to some extent must be customized for each

q

ut i I it y.4b

Radio: This is currently the predominantcommunica tion system used for loa d ma n-agement .

Power-1ine carrier (PLC) systems: These sys-tems use the utility’s already installed trans-mission or distribution networks (or both) tocarry the signal.




q

q

q

Telephone: Telep hone lines can be used inseveral different ways in communicating in-formation to and from the utility.Cable TV: Using a cable modulator, the util-ity injec ts its signa ls into the cable netwo rk.Receivers are “hard-wired” to the cable atthe c ustom er’s end .Hybrid communications systems: These sys-tems incorporate two or more of the abovesystems in one load control system. This al-lows incorporation of the best features ofboth systems while avoiding some of theirpitfalls.

Each of these communications systems has itsad vanta ges and disad vanta ges. They d iffer in theamount of information which can be communi-cated over any period of time; the reliability withwhich the c omm unica tion ta kes plac e; the ex-tent to which the communication system already

exists; the cost and technical risk associated withthe system; and the ease with which the utilitycan deploy and utilize the system in conjunctionwith a load management program. It is impor-tant to no te tha t the hardware itself is in manyinstances fully mature, and involves little tech-nical risk. In some cases, however, technical im-provements remain to be made and costs maystill be reduced.

The c urrent d eb at e over comm unica tions sys-tems centers around which best serves the needsof the utility. These ne ed s extend be yond the use

of the communications network for load control,and touch on their application to remote meter-reading, distribution system automation,d’ andother uses. The needs also extend beyond thenear term in that the utilities seek systems whichare flexible enough to perform a variety of futuretasks.

For example, one choice the utilities have isbetween one- and two-way communications sys-tems. One-way systems are sufficient for loadcontrol, but two-way systems allow utilities tomonitor more closely the results of load controlby transmitting information from the customer to

dTDiStribution automationis the remote control of the distribu-tion system which transmits electricity to customers from local sub-stations; such control could offer significant improvements in overallpower 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 Ex-plores 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 LoadManagement Technologies: Some Implications for Utility Planning and Operations (Washington, DC: World Resources Institute, 1984).






trad itiona l utility p lanning ac tivities. SJ Moreo ver,as will be discussed in chapter 8, systematic ana-lytica l tools for com pa ring load ma nage mentstrategies with other strategic options are notwidespread.

Even if economic benefits of load management

are calculated to exceed direct costs, utility oper-ators may prefer not to pursue load management.They ma y enc ounter difficulties in reaching ag ree-ments to jointly use communications networkswith nonutilities. Access may be limited or pro-hibitively expensive; legal impediments may beencountered. 54 Or customers themselves may be

sjEnergy ManagementAssociates, t nc., /SSUeS in Implementinga Load Management Program for Direct Load Control (Palo Alto,CA: Electric Power Research Institute, 1983), EPRI EA-2904.

54’’ Justice Department States Cautious on UtilityTelecommuni-cations 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 problemso far—given incentives customers to date havebeen very receptivess---it is a significant un-known that co uld potentially imp ede the de ploy-ment of direct and distributed load control tech-nologies.57

—...—

SsAnge[ Economic Repofis and Heberlein-Baumga rtner ResearchServices, 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 Condi- tioning, op. cit., 1981.

5TAla n S, Miller and Irving Mi ntzer,Draft Report: Evolving Load Management Technologies: Some Implications fo r Utijity Planning and Operations, op. cit., 1984.



Chapter 6

The Impact of DispersedGeneration Technologies on

Utility System Operationsand Planning



CONTENTSPage

Introduction. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..............161Interconnection of Dispersed Generating Sources. . . . . . . . . . ..............,161

Overview . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ...............161Current Industry Issues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. ..,162

Interconnection Performance. . . . . . . . . . . . . . . . . . . . . . . ...................165overview . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .,165Protection and Control Subsystems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ....165

Distribution System and DSG Device Protection Problem Areas . ............167P o w e r C o n d i t i o n i n g . . . , . . . . . . . . . . . . .Metering . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Interconnection Costs. . . . . . . . . . . . . . . . . . . . . . . . . .Utility interconnection Standards . . . . . . . . . . . . . . . .Utility System Planning and Operating Issues . . . . . .

Overview . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Electric System Planning ..., . . . . . . . . . . . . . . . . . .Electric Power Systems Operations . . . . . . . . . . . . .

List of FiguresFigure No.6-1. Layout o f of a n Elec tric Power System . . . . . . . . . .6-2. Distribution System and DSG Device Protection6-3. Costs for Interconnection of Qualifying Facilities



Chapter 6

The Impact of Dispersed GenerationTechnologies on Utility System

Operations and Planning

INTRODUCTIONAs the penetration of dispersed generating

sources increases in U,S. electric power systems,the imp lic at ions for system planning, op eration,performance, and reliability are receiving in-c rea sed at tention by the industry.IThe interestin dispe rsed ge nerating technologies has beenstimuIated by new Federal laws that have in-creased the economic attractiveness of such sys-

tems. As discussed in chapter 3, the Public Util-ity Regulatory Policies Act of 1978 (PURPA)opened the way for customer-owned generationmandating interconnection with existing electricsystems.

The c ha rac teristics of ma ny alternative g ene r-ating technologies pose both potential benefitsand prob lems for electric system planning a ndop eration. The b ene fits of d ispe rsed ge nerationgenerally stem from the potential of substituting

plentiful, environmentally acceptable and renew-able sources of energy for conventional fuels.Due to the modularity of many of these alterna-tive technologies, deployment on an incrementalbasis is possible, offering the potential for a moreec onom ic expa nsion of the generation supp ly.(Other benefits are discussed in chapter 3.)

The nonconventional aspects of dispersedsources of g eneration c onc ern elec tric utilitieslargely because of the industry’s lack of knowl-ed ge reg arding p erforma nce o f these systems.There is c onc ern, for exam p le, ab out the lac k ofutility control over generating resources. in ad-dition, where alternative generation supplies arewea ther dep endent, produc tion is intermittent.Similarly, many c og ene ration supp lies are highlydependent on the process to which they arelinked . Finally, inc reasing p roduc tion a t the d is-tribution level poses new questions regardingreliability because the delivery system is less relia-

ble at the distribution level tha n a t the transmis-sion or bulk level, i.e. a kilowatt of productionat the distribution level is less reliable than onegenerated at the bulk level.

INTERCONNECTION OF DISPERSED GENERATING SOURCESOverview

The c onc ep t of a dispe rsed source o f ge nera-tion (DSG) has a variety of meanings, often re-sulting in some confusion. In this document, aDSG is any generating device (irrespective of size)that introduces power into an electric deliverysystem, but not at the bulk power level or at thetraditiona l point where a pa rticular utility’ s c on-ventional ge neration injec ts po wer. By and large ,

this means elec tric po wer produc tion linked tothe distribution system of the utility, such as mostnon utility pow er produc ers that are q ualifying fa-cilities (QFs) under PURPA.

While present day electric systems have beenstructured (in capacity, protection, and configura-tion) to allow safe and reliable operation with-out the presenc e o f a DSG d evice , most research-ers agree that with proper modification of the

161




electric network configuration and operationpractice, a DSG d evice ca n be co mpa tible withthe electric system.

Current Industry Issues

Trad itiona lly, utilities and the age nc ies tha t reg-ulate them have primarily been concerned withpower flows in electric systems in one direction: 2

either from utility-ow ned central stat ion po wer-plants to customers through the transmission anddistribution network, or from one utility toanother. More recently, however, the incentivesoffered under PURPA and other Federal and Statelaws have promoted addition to the electric gridof DSGs which a re o ften nond ispa tc hab le andpredominantly nonutility-owned. Management ofthese “two-way” power flows has introduced anew element of complexity into the operation of

elec tric utilities. As a result, ut ilities and DSG cus-

tom ers have b egun to foc us some a ttention onthe nature, quality, and cost of the interconnec-tion equipment, and regulators have begun to ex-am ine the ir role in mana ging the integ ration ofDSGs into the utility grid.

The issues associated with interconnection

have their root s in the wa y po wer is generatedand transmitted through the utility grid. A typi-cal grid (shown in figure 6-1) is composed of sev-eral large central generating plants, connectedto bulk power transmission lines. These lines typi-cally are maintained at the highest voltages in thegrid. Power is then transported through a networkof transformers and lower voltage lines until itreaches the customer. Depending on the type ofend use, an industria l customer with large p roc-ess needs may connect directly to primary dis-tribut ion c ircuits, while mo st resident ial c ustom -ers connect to secondary distribution circuits atlower voltages.

In addition to power lines and transformers, thegrid also includes protection equipment such ascircuit breakers, relays, and switches as well ascontrol equipment such as voltage regulators,capacitors, and tap-changing transformers. Inpo werplants, co ntrol of turbine, freq uenc y, andexcitation systems is performed. While, a central

Figure 6-1 .—Layout of an Electric Power System ——— — — —.———— — — ——— ———— ——————————— ————

IIIIIII

I

I

IIIIII

Generatings t a t i o n Subs ta t ion

I I

Distributionlines to

customers






duced. As a consequence, harmonic voltage p roblems typically will result in a location remote from th e point of inject ions

While there seems to be no general agreementconcerning the precise acceptable level of dis-tortion, typically utilities limit THD at the pointof injec tion to less than 5 perce nt of the c urrentsigna l with any single ha rmonic less tha n 3 per-cent, and 2 percent of the voltage signal with anysingle harmonic less than 1 percent. Filtering out

this distortion may be expensive for smaller sized

DSGs. Therefore, anot her issue tha t ha s surfac edis whether or not all interconnected harmonicsources should be required to meet specifiedTHD standards, or whether these standardsshould vary according to DSG size and type.

In addition to power quality issues, utilitiesare concerned with the proper measurement ofnet power generated by DSG customers. Shouldall DSG customers be required, and thereforecharged, for extra metering equipment? Utilities

are a lso c onc erned with the liab ility of DSG c us-tom ers for utility employee ac c ide nts or equip-. , s

5“Computer Simulation Study, ”ORNL/SUB/81-9501 1/1, Oak m e n t d a m a g e t h a t m a y r e s u l t f r o m i m p r o p e r i n -Ridge National Laboratory, Oak Ridge, TN, August 1983. terconnection.






current, over- and under-voltage, and over- andunder-frequency of the power produced from theDSG; and 2) filters to eliminate excessive har-monics and electromagnetic interference. A ma-

jor issue is the setting of these relays to providean appropriate level of protection, yet avoid “nui-sanc e tripp ing” of the DSG off-line whe never sys-tem po we r qua lity cond itions vary over the nor-mal course of the day. Of related concern are thecost implications of the tolerance range—thecosts for more sensitive protection equipment arehigher. These issues are discussed later.

Protection philosophy covers both the normaland abnormal operating conditions of the elec-

tric system . The prob lem of p rotec ting the elec -tric system involves protection of the distributionsystem, loads, and other customers as well as pro-tec tion of the DSG. 8 The mo st c onc ern a rises dur-ing abnormal operation when potential damageto the electric system, its customers, and the DSGcouid o cc ur. The o verall protec tion philosop hyand problems are presented in figure 6-2.

6D.T. Rizy, Personnel Safety Requirements for Electric Distribu- tion 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 ANDPROBLEM

Potential safety problems for electric utility per-sonnel a re also of c onc ern to the e lec tric utilityindustry. Attention is foc used on the ad eq uac yof present maintenance practices and hardwareto ensure a safe working environment. Work pro-cedures9have been developed for both ener-gized (live line) and de-energized (dead line)maintenance practices.

For de-energized line work, there are six basicsafety steps: notification, certification, switching,tagging, testing, and grounding. When work ispe rforme d on ene rgized system s, insulating de-vices such as rubber gloves and mats, insulatingstools and platforms, and/or insulated tools suchas hotsticks are used by utility personnel. Guide-

lines of the Oc c upa tiona l Safety a nd Hea lth Ad-ministration (OSHA) require that utility personnelmay not approach or take a conductive objectwitho ut suitab le insulat ion. The a ddition of a DSGdevice has the potential of converting a dead lineto a live line without knowledge of the mainte-nanc e pe rson. The ea siest w ay to preve nt th is sit-uation is to either place a manual disconnect atthe DSG o r use live line m aintenance p rac ticeswhere DSGs are present.

Power Condit ioning

For wind and photovoltaic generators, the PCSis perhaps the most crucial link in the intercon-nec tion app aratus. Ea rly PCS and m any low c ostsystems consisted of inverters which oftenproduced many harmonics and operated at lowconversion efficiencies. However, recently therehave been a number of important advances indevelopment of PCS technologies. These newtechnologies use a method called high-frequencymodulation (H FM) to chop the dc output into thesine wave pattern of ac power, using solid-stateswitching devices.10Such equipment generally

‘D,T, Rizy, et al., ( lperd t ;onal and Design Considerations for E/ec-trvc Dlstrfbutlon Systems With D\spersed Storage and Generation (DSG) (Oak Ridge, TN: OakRidge National Laboratory, Septem-ber 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 PROTECTIONAREAS

produces fewer harmonics; has higher efficien-cies and power factors; increased fault and reclos-ing detection; and improved voltage regu Iation

compared to earlier, line-commutated designs. 11

Working with utilities, private PCS manufac-turers and government researchers at SandiaLaboratory have developed and improved uponresidential-sized ( <20 kW) “advanced-design”PCS. A p roto type Sandia -de signed HFM-PCS per-formed we ll in ut ility simulatortests.12 Further re-search is underway at several utilities, such as atGeorgia Power (see box 6B). Most engineersagree that the H FM-PC has superior performanceco mp ared to earlier line-comm utatedinvertersin terms of power quality. For example, current

HFM devices in production (for 2 to 4 kW gener-ators) produce harmonics similar to those of hairblowdryers, and have power factors between0.97 and 1.00. The new eq uipment has fast a ndreliable rec losing and fau It detection capabilities,accomplished through electronic sensing andc ontrol. I n the c ase w here a fa u It (e. g., prec ipi-tated by a thunderstorm) disconnects the PCSfrom a utility, logic and control circuits turn offthe PCS, thus preventing a ny dange r to the util-ity and any reconnec tion of theDSG if the util-ity quickly returns on-line.1s




cation, July/August 1984’ andR.S. Das, et al., “Utility-InteractivePhotovoltaic Power Conditioners: Effects of Transformerless Designand DC Inject ion,”paper presented at Intersociety Energy Con-version Engineering Conference, No. 849413, August 1984.

This increased PC p erformanc e, however, come sat a premium price. If HFM devices were requiredby ut ilities, the increa se in price wo uld b urde n thesmallest generating customer. (See figure 6-3 in nextsection for cost comparisons of different sized inter-connection equipment.) One suggested alternativeis to institute varying requirements for different sizesand types of generators. Utilities have begun to usethis idea in their ow n guidelines for interconnec -tion (a s d isc ussed in the ne xt sec tion) b y havingdifferent sections of the guidelines apply toward aparticular size of generator.

Som e utilities a re still c onc erned about t he so-c alled “ po llution” of their po we r system s, whileothers consider this concern as overly restrictive.Some researchers believe that if non-DSG custom-ers cannot distinguish differences in power qual-ity, the utility should no t p ena lize DSG c ustome rswith overly stringent and costly requirements. 14 This

would shift the issue of “how high a power qualityis appropriate” to the question “what are custom-ers willing to pay to receive higher power quality?”These issues are b eing d eb at ed in the tec hnica lcommunity.

Metering

The third and last c omp onent o f interconnec -tion is the metering equipment used to measurepower consumed by the customer. In general,the three types of meters available today are thesingle watt-hour, double watt-hour with rachets,

and advanced meters.15

The single watt-hour me-ter is in common use in most homes and costsabout $30 (1 984$). If a DSG is producing power,the me ter simply runs bac kward. This c onfigu-ration only measures net power use and assumesthat there is no difference between the utility’sreta il rates and its rat e fo r purcha sing p ow er fromDSGs. If these rates are different, which is usu-ally the case, then two meters are routinely used,one of which runs in the reverse direction tomeasure power produced; both meters haverachets that prevent any reverse rotation. Anotherconfiguration uses more advanced meters to

I qMartin Schlect, General Electric Co., personal Communicatlon,jU & 1984.

I SDiscussed in more detail in C)TA, /ndustria/ and COmmefc;a/Cogeneratior?, op. cit., 1983.






two levels of protection, using manufacturers in-formation and price catalogs currently available.For the higher level of protection, additional in-terconnection equipment is used, such as dedi-cated transformers, more expensive “utilitygrade” (see box 6A) relays, and more protectiondevices.

interconnection costs include engineering la-bor and the equipment cost of switchgear, powertransformers, instrument transformers. For instal-lations under 50 kW, these costs can be pro-hibitive when using utility-grade equipment andproviding the typical level of protection for gen-erating equipment. (Many of the details of inter-connecting DSGs have been tabulated else-where. 21) These costs are still much higher thanthe Department of Energy’s (DOE) suggestedprice of $200 to $300/kW for “economical”interconnection equipment for residential gener-

ators. 22 While future technological advances suchas microprocessor controls, less costly nonmetal-lic construction, and integration of different com-ponents could bring prices down, “the major cost

z I D T, RIZY, protection drl~ Safety Requirements for Electric Dis-tribution 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 pro-duction” of interconnection equipment.23

For systems using inverters, perhaps the mostcostly component for interconnection is thepower conditioning subsystem (PCS). In 1981,Sandia Laboratories asked four potential PCS

manufacturers to estimate their selling price forthese units, assuming they would be sold in quan-tity lots of 1,000. The prices ranged from $109to $254/kW for 100 kW-sized units. Since receiv-ing the se e stima tes, Sandia repo rts tha t the c ostof solid-state power devices has fallen dramati-cally and predicts that prices will drop substan-tially in the future.24

Interconnection costs have continued to de-c line d uring the p ast 5 years. How ever, the c ostof interconnection for smaller units remains ahigh proportion of the cost of the generation

eq uipme nt ($600/ kW). The c ost for intercon ne c -tion for larger units is about 5 to 10 percent ofthe c ap ital co st o f these units.

23T. S. Key, “Power Conditioning for Grid-Connected PV SystemsLess Than 250 kW, ’’op. cit., 1984.

Z4D. Chu and T.S. Key, “Assessment of Power Conditioning forPhotovoltaic Central Power Stations, ’’paper presented at IEEEPhoto-voltaic Specialist Conference, May 1984.

UTILITY INTERCONNECTION STANDARDSIn the first years since the enactment of PURPA,

few utilities had any published guidelines deal-ing with interconnec tion requirem ents. In 1983,OTA reported that mo st interc onnec tion co nfig-urations were custom-fitted and no general pat-terns for utility standards hademerged.zs Since1983, the number of applications from dispersedgenerating customers to interconnect to utilitieshas increased. As a result, more utilities havestandardized their interconnection requirementsin the form of published guidelines. The guide-lines, approved by the Public Service Commis-

sion, usually require data and drawings on thetype of generator and PC equipment as well asanticipated customer loads.

25(3TA, /ndu5tria/ and Commercial Cogeneration, op. cit. t 1983.

It is important that such requirements be sensi-tive to the needs of both the utility and DSG cus-tom ers. The c ustom er should know exac tly wha tequipment is necessary so that costs can be pre-dicted with some certainty, and the utility shouldbe able to reduce design review approval timeand costs so that its power quality and operationscan be maintained. Knowing probable intercon-nection costs ahead of time may be as importantas the actual cost itself. zb

interconnec tion g uidelines should a lso stimu-late the exchange of informa tion be tween theutility and theDSG customer. Ideally, theDSG

ZGF.V. strnisa, et al., New York State Energy Research dnd De-velopment Administration,“Interconnection Requirements in NewYork State, ’’paper presented at Tenth Energy Technology Confer-ence, Washington, DC, 1983.



Ch. 6—The Impact of Dispersed Generation Technologies on Utility System Operations and Planning 171

customer shouId have access to necessary infor-mation regarding technical characteristics of theutility system’s power circuits, such as relay tol-erance settings, the short circuit capacity at thepoint of interconnection, and the speed and oper-ation of reclosers after detecting faults.

Utilities currently use two different philosophiesin preparing guidelines: they either prescribefunctiona l performa nce requirements that mustbe met by the interconnection equipment, ornonfunctional, equipment-specific requirements.For example, a utility might require equipmentto detec t when the DSG ge nerates po wer witha frequency outside a certain range (a functionalrequirement) or require specifically an under-frequency relay (technology-specific).

While a combined approach may be used bya utility in preparing its guidelines, research to

date suggests that performance-based standardsappear preferable since they allow cogeneratorsto meet functional c riteria rathe r than requiringthem to install particular types of equipment thatmight later be found unnecessary. New intercon-nection equipment is being introduced continu-ally with better performance and reduced cost.Perhaps in response to the fast pace of techno-logical change and improvements in the dispersedgeneration industry, many utilities are institutingfunction-ba sed interconnec tion g uide lines.

Ty p i c a l l y , u t i l i t i e s h a v e d i f f e r e n t r e q u i r e m e n t sfor different sized DSGs, with fewer and less strin-gent protective functions for the smaller genera-tors. While the precise definition of “smaller”versus “ large r” is not agreed upon by all utili-ties, usually, generators less than 20 kW are con-sidered sma ll DSGs and have fe wer functiona l re-quirements imposed on them than generatorslarger than 100 kW. The rationale behind thisscaling is, as mentioned earlier, to relate the levelof protection and cost of the interconnectionequipment to the size of the generator. In spiteof this, the per-kilowatt cost of even the least strin-gent interconnection requirements is much higherfor smaller generators (see figure 6-3.)

There a re othe r varia tions in the e xac t require-ments specified by utility guidelines (see box 6C).Even within a particular State, such as New York,requirements differ among utilities for pa rticuIar

kinds of equipment, compliance with specificelectrical codes, etc. 27 (see table 6-2 and box 6D).

In addition to these changes, there are the on-go ing efforts by standa rd-setting committees ofthe Institute of Electrical and Electronics Engineers(IEEE) and the National Electric Code (NEC) aswell as research sponsored by DOE, and the Elec-tric Power Research Institute (EPRI) to developnational “model” guidelines. While all of theseorganizations have published draft standards orsuggestions for model guidelines, none has as yetreleased final versions. 28One of the more influen-tial of such efforts is the prepa ra tion o f revisionsto the NEC. Working groups meet periodicallyto suggest revisions, and the overall committeepublishes the consensus every 3 years, with thenext revision planned for 1987. Once the revi-sions are published , they a re usually c irculatedto all local city, county, and other municipal bod-ies, which then incorporate the changes into theirown loc al b uilding and inspe c tion c od es. Thisproc ess of incorpo ration, however, may ta ke adecade or longer.

The delays inherent in this p roc ess wo rk aga instthe fast-changing nature of interconnection tech-nology. Even w ith the ad op tion of NEC or othernational standards, utilities are reluctant to ac-c ep t equipm ent which is unknown to their ow nexperience, even if it is in wide use in some otherutility’s service territory. For example, New YorkSta te Elec tric & Gas req uires tha t interco nnec tion

equipment m eet American Nat ional Stand ards in-stitute standard C37.90 (for power quality) butstipulates the utility must have already tested theequipment, surveyed users by telephone, andcollected successful performance histories i nother utilities .29

Another example is the req uirem ent tha t DSGcustome rs use “ utility-grade” relays, which c ost

.?71bi~,

2’%. Chalmers, “Status Report of Standards Development torPhotovoltalc Systems Utillty Interface, ’’paper presented at lnter-society Energy Conversion Engineering Conference, No. 849406,August 1984; IEEE Standards Coordinating Committee forPhotovol-(aIcs, “TerrestrialPhotovoltaic System Utillty Interface for Rcwdentlaland Intermediate Appllcatlons, ”Standard 929 (Draft), November1983; and D, CurtIce and J. B. Patton, /rtterconnectirrg DC EnergySystems: Responses t o Technica/ /ssues, o p . c i t . , 1 9 8 3 .

29F.V. Strnlsa, et al,, “InterconnectIon RequirementsIn New YorkState, ” op. cit., 1983,




more and have supposedly better reliability thanordinary commercial-grade relays. There is nogeneral agreement as to what relays are of which

grad e. For exam ple, Ce ntral Hudson Electric &Gas defines relays as “utility-grade” if the utilityhas had experience with it and can predict its per-formance.30As yet, how eve r, no utility ha s pub -lished any assessments linking reliability with thelevel of eq uipment grad e. Thus, the req uireme nt

of and definition of “utility-grade” equipmentmay be largely attributed to general utility conser-vatism towards equipment performance, rather

than towards specific groups of interconnectionapparatus.

Equipm ent g rade stipulations c an p resent a nawkward situation for DSG customers wishing tointerconnect. For example, a utility refuses to ap-prove an interconnection unless the eauipment

Wbid. has undergone prior safe ty inspe c tion’, yet the







Ch. 6—The Impact of Dispersed Generation Technologies on Utility System Operations and Planning “ 175

A number of value studies of incorporating so-lar energy generating sources into utility resourceplans have been performed on a variety of spe-cific utility systems since 1975.33 Typically, thesestudies analyze a base case (without solar tech-nolog ies) and then a case w ith solar. The va lueassigned to the solar energy is the cost differencebetween the two study cases.

These studies34 generally incorporate the fol-lowing step s in eva luating the value of DSGs ina utility’s resource plan. First, a base case analy-sis of an expansion plan without solar technol-ogy establishes a benchmark against which solartechnologies are evaluated. Next, a second caseis analyzed with solar te c hnolog ies in three step s:1 ) estima ting the po wer outp ut of the solar tech-nologies, 2) modification of the hourly loads bythe solar production to determine the residualhourly loads on the nonsolar technologies gen-eration, and 3) recalculating production costs andthe reliability impa c ts. Typic a lly, gene ration p lan-ning studies for the 20- to 30-year planning hori-zon do not use detailed, hourly data, but the in-termittent nature of solar energy requires this typeof rep resenta tion. The d ifferenc e in reliab ility be -tween the base case and the solar alternative canbe used to compute the solar technologies’ ca-pa c ity credit in the utility’ s ge neration plan. Asa final step in the process, the cost difference be-tween the cases with and without solar technol-og ies are exam ined to o bta in the single yea r sav-ings. Using the single year savings, the presentvalue of the total savings is accumuIated over theexpected lifetime of the solar facility under study.

The m ost impo rtant fa c tor affec ting the break-even energy cost is the utility’s present andplanned future generation mix, which determinesthe type a nd q uantity of fuel and c ap ac ity dis-placed. Evidence strongly suggests that while so-lar technologies may displace some conventionalproduction capacity, the greatest value of solarrests with the displacement of energy, i.e., fuelsavi rigs.

Key areas of future work include the develop-ment a nd va lida tion of m ode ls that a cc uratelycharacterize the dynamic behavior of solar tech-nologies. Capacity potential will be measured inpart by the effectiveness of solar technologies toparticipate in short-term load following process,i.e., loa d freq uenc y control.

Transmission Planning.—Electric tra nsmissionsystem s are stud ied in terms of ne twork ca pac -ity and reliability requirements. Criteria for siz-ing the transmission system vary from utility toutility; however, the basic purpose of all trans-mission system design studies is to establish whenand where new lines should b e a dd ed and atwhat voltage level.

A transmission plan consists of three majorcomponents: 1 ) a generation dispatch strategyand the projected load profile for the system are

used to determine the expected transmission lineloading levels over the planning period; 2) a min-imum cost transmission expansion plan for thehorizon yea r which meets the reliability c riteria ;and 3) and a “ through-time plan, ” i.e., the se-quence of changes in the transmission system intransition to the horizon year.35Key parametersfor comparing alternative expansion plans are thenumber of line additions required per unit of timeand the p resent w orth co st of those a dd itions.

Studies sponsored by EPRI36estimate transmis-sion “credits,” i.e., capital cost savings, associ-a ted with DSG siting c lose to load c ente rs of $66to $133/kW, for a va riety of transmission systemconfigurations. If more expensive undergroundcables are involved, the savings were estimatedto be a s high a s $250/kw. The simulat ions showe dthat an optimal DSG market penetration, fromthe point of view of transmission system planning,appeared to be about 20 percent of metropoli-tan loa d g rowth. Below or ab ove tha t level, thetransmission credits per kilowatt decreased.

Distribution Planning.–The effect of DSGs onthe d istribution system (typ ica lly 13 kilovo lts 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 EnergyResearch Institute, May 1984), SERI/TR-211 -2318

~~T. Fla I m and S. Hock, wind Energy Systems for E/ectric Ut;/i-ties: A Synthesis of’ \/a/ue Stud/es, op. cit., 1984.

31B ~ Ka u pang , Assessment of Distributed Wind po~$’er -$Ystems,,(Palo Alto, CA: Electric Power ResearchInstttute, February 1983),EPRI AP-2882.

16 Systems Contro[, Inc., /mpacf on Transmission Requirements

of Dispersed Storage and Generation (Palo Alto, CA: Electric PowerResearch Institute, December 1979), EPRI EM-1 192.



176 . New Electric Power Technologies: Problems and Prospects for the” 1990s

below) is determined by the deployment strat-egy of the equipment. Clusters of generatingequipment, irrespective of individual unit size,that are placed on feeders or in substations, af-fect the system very differently than small gener-ators distributed throughout the electric system.

In substations, the primary element for concernis the transformer. The addition o f DSGs has thepotential for changing significantly the operatingconditions of the transformer. Deferring addi-tional substation capacity is the desirable attrib-ute. For small additions of DSGs up to some min-imum level, no d eferral of t ransformer ca pa c ityresults because the substation is largely respon-sible for serving all the load. Above this minimumup to some maximum level, deferrals will result;above the maximum, additional transformer ca-pacity is required for the generator itself. In sum,the effect of deferral is captured by the particu-

lar sizing policy of the utility, but DSGs can de-fer the add ition of both transformer and feed ercapacity .37

The addition of DSGs to the substation has noinfluence on distribution system losses, but plac-ing g enerating equipment on the feeder ca n re-duce losses because the production will be closerto the load. When generation is placed closer tothe load, less power is transported through thesystem, thereby reducing losses. DSG installationmust be well planned so that existing circuits arenot a limitation. Aga in, the a mount of loss red uc -

tion depends on the utility.Excessive voltage fluctuations offer greater po-

tent ial conc ern when DSGs a re p lac ed in the d is-tribution system, especially since they are nearerthe loads. Under wind gust or cloud cover condi-tions, solar technologies can cause large voltageswings due to c urrent surges from the elec tricalconverter. Voltage regulators and tap-changingtransformers in the power system are very slowto respond (on the order of a minute) resultingin no influence on the short-term problem.

Electric Power Systems OperationsOverall management of power system opera-

tion consist of two phases—operation planning

JZlb id

and real-time operation. Operation planning con-sists of the scheduling of generation and trans-mission facilities for use during a 1- to 3-daype riod; it is the so c alled “ red ispa tc h p rob lem.”Real-time operation involves the on-line manage-ment a nd c ontrol of all fac ities on a sec ond -to-second basis. In most utilities, daily operationsare direc ted from a ce ntral c ontrol center.38

Operations Planning.–A strategy is formulatedto deploy the system’s available resources to meetthe anticipated load of the next day economicallyand reliably. First a load forecast of hourly loadsand load ramp rates (minute to minute changesin load) is made to determine the generation andtransmission req uirem ents. Sub seq uen tly, a “ unitcommitment” strategy is determined based onavailable facilities as determined by any sched-uled or unscheduled down-time of equipment.The resulting p lan is the guideline to daily op er-ations.39

Real-Time Operations.— Utilities must contin-ually adjust electricity production to follow theconstantly changing electric demand. Productionand demand are maintained in balance by thecombined actions of speed governors on individ-ual generating units (frequency regulation) anda closed loop automatic generation control sys-tem which performs load frequency control (reg-ulation) and economic dispatch functions.40Inaddition, the instantaneous balance of load andde ma nd is known a s stability. A c onfigurat ion is

chosen which assures a stable system under acredible list of potential system componentfailures (faults, equipment trips, etc.).

Automatic Generation Control.–There remainsmuch uncertainty and debate over what DSGpenetration level will negatively affect utility sys-tem pe rforma nc e. An earlier OTA rep ort41 dis-cusses concerns about the effects of a highpenetration of DSGs. A common definition of“ high pene tration” is a DSG c ap ac ity over 25 per-cent of the capacity of the particuIar distribution

JET. W. Reddoch( et al., “Strategies for Minimizing OperationalImpacts of Large Wind Turbine Arrays on Automatic GenerationControl 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 q 1 7 7

feeder or over 25 percent of overall utility sys-tem capacity.

There are no ut ilities tod ay ap proac hing thisde finition of high p enetration of DSG e quipm enton p articula r d istribution feeders—even the util-ities with the most DSG installations have lessthan one-tenth of 1 percent penetration. Yet, formost utilities, the penetration level is increasingand some, such as Houston Lighting & Power,are planning for the possibility of penetrations ashigh as 30 percent by the year 2000.42One util-ity in Hawaii currently has 10 percent DSGpene tration (see box 6E).

The e ffec t DSGs have o n a n elec tric a l system ’sarea control error (ACE) is of pa rticular interest.ACE measures a combination of frequency devi-ation a nd net tie-line p ower flow (see b ox 6A).North American utilities have agreed on certain

minimum standards for ACE values: ACE musteq ual zero at least onc e a nd m ust not va ry be-yond a certain range during each 10-minute in-terval . 43

Analysts measuring utility system performancewith high penetrations of DSGs must measure theincrease in ACE caused by the DSGs, rather thanby other influences unrelated to DSGs. Thesemeasureme nts are d ifficult to ma ke in the field,since ACE often results from the demand shiftscaused by fast-changing, unpredictable condi-tions suc h a s a quickly moving thund erstorm, afast drop in temperature, or a drop in power com-ing from a neighboring utility across a high-voltage tie-line.

Most researchers agree that at the present lowlevels and continuing up to at least 5 percent ofDSG pe netra tion, the re a re no ill effec ts on sys-tem operations as measured by ACE. However,there is no general agreement on what increasein pene tration of DSGs be yond 5 pe rc ent will in-crease ACE.

4ZHenry Vad ie, Houston Lighting & Power, OTA workshop onCost and Performance of New Generating Technologies, June 1984.

43M, G. T h o m a s , e t a l . , A r i z o n a S t a t e U n i v e r s i t y,Dfdft R e p o r t : The Effect of Photovoltaic Systems on Utility Operations,contractorreport (Albuquerque, NM:Sandia National Laborator ies , February1 9 8 4 ) , SAND84-7000.

Curtice and Patton 44 used data on wind gener-ators and estimated ACE for four different gener-ator pe netrat ion levels. Their results indicated tha tACE increases only 1 percent when total windcapacity is at 20 percent of the overall utility sys-tem. When penetration reaches 50 percent, ACEincreases to 10 percent. While these changes inACE were not significant, the authors noted, with5 percent penetration, wind output variations

, . . did not cause a significant change in thecontrol process. . . . However, increased energyflow over the tie-lines connected to neighboringutilities compensated for generator/load mis-ma tche s oc curring too fast for the utility’s gener-ators to follow. If the utility’s control process isdesigned to minimize tie-line flow deviations,. . . then generator/load mismatches show up asincreased ACE and decreased system per-formance.

These results suggest tha t, a lthough mea suredACE wa s not la rge, there is a p ote ntial prob lemwith installing wind machines. / f there is a highenough fluctuation in wind speed,if there is ahigh proportion of wind generation on a particu-lar feed er, and if the utility optimizes its controlproc ed ures for minimizing t ie-line va ria tions (anelectric industry standard), a decrease in systempe rformanc e c ould oc cur. Moreover, there is apotential for overloading the distribution feeder.(Other research notes the need to develop alter-native generation control algorithms to better ac-co mmo da te DSGS.45)

A Sandia Laboratories study 46 also supports theview that DSGs have a limited effec t 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 Oper-ate and Control WindTu;bine Arrays in Utility Systems, ”/EEE Trans- action on Power Apparatus and Systems,IEEE Summer Power Meet-ing, Seattle, WA, 1984; F. S. Ma and D. H.Curtice, ‘ ‘DistributionPlanning and Operations With Intermittent Power Production, ”/EEETransactions on Power Apparatus and Systems,August 1982; Sys-tems Control, Inc.,The Effect of Distributed Power Systems on Cus- tomer Service Re/iabi/ity, contractor report (Palo Alto, CA: ElectricPower Research Institute, August 1982), No. EPRI 3L-2549; and T.W. Reddoch, et al., “Strategies for Minimizing Operational Impactsof Large Wind Turbine Arrays on Automatic Generation Control

Systems, ” op. cit., May 1982. Another recent study examined howto efficiently operate and control wind turbine arrays; see Stevensand Key, op. cit., 1984.

*Thomas, et al., op. cit., 1984, SAND84-7000; and M. G. Thomasand G. J. Jones, Draft Report: Grid-Connected PV Systems: How and Where They Fit (Albuquerque, NM:Sandia National Labora-tories, 1984).




pe rformanc e. The resea rchers mod eled p hotovol-taic (PV) arrays on a long rural distribution linewith 30 percent of the homes on the line usingsmall (1 O to 20 kW) PVs. In order to observe anysignificant increase in ACE, “a solid cloud coverwould engulf all 10 miles of the distribution feedersimultaneously ma sking eve ry PV home . . . andthis scenario would be repeated every 6 minutes. ”The study maintains this is a very unlikely situa-tion and in any event represents the worst possi-ble condition for PV interconnection equipment.

The sudd en a nd unpred ic ted loss of a largegenerator can drastically unbalance the supplysystem of a utility, espec ially when this gene ra-tor represents a large proportion of the entire sys-

tem c ap ac ity. Two mode lers have stud ied sucha situation:

Researchers from Arizona State University sim-ulat ed the effec ts of larger PVs with a three re-gion model (the regions are the service areas ofArizona Pub lic Service and The Salt River Projec tas well as a third region representing the re-mainder of the Western United States and Cana-dian grid). A PV generator was placed in eacharea and its output changed in response to pre-determined cloud movement and wind velocity.Five different-sized PVs were used, ranging from50 to 250 MW. The researchers found no signifi-cant 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 q 1 7 9

of total system capacity or less than 5 percent ofany particular distribution feeder; and 2) a com-bination of smaller, home-sized PVs was less than50 percent of total system capacity or particularfeeders. 47

Dynamics and Transient Stability.—Most con-

cerns with stability have focused on wind tur-bines. The spe c ial c ha rac teristics of w ind t urbinegenerators which cause their dynamic behaviorto be different from that of conventional units canbe traced to the large turbine rotor diameter andslow turbine speed necessary to capture sufficientquantities of power from the relatively low powerde nsity of the w ind. The e lec tric al gene ra tors for

“R. M. Belt, ‘‘Ut]lityScale AppJlcatlon of WInci Turbines, ” pa-per pre~ented at V1’inter Power,Meetlng of the IEEE, No, CH 1664,February 1981,

large wind turbine ap plic ations are g enerally fouror six pole designs and a high ratio gear box isessential to step up the low turbine speed to thesynchronous spe ed of the g enerato r (],800 or1,200 rpm). The h igh ratio g ea r box causes windturbine drive trains to have torsional propertieswhich are not characteristic of conventional tur-bine generators. But the dynamics of large windturbines are compatible with conventional powersystems and pose no apparent barrier to their ap-plica tion. The sam e c ould b e sa id of the t ransientsta bility p roperties of w ind turbines during elec -trical o r mec hanica l disturba nce s.48

J8E N H n ric hsen a ncj p,J. NOlan, ~ynamfc+ Ot S//lg/e- ,Ind A’fu/f/-.Unit Wind Energy Con~erslon Plants Sui>p/}’\ng Electric UtIIIt}/ S}s-

f e r n s , c o n t r a c t o r r e p o r t , U S , D e p a r t m e n tof E n e r g y (W’ashtngtonf

D C : N a t i o n a l Te c h n i c a l I n f o r m a t i o nSer \ l ce , A u g u s t 1 9 8 1 ) , D O E /E T / 2 0 4 6 6 - 7 8 / 1 .



Chapter 7

Regional DifferencesAffecting Technology Choices

for the 1990s



CONTENTSPage

Introduction . . . . . . . . . . . . . . . . . . . . . . . . .183overview . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 183Definition of Reg ions . . . . . . . . . . . . . . . . . . . 183

Regional Issues Defined byElec tricity De ma nd . . . . . . . . . . . . . . . . . . . . 183

The Role o f Unc erta inty in Reg iona lDemand Forecasts. . . . . . . . . . . . . . . . . . . . 183

opportunities for Consumer SideAlternatives to New Capacity . . . . . . . . . . . 188

Regional Economic and RegulatoryCharacteristics AffectingTec hno log y Choice s . . . . . . . . . . . . . . . . . . 190

Rate Regulation Issues . . . . . . . . . . . . . . . . . . 190Licensing and Permitting of

Small-Sc a le Systems . . . . . . . . . . . . . . . . . . . 192Key Characteristics of Regional Electricity

Supply Systems . . . . . . . . . . . . . . . . . . . . . 194Present and Projected Fuel Reliance . . . . . . . 194Opportunities for Plant Betterment and

Life Extension. . . . . . . . . . . . . . . . . . . . . . . . 195Supply Enhancements From Interregional

and Intra reg iona l Pow er Trdnsfers . . . . . . . 197Prospects for Nonutility Generation. . . . . . . . 198

Reg ional Fuel and Tec hnolog y Relianc eProfiles . . . . . . . . . . . . . . . . . . . . . . . . . . . ..203

East Central Area Reliability CoordinationAgreement (ECAR) . . . . . . . .............203

Electric Reliability Council of Texas( E R C O T ) . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 0 4

Mid-Atlantic Area Council (MAAC) . .......204Mid-America Interpoo l Netwo rk (MAIN) ....205Mid-Continent AreaPower POOI

(MAPP-U.S . ) . . . . . . . . . . . . . . . . . . . . . . . . 206Northeast Power Coordinating Council

(NPCC-U.S.) . . . . . . ...................207Southeastern Electric Reliability Council

( S E R C ) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 0 8Southwest Power Pool (SAP) . . . . . . . . . . . . . .209Western Systems Coordinating Council

( W sc c - u . s. ) . . . . . . . . . . . . . . . . . . .. . . . . 2 1 0Alaska Systems Coordinating Council

(ASCC) . . . . . . . . . . . . . . . . . . . . . ........211Hawaii . . . , . . . . . . . . . . . . . . . . . . . . . . . . . . . 212

Summary of Major Regional Issues . .........214Demand Uncertainty. . . .................214Present and Projected Fuel Reliance . ...,..214

Page Plant Life Extension. . . ..................215Other Key Variables . . . . . . . . . . . . . . . . . . . . 215

Table 7-1.7-2.7-3.

7-4.

7-5.

7-6.

7-7.

List of TablesN o . Page Utility Type, By Region . ..............188Average Fuel Prices, By Region . .......190Average Residential Commercial andIndustria l Elec tric ity Pric es,By Census Region . ..................191Selected Characteristics of RegionalElectric Utility Generation Systems. .. ...193Life Extension Resource Base: Age ofFossil-Fired Steam Plants, By Region ....196Ac tua l and Expec ted Pow er Transfers,1983-1993 . . . . . . . . . . . . . . . . . . . . . . . . . . 199Estimated Maximum IndustrialCogeneration Potential Availableas of 1980 . . . . . . . . . . . . . . . . . . . .. ...200


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 . . . . ........184Map of U.S. Census Regions. . .........1851993 Regional Capacity Shortfalls orSurplus Relative to 20 Percent ReserveMargin Given Varying National DemandGrowth Rates and Current UtilityCapacity Projections . ................186Sample Load Curve for a Utility in theECAR Region on a Day in January ... ...l89Regional Utility Capacity by Fuel Use,1984 and 1993 .. . . . . . . . . . . . . . . . . . . . .195Regional Utility Generation by Fuel Use,1984 and 1993 . . . . . . . . . . . . . . . . .. ....196Historical Transmission Loading

Patterns in MAAC . ..................197Interregional and Intraregional PowerTransfer Capabilities . ................198Major U.S. Hydrothermal Resources ....200Average Annual Wind Power . .........201Average Annual Solar Radiation . .......202Geological Formations PotentiallyAppropriate for Compressed AirEnergy Storage ., . ...................202



Chapter 7

Regional Differences AffectingTechnology Choices for the 1990s

INTRODUCTIONOverview

The inherent unc erta inty assoc iated with e sti-mating future electricity demand is one of themost important factors affecting utility choicesamong electricity supply options. Demand growthrates differ dramatically within and among re-gions, and unanticipated changes in these ratescan substantially affect both overall system relia-bility and the need for new g enerating ca pa city.Other factors that vary by region also strongly in-

fluence utility tec hnolog y cho ices. This chapterfocuses on these differences, quantifies themwhere possible, and speculates on their short-and long-term influence.

Among these other differences are plant life ex-tension opportunities (defined by the age andtype of existing generating facilities) and presentand projected fuel dependence, which generallyestablishes regional benchmarks for technologycost comparisons. Other variables discussed inthis chap ter include op po rtunities for

REGIONAL ISSUESThe Role of Uncertainty

power transfers; potential supply contributionsfrom load management, conservation, and co-generation; constraints imposed by natural re-source availability; and differences in regionalreg ulato ry and ec onom ic e nvironme nts.

Definition of Regions

While regions can be defined by manycharacteristics—e. .g., demographics, economicmake-up, census divisions, and/or physicalgeography—the regions used most often in thischapter will be those of the electric reliabilityc ounc ils. There a re nine regional co unc ils in theUnited Sta tes and o ne na tional group : the NorthAmerican Electric reliability Council (N ERC). Fig-ure 7- I summarizes what the councils do andshows which areas of the country they cover. Fig-ure 7-2 illustrates how these regions comparewith census divisions, because occasionally datawill be presented in this format as well.

increased

DEFINED BY ELECTRICITY DEMANDin

Regional Demand Forecasts

As noted in chapter 3, the national average an-nual rate of growth in electricity demand fluctu-ated greatly through the 1970s. Growth ratepredictions have similarly varied. For example,in 1975, NERC expected demand growth to sta-bilize at 6.9 percent per year through 1984; asof early 1984, the council expected growththrough 1993 to average 2.5 percent, ’ Other esti-

‘NorthAmerican Electric Reliability Council (NERC), 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 fig-ure 3-4 in chapter 3). As figure 7-3 illustrates,sma ll chang es in expec ted growth lead to sub-stant ial d ifferences in c ap ac ity req uirements tomeet overall demand.

Wide regional variations in demand growthrates have bee n and c ontinue to be co mmo n.NERC 1984 projections for average annual de-mand growth in the next dec ad e range from 1.3

(MAAC) to 4.0 pe rcent (ERCOT). Comparable dis-parities also oc cur within reg ions. For examp le,within WSCC, which is divided into four sub-regions, the California-Southern Nevada Pow erArea expects dem and growth of 1.9 percent,

183

38 -743 0 - 85 - 7




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 coor-dination between regional utility systems. The nine regional organizations listed below provide similar services to their member utilltleSeveral 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 AgreementElectric Reliability Council of TexasMid-Atlantic Area CouncilMid-America Interpool NetworkMid-continent Area Power PoolNortheast Power Coordinating CouncilSoutheastern Electric Reliability CouncilSouthwest Power PoolWestern Systems Coordinating Council





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 beaccounted 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 JeffreySkeerof the Office of Coal and Electricity Policy, U.S. Department ofEnergy projects regional reserve margins through 2000 under twodifferent national demand growth scenarios. The first scenario as-sumes growth at 2.6 percent through 1990 and 2.4 percent from199o through 2000. The second, higher growth scenario assumes3.3 percent growth through 1990 and 2.9 percent growth from 1990to 2000, The utility capacity projections used in Herod andSkeer’sanalysis exclude: 1 ) coal units planned but not yet under construc-tion as of the end of 1983, and 2) nuclear units only one-third com-plete as of that date. As would be expected, under these assump-tions several regions show reserve margin problems earlier thanindicated in figure 7-3. In particular, both ERCOT and MAPP wouldfall below 20 percent in the mid to late 1980s, highlighting theseregions’ dependence on planned additions. All regions would fallbelow 20 percent by 1994 under the high growth scenario. For fur-ther information, see J. Steven Herod and JeffreySkeer, “A Lookat National and Regional Electric Supply Needs, ’’presented at the12th 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/Y andDemand for tk Contiguous United States 1984-1993 (Washington,DC: DOE, June 1984.




Table 7-1.-Utility Type, By Region

Percent totalPercent total electricity sales to

Number of electricity sales to ultimate customerspublicly ultimate c ustomers from publicly ownedowned from IOUS, by census utilities, by censusutilities region, 1983 region,- 1983

43491652171521381135255

984

9192906481368170 62 76

98103619641930 39 24

cent m argin ma y not c om pletely assure systemreliability in those systems which place heavy em-phasis on large plants, Whether or not this willemerge as an issue remains unclear; as of 1980,ECAR, ERCOT, MAAC, and SERC were the onlyregions with more than 15 percent of total ca-pacity in units equaling or exceeding 500 MW;of these regions, ERCOT had the highestpercentage–25 percent. G

Opportunities for Consumer SideAlternatives to New Capacity

Conservation

Conservation can offer a cost effective alterna-tive to a significant quantity of new capacity con-struction, and the National Association of Regu-latory Utility Commissioners (NARUC) is activelyencouraging utilities across the country to includeconservation in their resource plans. From a util-ity’s perspective, one of the major issues associ-ated with relying on this “consumer side” sup-ply strat egy is that imp lementa tion depe nds onac tions outside the utility’s d irec t c ontrol. Whiledifferent pricing strategies have been used to en-courag e c onservat ion, custome r responses arenot entirely predictable. Utilities are also con-cerned a bo ut conservation efforts which mightreduce off-peak demand without affecting the

G@rlVecf f~om generating plant database prepared for OTA inJanuary 1985 by E.H. Pechan & Associates, Inc.

peak, thereby decreasing system load factor with-out decreasing the need for new capacity.

The ene rgy conservat ion resource app ea rsquite large, although e stimates of the po tentialenergy savings and capacity deferrals vary widely.OTA’ S a ssessme nt of conserva tion opportunitiesin specific energy-use categories can be foundin several previous studies. ’

Load Management

NARUC is also encouraging U.S. utilities toconsider load management in their resourceplans, Load shape patterns define the opportu-

nities for load management, As figure 7-4 illus-trates, these patterns differ among end-use sec-tors, with industrial loads generally more uniformthan commercial or residential ones. Load shapevariations between utility systems within NERCregions are as ma rked as the variations amo ngreg ions. The load ma nag ement o pp ortunitieswithin a given region are de fined by m any fac -tors, including system reserve margins, expectedload factors, customer profiles, the degree towhich a utility generates its own power or pur-chases it from other systems, and public utilitycommission policies.

7U. S. Congress, Office of Technology Assessment(OTA), Energy Efficiency of Buildings in Cities (Washington, DC: U.S. Governmentprinting Office (GPO), March 1982); OTA,Industrial Energy Use (Washington, DC: GPO, June 1983); OTA,U.S. Vu/nerabi/ity to anOil Import Curtailment: The Oil Replacement Capability (Wash-ington, DC: GPO, September 1984.)



Ch. 7—Regiona/ Differences Affecting Technology Choices for the 1990s q 189

Figure 7.4.— Sample Load Curve for a Utility in theECAR Region on a Day in January

100

90

80

70

60

50

4 8 12 16 20Hour of the day

IResidential

Commercial

Industrial

One of the key operational objectives behindload management i s to inc rease sys tem loadfactor–the ratio of average load to total load overa specified time interval.I n the united States, re-gions with high load factors are generally charac-terized by moderate, stable climates and/or heavyindustrial loads, while low load factors usually areindicative of high seasonal peaks in electricity useand/or little heavy industry.8

In all regions, there appear to be substantial op-portunities for load management; these opportu-nities are discussed in detail in chapter 5. In par-ticular, the residential market remains largelyuntapped, making areas characterized by highpopulation density or high population growth at-tractive candidates (see table 5-I ) if the obstaclesdiscussed in chapter 5 can be overcome. Oppor-tunities also remain in the commercial and indus-trial sectors.

In the long run, fuel reliance patterns may makeload management an unattractive option in someregions if it defers replacement of costly oil- orgas-fired units.9 This ma y be e spec ially importantin oil- or gas-dependent areas such as ERCOT,MAAC, NPCC, SPP, the Florida subregion inSERC, and two subregions of WSCC–the Ca!ifornia-Southern Nevada Power Area and the ArizonaNew Mexico Power Area. From the consumer’sstandpoint, the deciding factor regarding thedesirab ility of such d eferrals will be the ultima teimpact on electricity bills—a function of both

electricity rates and electricity use. For utilities,the desirability of such deferrals will be heavilyinfluenc ed by their c ost relative to other elec tri-city supply options.

Municipal utilities (munies) and rural cooper-atives (coops), most of which buy the bulk of theirpower from other systems, are already activelypursuing load management to both improve loadfactor and minimize the cost of purchased power.These system s ac c ount ed for one -third o f a ll theload control points in 1983. Munies and coopsfacing 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; rice- ton, Nj: NERC, 1984).

gjames j, Mulvaney, planning and Evaluation Division, ElectricPower 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 DistillateRegion oi la oi lband year Coal (#6) (#2) GasECAR:

1983 ......., . 168.1

1984 . . . . . . . . . 165.9ERCOT:1983 . . . . . . . . . 164.31984 . . . . . . . . . 156.5

MAAC:1983 . . . . . . . . . 158.11984 . . . . . . . . . 166.3

MAIN:1983 . . . . . . . . . 186.71984. . . . . . . . . 180.3

MAPP (U.S.):1983. . . . . . . . . 128.81984. . . . . . . . . 132.1

NPCC (U.S.):1983. . . . . . . . . 194.81984. . . . . . . . . 192.5

SERC:

1983. . . . . . . . . 191.81984. . . . . . . . . 191.9SPP:

1983. . . . , . . . . 166.31984. . . . . . . . . 172.6

WSCC(u.s):1983. . . . . . . . . 109.41984. . . . . . . . . 112.6

451.9460.4503.7567.3

464.0488.0

605.6613.1

419.5453.0

446.8476.0

427.3463.2

373.8410.9

602.5620.9

625.6628.9517.9601.5

602.5614.6

621.4629.9

596.9603.9

635.4637.7

621.0608.4

615.3625.3

619.0616.2

426.9419.8362.3358.0

405.4434.1

506.4474.8

365.9363.9

395.9398.1

261.3332.6

251.3254.6

500.5502.9

aMost of the oiI burned by utilities (e.g., ~ percent) k residual oil; it is usuallYburned in base and intermediate load boilers.

bDistillate OiI IS burned in peaking units (i.e., combustion turbines and dieselengines).

SOURCE: Data generated for OTA by Energy Information Administration, Elec-tric Power Division, U.S. Department of Energy, November 1964.

REGIONAL ECONOMIC AND REGULATORY CHARACTERISTICSAFFECTING TECHNOLOGY CHOICES

Rate Regulation Issues

Avoided Cost

Potential markets for many new generatingtechnologies depend on the buy-back rates be-ing offered by utilities under the avoided costguidelines of the Public Utility Regulatory PoliciesAct (PURPA). Regional generalizations aboutthese rates are complicated by the substantial var-

iations within regions as well as the continuedchanges in rate offerings, primarily due to fluc-tuating p rojec tions of the c osts of a voided fueluse,

Sinc e fuel c osts are a c ritica l fac tor in the ec o-nomic s of te c hnology a lternatives, reg ional ave r-

ag es are p resented in tab le 7-2. As this table il-lustrates, fuel costs are particularly high in NPCCand WSCC, two areas within which avo ided c ostrates are also high relative to the rest of the coun-try. In general, the highest avoided energy rates(as of October 1984) were offered in NPCC,WSCC, ERCOT, and MAAC, with utilities in Statesin each of these regions offering rates equal toor above 6 cents/kWh. With the exception of

Florida (SERC), States within these four regionswere also the ones with utilities offering the high-est cap ac ity cred its.10

IOFrom data presented in “’States’Cogeneration Rate-Setting Un-der 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




While avoided cost rates could fall in the nearterm (e.g., due to de c lining oil and ga s prices)there is considerable disagreement on this issue. 11

As a policy decision to encourage cogenerationand new technologies, some State regulatoryagencies (e. g., New York, New Jersey, and Iowa)

are deliberately establishing or encouraging highbuy-ba ck rates .12 These a ct ions have often beenthe imp etus for litiga tion; the Iowa rat e w as be -ing challenged in court at the time this reportwent to press, while the New York rate had justavoided further challenge when, based on juris-dictiona l issues, the Supreme Court dec lined toreview a lower court’s decision upholding therate.

Construction Work in-ProgressState policies towards construction work in-

progress (CWIP) for new generating facilities areanother factor which may strongly influence tech-nology choices. Allowing CWIP in the ratebasehelps avert the sudden rate shocks which can oc-cur when major new plants come into operation;this assumes added importance in areas such asthe New England and Mid-Atlantic States (seetable 7-3) where electricity rates are already highrelative to the rest of the country. Allowing CWIPin the ratebase can also make it easier for utili-ties to ob tain financing for new c onstruc tion proj-ects, since this reduces the perceived and actualfinancial risks associated with new construction.

Conceivably, such a policy could encourage alltypes of technology, but industry observers sug-gest it is most likely to favor conventionaltechnologies—systems with which utilities are themost familiar and comfortable (see chapter 3 fora more detailed discussion).

Handling CWIP in retail rates is a State deci-sion; rate policies are highly variable both be-tween States and within the same States over

I IOTA workshop on Economicand Regu Iatory Issues AffectingNew Generating Technologies, February 1985.

I Zsome industry observers also note that severaluti Iity commis-

sions are beginning to react against high avoided cost rates andmay move to set artificially low rates in an effort to protect theirratepayers. Other States such as California are stepping back fromlong-term Ievelized rates and returning to annual ones. Source: AllenClapp, Director of Financial and Economic Analysis, North Caro-lina Alternative Energy Corp., personal communication, Novem-ber 1984,

time.13As of 1981, about 50 percent of all Stateregulatory agencies allowed some form of CWIPin the ratebase. 14 The Fed era l Energy Reg ulatoryCommission (FERC), which controls wholesalerates, allows 50 percent of the funds used for con-struction to be treated as CWIP.

Licensing and Permitting ofSmall-Scale Systems

Because the economics of small or under-c ap italized projects are p artic ularly vulnerab le tounanticipa ted c osts or de lays, reg ulato ry p olic iesaffec ting fac iIity siting c an also have a strong im-pact on technology deployment, especially whenthird -pa rty produc ers are involved . To d a te, mo stof the experience in licensing and permittingsmall-scale alternative (especially renewable)technology projects has been in California. Al-

though Ca lifornia’ s environme ntal review proc -ess is unique and perhaps the most rigorous inthe c ountry, some ge neral trends ap pe ar to beemerging. Of these, the most important is thatnew, small-scale (i.e., less than 50 MW) technol-ogies are not immune to controversy and oppo-sition. While their impacts tend to be localized,concerns about them have in some cases led tolengthy and expensive environmental review,with the review costs bo rne b y the de velope rs.In other ca ses, the same types of p rojec ts havemet no local resistance at all (see box 76).

These expe rienc es sugg est tha t implem enta tionof small-scale solar, geothermal, and wind tech-nologies will be substantially influenced by lo-cal regulatory policies, the most influential be-ing local zoning ordinances, land use permits,and public health standards. In areas where aland intensive p rojec t is prop osed and sensitivehab itat is affec ted , State and Fed eral law s ma yassume a dominant role, but these effects will bemore site than region specific.

While siting of alternative technologies can beexpected to be carefully monitored, especiallyin Sta tes with strongly protec tive environmenta l

13For examp~, the Texas public Utility Commissionallowed Cwlp

in the rate base in 1980, but a subsequent 1984 ruling excluded it.14Energy I n f o r m a t i o n Admin i s t r a t ion , /fT1/JdCtS Of ~/flaf7C/c3/ CO~-

s(raints on the E/ectric UtI/ity /rtdustry (Washington, DC: Decem-ber 1981), DOE/EIA-0311.



Ch. 7—Regional Differences Affecting Technology Choices for the 1990s “ 193

q

q

q

q

q

q

q

.

.

q

q

q

q

q

q

q

q

q

q

q

q

m

q

.

q

,

,

*

q



KEY CHARACTERISTICS OF REGIONALELECTRICITY SUPPLY SYSTEMS

Present and Projected Fuel Reliance

Regional fuel and technology reliance estab-lish the benchmarks for technology cost compar-

isons. While most systems with substantial oil andgas capacity are expected to decrease use of thesefuels over the next decade, reliance on premiumfuels is expected to be strong enough in somearea s, i.e., ERCOT, MAAC, NPCC, a nd som e sub -regions of SERC, SPP, and WSCC, that the eco-nomics of competing technologies will remain

particularly sensitive to the price and availabil-ity of oil and gas (see figures 7-5 and 7-6, and ta-ble 7-2). 15 As discussed in the section on demanduncertainty, this sensitivity will be heightened ifthere are significant changes in actual demand

1 sThese fuel reliance projections are from N ERC,E/ectric powerSupp/y and Demand, 1984-1993, op. cit., 1984; and fromNERC,14th Annual Review,op. cit., 1984

The reader should note that all of the 1984 figures cited fromthese two NERC documents are projections made by the reliabil-ity councils in early 1984 (i. e., January-April).





IM q New Electric Power Technologies: Problems and Prospects for the 1990s

Figure 7-6.– Regional Utility Generation by Fuel Use, 1984 and 1993

s

I




Supply Enhancements FromInterregional and Intraregional

Power Transfers

The am ount and importanc e of interreg ionaland intra regional power transfers has increased

dram atically over the p ast four decad es. Whilesuc h transfers historic ally have been used to in-crease overall system reliability (i. e., emergencytransfers to support energy-deficient areas dur-ing emergencies), the more recent emphasis hasbeen on economy transfers which displace highcost, fossil fuel generation with cheaper electri-c ity from ne ighb oring systems. This trend ha s ledmany transmission systems to be consistentlyoperated at or near maximum secure loadinglevels. In systems throughout the country, highloading levels are now raising concern about im-pacts on overall system reliability. Related phys-ical transmission limits are curtailing economicallyattractive exchanges into many oil- and gas-de-pendent regions.16

The situation in MAAC, where considerableamounts of energy are imported from ECAR andSERC, highlights these growing problems. In1982, MAAC’ s mo st limiting bulk pow er fac ilitieswere loa ded to full cap ac ity 40 perce nt of thetime; 1 year later, this climbed to 70 percent. Intha t sam e ye ar (1 983), the system wa s used at 90percent of rated c ap ac ity almost 95 perc ent ofthe time 17 (see figure 7-7). When systems are used

at this intensity, their ab ility to respond to u nex-pected, severe disturbances is reduced, therebyincreasing the risk of service interruption.

Rather than increasing reliability through re-dund anc y, i.e., building ne w po wer lines, utili-ties are respond ing by d eve loping m ore sop his-ticated protective relaying schemes and operatingproc ed ures. Som e e ngineers argue that the netresult of this new trend may be increased loadshedding, indicating acceptance of increased riskof customer service interruptions (perhaps atpreselected sites) when it results in net economicgain. 18 A combination of factors probably under-

I GN ERC, 14(II Anrtua/ Review, op. cit,, 1984;and Energy I nfor-mat]on Administration,/rrteruti/ity Elu)k Power Transactmrrs (Wash-ington, DC: U.S. Departmentof Energy, October 1983),DOE/EIA-0418.

I ZN E RC, 74th A~n~a/ Review, op. cit. , 1984.‘81 bid.

I20

t -

1I

10 “

0 I 1 1 I I I I I I q

0 10 20 30 40 50 60 70 80 90 100

Percent loading of most l imit ing bulk power system faci l i t ies

lies this new trend, including anticipation of con-tinued escalation of construction costs, interestrates, and fuel costs, as well as public oppositionto (and the regulatory complexity of) buildingnew plants or new transmission lines .19

Figure 7-8 summarizes power transfer capabil-ities among regions; table 7-6 shows expected netimport/export levels by region through 1993(these a re relatively long -term “ firm c ap ac ity” ex-changes set by contract; economy transfers arefar more variable and predictions regarding theirregional levels are not included). In general, ifdemand growth follows present predictions andcurrent construction plans are implemented, util-ities with large amounts of coal-fired generationprobably will continue to be net exporters ofpower, while systems trying to reduce use ofexpensive-to-operate oil and gas units will be netpurchasers of cheaper power–if they have ac-cess to it. However, it is unlikely that power trans-fers will be a substantial source of alternative ca-pacity in many NERC regions due to the heavyuse of existing transmission capacity, the limited




frc

(t)

Figure 7-8.—lnterregional and Intraregional Power Transfer Capabilities

q Total amount of power that can be transferredin a reliable manner.

“ q With a specific operating procedurein effect.

( + ) No significant transmission limit at this level.

number of new lines scheduled for operationwithin the next decade, and the long lead timesassociated with siting additional lines. The fewexceptions are discussed in the regional profiles.

Prospects for Nonutility Generation

CogenerationA 1983 OTA assessment estimated the techni-

cal cogeneration potential in the United Statesby the year 2000 at 200,000 MW in the indus-

trial sector and 3,000 to 5,000 MW in the com-mercial, agricultural, and residential sectors.Ac tual imp lementa tion is expecte d to be co n-siderably less, dep end ing on a broad rang e o feconomic and institutional considerations.20Forexample, if a 7 percent rate of return after infla-tion is used as the c ut-off po int for ac cep tableproject economics a 1984 study prepared for



Ch. 7—Regional Differences Affecting Technology Choices for the 1990s q 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 inMW )Region be net exporter Low High be net importer Low HighECAR . . . . . . . . . . . 1984-92 270 3,938 1993 175 178

summer 1992 summer 1994 winter 1993 summer 1993ERCOT . . . . . . . . . 0 0 1984-93 582 709

winter 1986 winter 1989summer 1987

IvIAAC . . . . . . . . . . 0 0 1984-93 107 1,582winter/ winter/

summer 1993 summer 1984MAIN . . . . . . . . . . . 1985-93 65 536 1984 42 462

summer 1993 winter 1989 winter 1984 summer 1984MAPP (U. S.) . . . . . 1984-92 354 658 1984-93 327 556

winters winter 1984 winter 1986 summers summer 1987 summer 1993NPCC (U. S.) . . . . . Winters of 1991, 81 101 1984-93 77 1,747

1992, 1993 winter 1991 winter 1993 winter 1990 summer 1985SERC . . . . . . . . . . . 1984-89 300 1,540, summer 1984; 200 1,300

winter summer summer 1985 winter 1984 1989-93 winter 1989- winter 1992winter 1991

SPP . . . . . . . . . . . . 1992-93 240 539 1984-92 226 1,017summer 1993 winter 1993 winter 1984 summer 1987

Wscc (Us.) . . . . . 0 0 1984-93 183 610winter 1984 winter 1983

estimates are based on 1980 data; the study projects that 47,435 MW in addition to the 39,348MW presently available will be ava ilable b y theyear 2000.22

While some utilities consider the anticipatedimpact of power from nonutility generators intheir demand forecasts, capacity plans, and otherdata submitted to NERC for preparation of its an-nual reports, many others do not. This results ininconsistent treatment and probable underrep-resentation of these potential resources by theNERC projections cited in this chapter.

Resource Availability

Regional differences in resource availability willdefine the range of opportunity for many newtechnologies considered in this assessment.

As figure 7-9 illustrates, geothermal develop-ment is expectedwest and Hawaii

ZI Du n & Bradstreet Technical EconomicServices and TRW EnergyDevelopment Group, /ndustria/ Cogeneration Potentia/ (1980-2000)for Application of Four Commercially Available Prime Movers at the Plant Site, Final Report,1984. 221 bid.

to b e c o~fined to the South-




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. ShawlU.S. Geological Su’weyCircular 76, 1975.

While the wind resource is strong in the West(WSCC) and most of the d evelopment to da te hasoccurred 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 land-

intensive wind and solar technologies, especially

in areas where a high premium is placed on visualesthetics (see the earlier discussion on licensingand permitting). In densely populated regionssuch a s NPCC, d evelopment o f these tec hnol-ogies may be more affected by land availabilityrather than by resource availability, For example,solar electric development will be particularlyconstrained in heavily populated areas where in-solation levels require high acreage per kilowattof power production. Figure 7-1Iillustrates thenational solar resource .23

While land availability constraints may limitsolar and wind development, these same con-straints are expected to augment the attractive-ness of fuel cells and batteries in urban areas. Re-sources for CAES deve lopm ent are a vailab le inall regions, as illustrated in figure 7- I 2.

Regions projecting continued and/or expandedemphasis on c oa l generation (espec ially ECAR,MAIN, MAPP, and SERC) will be likely candidatesfor AFBC a nd IGCC de velopm ent (see tab le 7-4).

ZJSolar availability i n the United States varies by close to a factorof 2 between the Southwest, on the one hand, and the Northwestand 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)




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 RELIANCE 24 PROFILESEast Central Area Reliability

Coordination Agreement (ECAR)

In anticipation of a2.4 percent regionalannual growth ratein summe r pea k de-mand, ECAR is pro-

jecting a 14 percent PENNSYLVANIAincrease in its 1983installed capacity INDIANA

levels by 1993.25 Theregion relies heavilyon c oal (93 percentof 1984 electricitygeneration) and is expected to continue this reli-ance well into the 1990s. Present constructior~

plans also project a substantial increase in depen-dence on nuclear energy, from 7 percent of to-tal generation in 1984 to 13 percent in 1993.26

There is a possibility tha t severa l of the se nuc lea rplants will not be completed on schedule; mem-ber systems have already had to cancel four nu-clear units27 (3,600 MW) which were well alongin construction. Two of these (Midland 2 andZimmer 1) a re am ong the c ostliest p lants in thecount ry.28

Assuming completion of presently plannedunits (i. e., as of the 1984 14th Annual NERC re-port), ECAR’s 1993 reserve margin is currentlyestimated at 32 percentzg—well above traditionalmeasures of adequacy, According to the region’s1984 annua l rep ort, of the units planned and / orcurrently under construction, five nuclear units(5,1OO MW) scheduled for completion by 1988,nine combustion turbines (735 MW) and three

Z4A]I of the NERC regio~al maps included in this section arereprinted with permission fromNERC, 14th Annual Review, op.cit., 1984.

Z5H ;Storically, ECAR has been winter peaking, but the region isexpected to be summer peaking from 1984 on.

ZGN ERC, 14th Artrrua/ Review, op. cit., 1984.z7Marble Hill I and 2, Midland 1, and Zimmer 1.2 8 A c c o r d i n g t. ~~&5 (James C o o k , “Nuclear Follies, ”~~~bes,

vol. 135, No. 3, Feb. 11, 1985, pp. 82-100), the cost per installedkilowatt at Midland 2 was $4,889, and the cost per kilowatt atZim-mer 1 was at $3,827, compared with an $1,180 cost per kilowattat Duke Power’s McGuire 2 plant.

291xx , .E/ectrjc p o w e r Supply and Demand for th e Cmtkwous

United States, 1984-1993, op. cit., 1984.

coa l plants (1,550 MW) scheduled for comple-tion between 1989 and 1993 may not be finishedon schedule, raising some questions about ade-quate reserves at the end of the decade if demandgrows as expected. If these plants are completedon time, 1993 projections for adjusted reserves(4.6 percent) fa ll slightly be low sugge sted relia-bility criteriaso (see table 7-4), while reserve mar-gin estimate s remain we ll ab ove 20 pe rc ent. Asfigure 7-3 suggests, the national high demandgrowth scenario could lead to reserve shortfallsin the region, while lower demand scenariosleave ECAR with a sizable capacity surplus.

ECAR’s heavy dep end enc e on c oa l makes itpa rticulady vulnerable to the cost o f mo re strin-gent acid rain regulations. Plant derating, retire-ment of o lder units which ca nnot be ec onomi-cally retrofitted , and inc rea sed do wn-time frommaintaining additional flue gas desulfurizationequipment could create a need for additional ca-pa c ity, dep end ing on the emissions red uc tionsrequired, the age-mix of the plants affected, pro-

jected electricity demand in the area, and relatedfactors. Concerns regarding these regulations areexpressed in the annua l NERC rep orts for a ll thecoal-dependent regions. 31

ECAR is characterized by moderate levels ofboth intraregional and interregional transfers, in-c luding p ower imp orts from Ca nad a. Within theregion, these t ransfers are due to loa d d iversity;inter-regional sales are economy transfers displac-ing c ostlier fuel, espec ially i n the MAAC reg ion.The region is expec ted to b e a net expo rter throughthe early 1990s,32 ECAR’s current transmissionsystem is being used c lose to its limit; 1,800 milesof new line are under construction to strengthenthe region’s overall transfer ability.33

301 bid,

II NERC, 14th Annual Ret<iew, op. cit., I % x.

32 D c ) E , E/ectr ic p o w e r 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/ityBulk Power Transactions,op. cit., 1983.




Electric Reliability Councilof Texas (ERCOT)

Demand is ex-pected to grow at anaverage annual rateof 4 percent i n

ERCOT over thenext decade—thehighest g row th rateof all the NERC re-gions. Member utili-ties de pe nd he avilyon gas (60 percent oftotal electricity gen-eration in 1984; ‘p rojecte d to d ec rea se to 35 pe r-cent in 1993); they are planning to decrease thisdependence by building several thousand mega-watts of new c oal/lignite a nd nuc lear ca pa city. 34

Present utility ca pac ity plans ca ll for a 40 pe r-cent increase in installed capacity over 1983levels by 1993 (see table 7-4). Even with thisc onstruction, ERCOT ma y ap proa c h or fall be lowseveral suggested reliability criteria within thenext decade if present demand predictions proveto be accurate. For example, the adjusted reservemargin is projected to fall to 4.3 percent as of 1991,and the installed reserve margin is expected tofall below 19 percent from 1990 through 1993.35

Figure 7-3 suggests the region may experience largecapacity shortfalls relative to other regions underall but the lowest national growth scenarios.

power from cogenerators could offset possibleshortfa lls in the reg ion, since pote ntial c ont ribu-tions from cogeneration may be inadequately re-flected by current utility resource plans. Whilethe present industrial cogeneration potential inERCOT is estimated at 5,110 MW, 36 the cogenera-tion capacity additions shown in the region’s 1984report total 885 MW for the 1984-93 planningperiod; total capacity contributions from “other”sources for 1993 is estimated at 4,862 MW—thisfigure includes conservation, load management,energy from refuse, and other undesignated

JA N 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 tothe large cogeneration resource in-state, theTexas utilities commission recently ordered oneTexas utility to show cause why several plannedlignite-fired plants should not be decertified inlight of potential capacity from cogenerators.ga

Whether or not the full cogeneration potentialin ERCOT is realized will depend to a large ex-tent on relative economics; it is likely that cogen-eration will be one of the major supply optionswith which new power generating technologieswill have to c omp ete.

Imports from other regions are expected to playan increasing role in ERCOT. Historically, therehave been large amounts of interchanges amongERCOT member systems, mainly for emergencypurpo ses, but ERCO T ha s bee n relat ively isola tedfrom other regions. Lines are presently under con-struction to link ERCOT systems with SPP and bet-ter integ rate remo te generating sources withinERCOT.39The region is expec ted to b e a net im-po rter for the next decad e (see ta ble 7-6).

Mid-Atlantic Area Council (MAAC)

MAAC utilities relypredominately onnuclear and coal- -fired generation. By1993, n u c lea r’sshare of total gener-ation is expected to

jump from 28 to 45 MAACpercent, while coal’sshare o f generationwill drop ab out 10 pe rcenta ge p oints.40Accord-ing to a recent NERC report, the “comparatively

J7N ERC, j4th Annua/ Report, op. cit., 1984; and NERC , Elec tricPower Supply and Demand, 1984-1993,op. cit., 1984.

JBAt a recent conference on utility applicationsfor renewa ble tec h-nologies, the vice president of Houston Light and Power noted thisfact and also remarked that “We have had 1300MW e (of cogener-ated power) thrust on us over two years. ” In addition, in 1984 whenthe company sought to add 300 MW from third-party producersto boost its reserve margin to 20 percent,cogenerators offered 1,275MW. (Sources: RE1/EEl Conference, op. cit., November 1984; and“Developers, Utilities, Lay Out Their Arguments, ”So/ar Energy /rr-te/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~ r j c P o w e r 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 utilitiesin the Region may force decisions to reduce cap-ital expenditures, which will delay the servicedates of generating units under construction."41

Two units (one nuclear, one oil-fired) have al-ready been delayed (the nuclear unit by 2 years,

from October 1988 to April 1990; the oil unit fromJune 1992 to beyond the 1984-93 planning period).MAAC planners cite reduced demand forecastsand financing problems as the major reasons forthe delays.

Presently, annual demand growth is predictedto remain at 1.3 percent and reserve margins areexpected to be adequate through the early 1990s.As figure 7-3 illustrates, given present construc-tion p lans, reserves wo uld fa ll be low 20 pe rcentonly u rider the 4.5 percent national growth sce-nario. of course, further plant delays (or unex-

pec ted c hanges in dema nd growth) could changethis situation. The region is already taking maxi-mum possible advantage of economy powertransfers from neighboring regions, notably ECARand SERC; t ransmission limita tions are expec tedto keep these levels below the amount MAACutility systems would prefer. These factors maycreate an attractive climate for short lead time,new technologies if those technologies are eco-nomically com petitive a t the time a need for ad -ditional power is recognized.

While o nly 7 pe rcent o f the e lectric ity ge ner-ated in 1984 in MAAC was expected to be oil-fired (decreasing to 4 percent by 1993), oil andga s com prise nearly 52 percent o f MAAC ’s1984installed capacity and will probably account for44 percent in 1993.42 Oil is the region’s “swing”fuel: if circumstances delay construction or insome wa y imp ed e use of the region’s coa l andnuclear capacity, or if demand increases substan-tially faster tha n expec ted , oil use w ill inc rease.In that case, oil costs will strongly influence therelative economics of alternative generating options.

Like other coal-using reg ions, MAAC is vulner-able to changes in present environmental regu-lations. Regional planners note that, if present reg-ulations are substantially tightened, the impacton some of the area’s older coal plants could af-

4 I N ERC, r#th A n n u a l R e v i e w, op. cit., 1984 , P. s 1.42 N E RC , 7 q th A nnua/ Review, op. cit., 1984.

feet overall system reliability, because some unitsmight have to be retired and the output of otherswould be substantially reduced. This could cre-ate a need for additional power sources—anotherpotential opportunity for new technologies.

Nuclear power is another important issue in theregion. In particular, developing sufficient away-from-reactor storage facilities for radioactivewastes is a concern for some MAAC utilitieswhich face shortages in onsite storage facilitiesat some of their older nuclear plants. 43

In the longrun, this too may affect technology choices in theregion.

Mid= America Interpool Network (MAIN)

MAIN expects itsinstalled capability

t o e x c e e d 1 9 8 3levels by 22 percentin 1993; this con-struction level isbased on a predicteddemand growth rateof o nly 1.8 perce nt.The reg ion p resen tlyrelies heavily on coal(68 percent of to talelectricity genera-tion in 1984) and nu-clear power (29 per-

cent). By 1993, co alis expected to de-crease to 56 percent

MICHIGAN

of total elect ricity generated by elec tric utilitiesin the region, while nuclear’s share is expectedto increase to 41 percent.44

Given their empha sis on c oa l generation, theregion’s utility systems are sensitive to changesin air emissions regulations. Potential construc-tion delays could also be a problem—85 percentof all of the plants presently under constructionin MAIN are nuclear; seven new units are planned

to come into commercial service between 1984and 1987.45 Delays would be especially impor-tant in light of projected reliability criteria for the

431bid.441bid.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. membersof MAPP presentlyrely on coal and nu-clear power for the

bulk of their electri-city generation—20percent nuclear, 66percent coal; hydro-electric power sup-plies 14 percent.MAPP is expec ted tocontinue its relianceon these t ec hnologies throug h the 1990s. Whileoil and gas accounted for less than 1 percent oftotal generation in 1984 and are expected to sup-ply about the same in 1993, installed nuclear ca-pability in the region is expected to exceed oil

and ga s by less than 2 pe rcent d uring the sam etime period. so This makes oil and gas “swingfuels” in the region, with all the associated im-plic ations for avo ide d cost rates.

Demand growth is predicted to increase at anaverage annual rate of 2.4 percent over the next10 years; utilities within the region are planningan 11.5 percent increase in capacity levels by1993.51 DOE projections of reserve margins(which assume scheduled completion of all unitsplanne d a s of the end o f 1983) ind ic ate the re-gion 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 the20 percent reserve margin under all but the low-est nationa l de mand g rowth c ase. Since c onstruc-tion has not yet begun on roughly 50 percent ofthe plants scheduled to come on line afier 1989, 5

system reliability concerns may create a windowof opportunity for short lead-time technologiesin 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.




MAPP members echo the concerns of othercoal-reliant systems regarding the potential im-pact of more stringent air quality controls. Besidesimpeding overall reliability, increasing mainte-nance needs, and spurring “premature” plantretirements, they think retrofits could also lead

to higher electricity costs for consumers.53

While MAPP’s member utilities will not beincreasing their relianc e on nuc lear po wer, stor-age of spent fuel from existing plants is a con-cern for the 1990s because onsite storage capac-ity will be fully used by that time. If nationalnuclear waste repositories for away-from-reactorstorage are not available, some member systemsexpect they may have to reduce generation fromtheir nuclear units.sq As in MAAC, this could cre-ate further need for new c ap ac ity.

The U.S. me mb ers of MAPP are summe r peak-ing; its Ca nad ian memb ers are w inter pea king.MAPP’s U.S. members import power from itsCanadian members, exchange power with neigh-bo ring c ounc il such as MAIN, and engag e in asubstantial amount of intraregional transfers avail-able due to load diversity within the region.Studies are now underway regarding the feasi-bility of increasing the region’s ability to importhydroelectric power from Manitoba into Minne-sota and Wisconsin, and the Dakotas. 55Given theusual economic attractiveness of such trans-ac tions, imp orts could em erge a s a more c ost-effective supply option than competing generat-ing technologies if MAPP’s import capabilities areincreased.

’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 per-cent of installed ca-pacity in NPCC is oil-

fired. Oil accountedfor 38 percent oftotal generation in1984; it is expectedto account for 21percent in 1993,Nuclear units ac- NEW YORK. .counted for 16 per-cent of 1984 capac- NPCC-U.S.ity and are expected to represent 23 percent by1993 (23 percent and 38 percent of total gener-ation, respectively), while coal-fired units ac-counted for 1 1 percent of 1984 capacity and are

expected to contribute 17 percent by 1993 (18and 27 pe rcent o f generation, respe c tively).56

Decreasing the region’s heavy dependence onoil hinges on completion of several new coal andnuclear units ranging in size from 800 to 1,150MW. Some of these plants have proven quitecontroversial. For example, two of NPCC’s nu-clear units—Shoreham and Seabrook l—areamong the most expensive plants in the coun-try, with installed costs of $5,192 and $3,913 perkilowatt, respectively .57 increased electric ratesassociated with bringing these plants into the rate-

base c ould run a s muc h as 53 perc ent fo r Shore-ham (Long Island Lighting Co.’s service area)and 63 percent for Seabrook I (for Public Serv-ice of New Hampshire’s customers) .58 If demandgrowth continues as predicted (1.7 percent) andif some of these new plants are not c ompletedand brought into service during the 1985-90 timeperiod, the opportunities for new technologieswill depe nd to a large extent on their comp eti-tiveness with new oil-fired, conventional units.(As discussed below, imports from Canada arenot likely to be ab le to fill the resulting de ma ndfor power.) Given the high population density ofma ny NPCC Sta tes, mod ular technolog ies whic h

JGPJERC, E/e~riC Power Supply and Demand, 1984-1993,op. cit.,1984.

J7Cook, Op. cit., Feb. 11, 1985.Jalbid.




are not land intensive might prove the easiest tosite.

Cancellation of currently planned facilitiescould also adversely affect reliability criteriawithin the region. Given present plans to increasegenerating capability 14 percent over 1983 levels

by 1993, it is expected that the systems withinNPCC will meet traditional reliability measuresinto the 1990s. But problems are anticipated inmid-decade if these units are not brought on line,peak demand growth substantially increases be-yond present forecasts, and/or presently operat-ing nuclear units are not kept in operation,

On the other hand, if currently planned unitscom e into servic e a s sched uled, figure 7-3 sug-gests a shortfall of the 20 percent reserve marginin the early 199os only under the 4.5 percent na-tional demand growth scenario.

NPCC systems import power primarily from theCanadian NPCC systems and ECAR. Reliance onoil makes economy transfers especially attractiveto NPCC members, but the demand for suchtransfers exceeds existing, under construction,and planned transmission ca pa c ity both w ithinthe United States and between NPCC’s U.S. andCanadian members. Present economy energytransfer levels leave little c ap ac ity for eme rge nc yflows; if emergency transfers are needed, econ-omy transfers will be reduced. Even NPCCs coalburning utilities buy e conom y po wer when p os-sible, since they have large loads and heavy peakswhich must otherwise be met with oil-fired steamand pe aking units.59

WEIA, /nterutj/jty Bu/k Power Transactions, op. cit., 1983; NERC,

14th Annual Review, op. cit., 1984; and DOE,Electric Power Sup- ply and Demand for the Contiguous United States, 1984-1993,op.

Southeastern Electric ReliabilityCouncil (SERC)

SERC is character-ized by a diverse fuel KENTUCKY

base which encour-ages heavy intrare-gional economytransfers as well asexchanges with in-terconnected sys-tems in neighboringECAR and SPP.bO Re- MISSISSIPPI

gionwide , coa l andnuclear plants ac- SERC

counted for 68 per-cent of 1984 installed c ap ac ity and 87 pe rcentof total generation; 1993 projections call for con-tinuation of these patterns,bl

Twenty-two perce nt o f the c apa c ity in SERC isoil- or gas-fired. While these plants accounted foronly 7 percent of total generation in 1984, thispattern varies markedly, with Florida’s installedoil/gas capacity exceeding levels in the otherSERC subregions by a factor of 5 or more.bzFlorida’s reliance on oil and gas accounts for sub-stantial intraregional economy transfers fromother members of SERC, although transmissioncapacity constraints are limiting otherwise desira-ble transfers from hydroelectric and coal-firedgenerators in Alaba ma and Georgia.63

While Florida plans to decrease gas generationin 1993 to slightly less than 50 percent of 1984levels, oil generation is expected to increase by4 percent. The overall region is following a simi-lar but less pronounced pattern; gas generationas a percent of total electricity generation is ex-pec ted to de cline by ab out 2 percent w hile oilge neration inc rea ses ab out 1 pe rc ent.64Oil andgas 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 isprojected to decrease to 57 percent of capacity and 31 percent ofgeneration.

GJN ERC, 14th Annua/ Review, op. cit., 1984; and EIA,/nteruti/ity

Bulk Power Transactions,op. cit., 1983.154 N E R C , E/ectrjc P o w e r Supply and Demand, 1984-1993,OP. cit.,

“cit., 1984. 1984,





210 q New Electric Power Technologies: Problems and Prospects for the 19S0s

As a hedge against possible oil and gas avail-ability p roblems or price increases, memb er util-ities are installing (or planning to install by theearly 1990s) several new transmission lines to takebetter advantage of available economy powertra nsfers from SERC, ERCOT, MAPP, a nd WSCC.70

if new generating sources are needed, major fac-tors affec ting their compa rative ec onom ics willinclude the price and availability of oil and gas,the regulatory climate affecting the region’s coalplants, and the degree to which the promisingcogeneration resource in Louisiana (see table 7-7) has been tapped.

Western Systems Coordinating Council(WSCC-u.s.)

Of ail the NERCregions, subregional

differences in gener-ation mix are mostpronou need inWSCC, where thereare four separatepower pools–theNorthwest PowerPool, The RockyM o u n t a i n P o w e rArea, the Arizona-New Mexico PowerArea (ANMPA), andthe California-South-

ern Nevada PowerArea (CSNPA).

UTAH COLORADO

TEXAS

71 N ERC, I q th Annual Review,op. cit., 1984, P . 58.

7ZNERC, E/@ric p o w e r 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 ofcogeneration capacity in the heavyoil 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 q 211

western States in WSCC also import power fromthe Pacific Northwest when it is available. Con-struction plans are underway to improve trans-mission capability within WSCC itself as well asam ong it and SPP, MAPP, and MAAC to ta ke be t-ter advantage of economy power transfers. ANMPA

members are especially interested in maximizinguse of available transmission facilities becausethey are capacity rich and financially dependenton selling surplus power to other WSCC mem-bers. Presently, there are insufficient facilities inplace to take full advantage of available economypower transfers; in particular, transmission capa-bility is insufficient to meet the demand for suchtransfers into the Ca lifornia-Southern Neva da sub-region and for transfers between the RockyMountain and Arizona-New Mexico subregions. 74

Predicted demand growth varies dramaticallybetween WSCC subregions, with the predictedaverage annual increase in summer peak demandranging from 1.9 pe rc ent (CSNPA) to 4.4 pe rc ent(ANMPA). If only 65 percent of the capacity pres-ently planned to com e o n line in 1993 (41 pe r-cent coal and 34 percent nuclear) is actually built,member utilities expect that, while some relia-bility criteria may not be met, overall resourceswill be adequate as long as demand does not in-c rea se faster than c urrently projected.75

Alaska Systems Coordinating Council(ASCC)

Most of Alaska’s population (i.e., 75 percent)resides in the “Rail belt” area stretching betweenSew ard, Anc horag e, a nd Fairba nks. Elec tric ity inthis region is provided primarily by indigenousnatural gas, supplemented by coal, oil, andhydropower. The Railbelt is the only subregioninterco nnected by a co mmo n grid. If pend inglicense applications with FERC for two hydro-po wer projec ts are a pp roved (Brad ley Lake–90MW, and Susitna–1 ,600 MW), ASCC expects thesubregion will have suffic ient c ap ac ity to m eetexpected 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 nformation provided to OTA by the Alaska Systems Coordi-

nate ng Cou ncll (ASCC), a N ERC affiliate, personal communication,May 1985.

doubtful that capacity credits for akernative tech-nologies wou Id be ava ilable in the nea r term un-rider this scenario; the Railbelt’s projected 1985peak is 717 MW; the 1990 peak is expected tobe 918 MW.77

While the technical and environmental con-cerns surrounding the Susitna Project appear re-solved, its size and cost are controversial. In re-spo nse, the Sta te is prop osing to build the p rojec tin stages, starting with 500 MW and eventuallyupg rad ing the fac ility to 1,600 MW.78FERC is notexpected to make a licensing decision until some-time in 1986.79

The ASCC expec ts grea ter develop me nt of theRailbelt’s indigenous coal reserves if Susitna is notap proved, creating a po tential opp ortunity fornew coal technologies. In addition, there arepending applications for waivers of the Fuel Use

Act’s natural gas generation prohibitions to allowRailbe lt utilities to take greate r ad vanta ge of theSta te’ s na tural ga s reserves.

Southeastern Alaska is served primarily by Fed-eral and State hydropower projects. The rest ofthe Sta te—c onsisting of wide ly dispe rsed villages(the “bush’ ’)-obtains electricity from diesel-fueled generators. Access to many of these areasis d ifficult. The bush subregion a ppe ars to offe rthe best development potential for dispersedelectric generating technologies in Alaska. Of thetec hnolog ies considered in this rep ort, wind tur-

bines appear among the likeliest candidates.There also ha s been some developm ent of p hoto-voltaics (PV) in remote areas, and hybrid systemslinking wind or PV with battery storage may proveattractive. For any new technologies consideredfor electricity generation in the bush, project eco-nom ics will be strongly influenced by the PowerCost Equalization Program.

Diesel fuel costs in the bush are high, result-ing in elec tric ity co sts of up to $1 / kWh in som eareas (e.g., whe re fuel has to b e flown in). Elec-tricity 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.781bid.79Vic Reinemer, “Electrifying Alaska, ”Pub/ic Power, November-

December 1983, vol. 41, No. 6, pp. 10-19.








neighboring islands may experience 2 to 5 per- Development of the land-intensive solar and windcent annual growth, but this is from very small tec hnologies to me et the State ’s electric po werpea k dema nd levels to b egin with.102 need s will definitely be affec ted by the se fa c tors.

The Sta te’ s ec ono my is hea vily depend ent 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.

protec t its ag ricultural a nd rec rea tional land s.103

102E5timateS provided to C)TA by the Hawaiian Electric powerCO.,

Inc., May, 1985.103H/EA, op. cit., 1981

SUMMARY OF MAJOR REGIONAL ISSUESDemand Uncertainty

Future electricity demand and the inherent un-certainty associated with estimating it are two ofthe most important factors affecting utility choicesbetween electricity supply options. Predictedelectricity demand growth rates differ dramati-cally within and among regions, and unantici-pated changes in these predictions could substan-tially affect both overall system reliability and theneed for new g enerating cap ac ity. Trad itiona lreliability measures such as generating reservemargins are very sensitive to demand predictions.This sensitivity is especially high in regions wheresubstantial numbers of new coal and nuclearplants are under construction. In the long run,consumer reaction to the cumulative “rate

shoc k” assoc iate d with bringing suc h large p lantsinto the ratebase may increase utility commissionactions encouraging greater reliance on alterna-tive supply options.

The 1993 ca pac ity levels in four NERC regionsare expected to exceed 1983 levels by more than20 percent; for three of these regions—ERCOT,MAIN, and SPP—this entails an increase of morethan 75 pe rcent in installed nuc lear ca pa c ity. Theoil-dependent NPCC region will be increasing itscoal capability by similar percentages, althoughits overail capability increase over 1983 levels willbe below 20 percent. If demand increases fasterthan predicted and construction delays occur, re-serve m argins in som e of these reg ions ma y beadversely affected. If demand growth predictionshave been overestimated, construction plans may

have to be altered, with uncertain effects on thefinancial status of the utilities affected.

Present and Projected Fuel Reliance

Capacity needs and the relative attractivenessof a vailable supply options are a lso strongly in-fluenced by regional fuel and technology reli-ance, since these plant characteristics generallyestablish the benchmarks for technology costcomparisons. While most systems with substan-tial oil and gas capacity are expected to decreaseuse of these fuels over the next decade, relianceon premium fuels is expected to be strong enoughin ERCOT, MAAC, NPCC, and some subregionsof SERC, SPP, and WSCC tha t the ec onom ics ofcompeting technologies will remain very sensi-

tive to the price and availability of oil and gas.104

This will apply even more strongly in the Floridasubregion of SERC, the Southeast subregion ofSPP, and the Arizona -New M exico subregion o fWSCC w here, due to predictions of high d ema ndgrowth and continued decreases in (or stabiliza-tion of) oil prices, reliability councils are forecast-ing increased dependence on oil. Regions charac-terized by heavy reliance on coal or nuclearpo wer will be vulnerable to c hang es in presentenvironmental regulations; the ultimate effect ofregulatory change s will vary between utility sys-tems and may create the need for additional

pow er sources in som e areas.

104TheSe fuel reliance 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 ex-isting generating facilities is likely to influence theneed for new capacity because construction maybe deferred if scheduled retirement of aging pow-erplants can be delayed by plant rehabilitationor efficiency improvements. Deferral prospectsvary considerably by region, By 1995, approxi-mately 40 percent of the fossil steam generatingplants in MAIN, NPCC, and WSCC will be over30 years old; ma ny of these p lants ma y be prom-ising candidates for life extension. In terms of totalinstalled capacity, the opportunities for life ex-tension will be greatest in ECAR, SERC, SPP, andWSCC. In all regions, the degree to which thisop tion is exercised will be hea vily influenced bythe comparative economics of other supply alter-natives.

Other Key Variables

Opportunities for increased economy powertransfers betw een and within reg ions are foundto b e a ttrac tive to a ma jority of utilities, but ex-isting and planned transmission capacity will limitthese transfers.

The p otential for co generation tends to b e Statespecific; opportunities are proving particularlystrong in the Gulf States, e.g., Texas and Loui-

siana , and in Ca lifornia. These systems will oftenbe in direc t c omp etition with the new te chnol-ogies considered in this assessment.

Load management appears attractive in all re-gions, although peak reduction in oil-dependentsystems could prove counterproductive in thelong run if it de fers rep laceme nt of costly pea k-ing units.

Conservation is similarly attractive, although theresource is both difficuIt to define and tap com-pletely.

Land and/or energy resource availability con-straints are expected to limit development of geo-thermal, wind and solar technologies in someregions.

Utility eco nomic and financ ial c harac teristicsare so variable within as well as among regions

that no c lear reg ional ge neralizations are d raw n.Generalizations about regional regulatory char-

ac teristics prove similarly difficuIt, although thepolicies of some innovative utilities commissionsare creating more favorable environments fornew tec hnologies than m ight otherwise be thecase in their jurisdictions. In addition, given sit-ing experiences to date, it seems reasonable toexpect that developers of new technologies mayexperience permitting delays as localities adjustthe regulatory process to accommodate newelectric generating systems.

38-743 0 - 85 - 8



Chapter 8

Conventional v. AlternativeTechnologies: Utility and

Nonutility Decisions



CONTENTSPage

Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..............219Utility Investment in Power Generation . . . . . . . . . . . . . . . . . . . . . ..................219

Overview . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ...........................219Utility Dec isionmaking . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .......219Comparative Analysis. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .....................222Utility Strategic Options. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 225Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ...................227

Nonutility Investment in Power Generation . . . . . . . . . . . . . . . . . . . . . ...............228Overview . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ................228Histo rica l Nonutility Genera tion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ....228Current Nonutility Electric Power Generation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ...228Characteristicsof Nonutility Producers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. ....229Nonutility Investment Decisionmaking. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ......231Comparative Profitability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .................234Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .........................241

Cross-Technology Comparison . . . . . . . . . . . . . . . . . . . . . . .........................241Overview . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..241Cross-Technology issues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 243Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ....245

Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..245Appendix 8A: Investment Decision Cash Flow Models For

Cross-Technology Comparisons . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ........246

List of TablesTable No. Page

8-1.8-2.8-3.

Typical Power Planning Functions . . . . . . . . . . . . . . . . . . . . . ...................221Alterna tive Tax Inc ent ives: Cumulative Effec t on Rea l Inte rnal Rate of Return. ....242Cross-Technology Comparison: OTA Reference Systems . .....................244


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 . .........................223Base Load Technology Costs: Utility Ownership-West . .....................224Peaking/Intermittent Technology Costs: Utility Ownership-West . .............225Life Extension Costs: Sensitivity to Capital Cost . ............................226Shortv. Long Lead-Time Analysis: Impacton Financial Health . ...............227Survey Responses by Technology . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. ...229Nonutility Ownership: Current and Projected Companies . ...................230Survey Responses by Projec t Loc ation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. ....230wind Farm installed Capacity Distribution . . . . . . . ..........................231Initial Year of Generation: Currently Producing Companies . ..................231Investment Risk Continuum. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .............234Breakeven Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ......237Breakeven Buy-Back Rates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. ...238Technology Profitability Range: Nonutility Ownership-West . .................239Tax Inc ent ives for New Elec tric Genera ting Tec hnologies:Cumulative Effecton Real Internal Rate of Return... . .......................243Calculation of Capital Cost per Kilowatt-Hour . .............................247



Chapter 8

Conventional v. Alternative Technologies:Utility and Nonutility Decisions

INTRODUCTIONDeployment of the technologies addressed in

this assessment in the 199os hinges on investmentde c isions ma de by b oth e lectric utilities and non-utility power producers. They are the primary(and in som e c ases, the only) ma rkets for thesenew te c hno log ies. The ir investment dec isions willdetermine the future commercial viability of thetechnologies. Investment in these technologieswill only occur if they can compete with exist-ing electricity-generating technologies. In addi-

tion, the new technologies will have to competeamongst themselves for limited sources of capital.

This chapter focuses primarily on the processof technology choice by utilities and nonutilityentities, and the relative ec onom ics of the vari-ous new ge nerat ing te chnolog ies. The first a ndsecond sections discuss these issues for utilitiesand nonutilities. The t hird sec tion p rovide s c ross-technology comparisons on issues concerningdeployment, environmental impact, and ease ofsiting. Emphasis in the latter section will be onthe nonquantifiable issues which cannot be ad-

dressed in cost and profitability calculations.

UTILITY INVESTMENT IN POWER GENERATIONOverview

Electric utilities in the United States are regu-lated to meet customer electricity demands at alltimes with reliable a nd rea sona ble c ost p ower.If customer demand increases, sufficient gener-ating capacity must be available. Utility plannersattempt to examine all options available to themto meet this demand; traditionally, the least costoption—or at least what was thought to be leastcost—has been the preferred option. Recent de-mand and operating cost uncertainties haveforced the consideration of other investment cri-teria, e.g., financial health, and has complicatedthe t rad itiona l dec ision ma king proc ess. This sec -tion focuses on electric utility decisionmakingand, using the methodology of the utility deci-sionmaking process, compares new technologiesand load management with traditional utility op-

tions such as conventional pulverized coal-firedplants and utility-owned combustion turbines.

Utility Decisionmaking

Electric utilities operate under a different set ofdecision rules and constraints than other busi-nesses (see box 8 A for a brief description). I n re-turn for the privilege to operate as a monopoly,investor-owned electric utilities are subject togovernment regulation of prices, profits, and serv-ice quality. ’ Because of this regulation, utilitiescannot maximize profit. For example, a utilitymust install added capacity to meet increased de-

! Pu blicly owned utilities are also subject to governmental con-trol and oversight of utility operations and finances. The source ofcontrol can be municipal government, local entities, or the Fed-eral Government. Since investor-owned utilities (IOU) account forthe majority of U.S. energy sales to ultimate customers (76percent—see table 7-1 ), emphasis will be placed on IOUdecision-making. Moreover, many publicly owned utilities, primarilymunicipally owned utilities, are distribution-only utilities and donot invest in powerplants. Nevertheless, these municipal utilities

will be very Interested in demand side alternatives, e.g., load man-agement.

219




and, even though it may decrease profits. 2 Elec-tric utilities have a legal obligation to serve all thede ma nd o f their custom ers at a ny time.3 Utilitiesnormally construct enough extra capacity to pro-vide a reserve margin against the possibility of

being unable to serve customer load if a gener-ating unit fails.

Utility decisionmakers also have obligations: 1)to rate pa yers to minimize their rat e b urde n overtime, and 2) to their stockholders to maximizethe utilities’ financ ial hea lth. The ac cep ted mea ns

of accomplishing this is to minimize costs withinreliability, regulatory, environmental, and finan-cial constraints.4

Utility Planning ProcessElectric utility decisionmaking on new plants

is a four-step process: load forecasting, genera-tion planning, transmission planning, and distri-but ion p lanning. Table 8-1 lists the d ifferent c ha r-ac teristics of the se pow er p lanning func tions. Thefirst step, load forecasting, determines the needfor additiona l p lants. Typical forec asting tec h-niques include time series analysis, econometricmo deling, a nd e nd-use mod els. In the p ast, util-ities could rely on simple trend analysis to projectfuture demand based on past growth rates, e.g.,7 percent a year. Rec ent unpredicta ble de mandgrowth, however, has ma de this me thod unde-pendable and more sophisticated methods aregaining wider acceptance.

Generation planning focuses on two importantquestions: the ca pa city needed for ad equa te re-serve margins and the mix of capacity needed forleast cost operation. Capacity expansion models

are used to examine p ossible g eneration a lterna-tives and to determine the least costly mix of fu-ture generation additions. Next, the operationcosts and reliability of this generation mix are ex-amined. Finally, the impac t of the c andida te c a-pacity plan on the utility’s financial position isassessed . These mo deling a nd ana lysis func tionsoften rely on c omplex opt imization a nd simula-tion mod els. s Transmission and distribution p lan-

2G. R. Corey, “Plant Investment Decision Making in the ElectricPower Industry, ”Discounting for Time and Risk in Energy Policy,Robert C. Lind (cd.) (Baltimore, MD: Resourcesfor the Future/JohnsHopkins, 1982), pp. 377-403.

]Garfield and LOve jOy p rov ide a good summary of this Obliga-tion: “public utilities are further distinguished from other sectorsof business by the legal requirement to serve every financially re-sponsible customer in their service areas, at reasonable rates, andwithout unjust discrimination. ”(P.). Garfield and W,F. Lovejoy,Pub//c Uti/ity Economics (Englewood Cliffs, NJ: Prentice-Hall, 1964),p. 1.

4A large body of economics Iiteratu re is devoted to the incen-tive (or lack of incentive) for cost minimization under rate of re-turn regulation. The seminal piece by H.Averch and L. Johnson(H. Averch and L. Johnson, “Behavior of the Firm Under Regula-tory Constraint,”American Economic Review, vol. 52, No. 6, 1962,pp. 1053-1069) argues that rate-of-return regulation provides an op-posite incentive towards capital maximization.

sGood reviews of generation planning models have been doneby S. Lee, et al. (S. Lee, et al.,Comparative Ana/ysis of Generation Planning Models for Application to Regional Power System Plan- ning (Palo Alto, CA: System Control, Inc., 1978); and D. Anderson(D. Anderson, “Models for Determining Least Cost Investment inElectricity Supply,”Be// Journa/ of Economics,vol. 3, spring 1972).





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 decisionsstrictly on profit maximization. Instead, they havetraditionally examined all available means ofmeeting customer demand (both generation anddemand-side options) and then selected the alter-native that is least costly in terms of the revenuerequired from the consumers. This comparisonapproach, known as the minimum revenue re-quirement approach, is derived from standardutility rate-making techniques (see box 8B). It hasbe en used throughout the industry8 One recentsurvey indicated that 91 percent of investor-owned electric and combination electric and gassystems used a minimum revenue requirementapproach.9

In this analysis, the comparative costs of thenew technologies and of the conventional alter-natives were arrived at by applying the minimumrevenue requirement concept to each investmentalternative and then deriving its Ievelized cost.OTA sta ff deve lope d a c ost a na lysis mo del usingstand ard utility ac counting and investment de -cision methodologies for comparison purposes. 1

0

This mo del p roject s yea rly revenue requiremen ts,i.e., costs, taxes, and allowed rate of return, forthe expected life of a new plant. Levelized costsin cents per kilowatt-hour are derived from thisrevenue requirement stream, and form the basisof cross-technology cost comparisons, (Appen-dix 8A discusses the Ievelized cost estimation inmuch greater detail.)

7“Available” in this context refers to the technologies utilities per-ceive as being able to meet their needs. The utility planners mayfeel that adequate information on a technology or commercial dem-onstrations are not sufficiently available for new technologies, andwill not consider the technology.

sPublicly owned utilities perform a similar comparison. The com-ponents of revenue requirement will be different-reflecting fac-tors such as rate of return.

9G. R. Corey, “Plant Investment Decision Making in the ElectricPower Industry, ” op. cit., 1982,IOThe analysis structure usecf to develop the OTA model was de-

rived from the techniques used by Philadelphia Electric Co. ’s RatesDivision (Philadelphia Electric Co.,Engineering Economics Course (Philadelphia, PA:Philadelphia Electric Co., Rates Division, Financeand Accounting Department, January 1980), p. 2-2.).

Basic Assumptions

In order to compare different technologies ona consistent basis, several assumptions had to bema de. The te c hnolog ies c onsidered for utility in-vestment were assumed to be electric-only tech-nologies—no cogeneration technologies wereconsidered. Cost estimates calculated in thismod el were mad e on a co nstant d ollar (1983) b a -



Ch. 8—Conventional v. Alternative Technologies: Utility and Nonutility Decisions q 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 technologieswith different reference years, lead-times, and life-times. Figure 8-1 lists the basic parameters thatare assumed not to vary across technologies.Later in this section, the sensitivity of the coststo changes in these parameters will be addressed.

For the basic cost comparison, the technologieswe re examined fo r three sc ena rios: worst c ase,mo st likely c ase, and best c ase. These sc ena rioswere derived from the parameter ranges includedin the cost and performance projections devel-

op ed in cha pters 4 and 5. The w orst c ase sce-nario incorporates the “worst” (most pessimis-tic) values for each parameter, while the best caseuses the “best” (most optimistic) values. For ex-am ple, the w orst c ase uses the high e nd of thecapitalcost rang e, but uses the low e nd o f thecapacity factor range. In addition, the worst casescenario assumes little improvement in currenttechnology conditions. Comparison of the worstand best case scenarios provides a range of level-ized costs. The most-likely case numbers repre-sent OTA’s best estimates of future utility costs.




Cross-Technology Cost Comparison

The results of the c om parative c ost ana lysis a reshown in figure 8-1. Costs for pulverized coal-fired plants, combustion turbines, and coal pIantlife extension were included for comparisonpurposes.

One of the striking features of the results shownin figure 8-1 is the wide cost ranges for solarphotovoltaics and fuel cells. Both of these tech-nologies are currently in early stages of develop-ment relative to the other technologies in the fig-ure and are currently not competitive with othertec hnolog ies. Nevertheless, as figure 8-1 shows,these tec hnologies have the po tential of signifi-ca nt co st red uctions, and they co uld c omp etewith peaking technologies, e.g., combustion tur-bines, or even ba se load tec hnolog ies. To be-c ome c omp etitive, however, they must be de-ployed in significant numbers, and importantresearch, development, and deployment ques-tions must be resolved (see chapter 4).

Comparison of the new base load technologies– geothermal, atmospheric fluidized-bed combus-tors (AFBC), and integrated coal gasification/com-bined-cycle (lGCC)–with the primary conven-tional alternatives—pulverized coal-fired plantswith flue gas desulfurization (FGD) and existingcoal plant life extension—indicates that all ofthese new technologies are likely to be competi-tive with current technology in the 1990s. Fig-ure 8-2 shows Ievelized costs for each of thesetec hnolog ies under the mo st likely c ase. Theseresu Its indicate that coal powerplant bettermentis the cheapest source of base load power.Among the new technologies, IGCC appears tobe the b est com pe titor follow ed by AFBC. Theco mp etitiveness of these new “ clean co al” tech-nologies is important because both produce lessnega tive e nvironmenta l imp ac ts than c onven-tiona l c oa l-burning te c hnolog ies. The p ote ntiallyattractive economics of the plant betterment op-tion, however, could lead to extended use of old,dirtier coal plants, many without scrubbers. Geo-thermal plants are also attrac tive in terms of c om -parative cost, but the site-specific nature of geo-thermal power will probably limit widespreaddeployment,

Figure 8-2.— Base Load Technology Costs: UtilityOwnership—West

a ~

Geothermal AFBC IGCC Coal Life

Technologyextension


The new , intermittent, and pe aking tec hnol-ogies addressed in this assessment are also ex-pected to compete favorably with current tech-nologies in the 1990s, Figure 8-3 shows the mostlikely-case costs for solar thermal electric, solarphotovoltaics, wind, fuel cells, battery storage,and compressed air energy storage (CAES), aswe ll as the mo st likely c osts for c om bustion tur-bine powerplants. Wind power from utility-ownedsmall turbines ( <400 kW) in wind farms showsthe lowest cost among the new generation tech-nologies. The expected future Ievelized cost ofwind technology is significantly lower than the

other non-base load technologies. Wind also hasthe po tential of c omp eting w ith the ba se loadtechnologies (see figure 8-2). The relatively lowcost estimates for the storage technologies indi-cate that these technologies could compete fa-vorably with pe aking tec hnologies to satisfy pe akelectric loads.

Sensitivity to Uncertainty

Despite the optimism reflected in the cross-technology comparison, the projections of thesefuture costs for the new technologies are subject

to a great de al of unce rta inty. This unce rtaintyis reflec ted in the Ieve lized cost rang es in figure8-1. Several of the tec hnolog ies–solar pho tovol-taics, wind and fuel cells—show particularly wide



Ch. 8—Conventiona/ v. Alternative Technologies: Utility and Nonutjlity Decisions . 22

Fiqure 8-3.— Peaking/Intermittent Technology Costs:Utility-Ownership—West ‘ -

t20

t —

1hoto-p a r a b o l i c v o l t a i c s

d i shcell bustlon storage

turbine

TechnologySOURCE. Off Ice of Technology Assessment

cost ranges. Unless resolved, this uncertainty, andthe investment risk it represents, will probablyhamp er widespread dep loyment of ma ny newtechnologies well into the 1990s.

A sensitivity analysis was performed for eachtechnology considered in this assessment. Thisanalysis highlights the most sensitive parametersand provides insight into the tec hnologica l de-velopments that could produce the most im-proveme nt in future c ost a nd pe rforma nc e. Thesensitivity of a technology’s Ievelized cost to

changes in key parameters—capital cost, opera-tion and maintenance (O&M) cost, capacity fac-tor, and fuel cost—was tested by varying each pa-rameter above and below the base case estimateby 25 percent. This analysis indicates, for exam-ple, that a 1 ()-percent increase in wind farm cap-ital co st c ould cause our most likely estima te o futility Ievelized costs to increase 1.5 cents/kWhor abo ut 21 percent.

In general, the results of sensitivity analyses forall the technologies indicate that the three mostcritical parameters are capital cost, capacity fac-tor, and fue l c ost. The c apa c ity fac tor is the m ostcritical parameter for electric utility operation,Fuel costs were also very important for non solartechnologies, but capacity factor consistently pro-duced the largest variations in Ievelized costs. Asom ew ha t surprising result from the ana lysis was

that capital cost changes do not produce as muchvariation as these other parameters. Nevertheless,the relative importance of each of these param-eters varies ac cording to d uty cyc le, heat rate ,and capital intensiveness. For example, fuel costsare the most sensitive parameter for combustionturbines, but c ap ac ity fac tor is more importantfor fuel c ells. This is bec ause of t he lower ca p italcosts and higher heat rates of combustionturbines.

A possible explanation for the relative impor-tanc e of c ap ac ity fac tor vis-a-vis cap ita l cost isfound by examining the Ievelized cost formula. 11

The nume rator of t he fo rmula is the Ieve lized an -nual revenue req uirem ent. The deno minator isaverage kilowatt-hour production.Inc reases inc ap ac ity fac tor will direc tly inc rea se e lectric ityproduct ion and reduce levelized costs. Cap ita lcosts are recovered through economic depreci-

ation over a number of years (1 5 years underpresent tax law). The Ieve liza tion c alc ulation d is-counts the depreciation costs more in later yearsthan in early years. Thus, changes in initial capi-tal cost do not produce as significant and directan effect. This suggests that utilities are likely tocontinue to be very concerned with the availabil-ity and reliability of future generating optionssince these factors cause significant levelized life-cycle cost uncertainty.

Utility Strategic Options

Most utilities have put off decisions on new,large coa l or nuclear plants. To commit largesums of c ap ita l to such long lead -time projectsin the highly uncertain investment environmentwhich has prevailed in this industry since the1970s, they think, is too financially risky. Instead,many utiIities are considering a variety of strate-gic options that will defer the need for such large-scale commitments. Chapters 3 and 5 discussthese options in detail. The discussion that fol-lows focuses primarily on three of these options,namely life extension and rehab ilitation o f exist-ing generating facilities, increased reliance onload management, and construction of smallmodular plants.

1 IThe general form of the Ievelized cost formula is:Ievellzeci annual revenue requirementaverage annual electricity production




Plant betterment—i.e., life extension and re-habilitation of existing generating facilities–is away to defer new generation investment. The c a -pac ity ba se fo r this op tion is sizable–by the yea r2000, nearly a third of the existing U.S. fossil gen-erating capacity will be more than 30 years old.In addition, the capital investment required–$200 to $800/kW–is relatively small. The attrac-tiveness of this option is partially explained byits low expected Ievelized cost. As can be seenin figure 8-2, the expected costs of existing coalplant be tterment a re lower than b oth c onven-tional and new b ase load generating tec hnol-ogies. Moreover, figure 8-4 shows that capital costlevels for life extension up to $1 ,500/kW can pro-duc e lower cost p owe r than c onventional pul-verized coa l plants with FGD, or an IGCC p lant.Additiona l OTA mod eling efforts12using EPRI Re-giona l System s da ta ls indica te tha t a t the systemlevel, at least in the Southeast, fossil life exten-sion (coal, oil, and gas-fired units) could produceoverall utility system revenue requirements14 asmuch as 5 percent lower than a capacity expan-sion plan ba sed on large unit c onstruc tion (theba se c ase) to me et the sam e loa d. Nevertheless,the results also indicate that focusing plant bet-terment activity solely on oil and gas units couldproduce higher revenue req uirements than thebase case.1 5

Load management is the other primary non-generation option available to utilities. Its prin-cipal goals are to permit a higher proportion of

demand to be served by lower cost electricity(from base load sources) and to defer the needfor new g enerating c ap ac ity. There is the p oten-

12 A state-of-the-art uti Iity si mu Iation model, the UtilitySystemAnalysis Model (USAM) by Lotus Consulting Co., was used for thisanalysis.

I JElectric power Research Institute, The Ef’/?/ Regional S)@em5(Palo Alto, CA: Electric Power Research Institute, July 1981),EPRIP-1 950-SR. The load and system data used by OTA were the basicEPRI typical utility data sets that were modified by Lotus Consult-ing Co. to include plant additions.

1 oThis value refers to a Ievelization of the utilitySyStem revenuerequirements (using a 5 percent discount rate) over the 10-yearperiod 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 2000will have their life ex-tended; 2) plant efficiency is increased by 5 percent, capacity isincreased by 5 percent, and 10 years are added to design plantlifetime; 3) the plant betterment costs$200/kW (based on the newplant size); and 4) future capacity is deferred to achieve the samereserve margins as in the base case.

IGElectrotek Concepts, Inc., Future Cost and Performance of New Load Management Technologies, final report to the Office of Tech-nology Assessment, January 1985, OTA Solicitation US-84-7. Forthe Southeast, 5.4 percent reduction equals 891 MW in 1990.

I Th e basic assumptions used in this analysis are the same as forthe plant betterment analysis. The capital costs of the utility loadmanagement program (calculated byElectrotek to be $191 /kW) areannualized and expensed over the life of the equipment. Furtheranalysis by OTA has shown that utility revenue requirements donot significantly differ when expensing or capitalizing the load man-agement program.



Ch. 8—Conventional v. Alternative Technologies: Utility and Nonutility Decisions . 22

Comp arison o f the results for the p lant life ex-tension and load management cases in a typicalSoutheast utility indicates that plant life extensionis the more attractive option at currently pro-

jected load management levels and assumed pro-gram costs,

Of particular interest to many utilities are thepotential benefits of increased flexibility and fi-nancial performance offered by small-scale, shortlead -time generating p lants. OTA m od elingstudies indicate that under uncertain demandgrowth, the cash flow benefits of such plants inthe short term couId be considerable .18 For ex-ample, as shown in figure 8-5, the interest cov-erage ratio, which measures a utility’s ability torep ay its de bt ob liga tions—and is the princ ipa lconsidera tion in bond rating d ec isions, tend s todecline for a utility engaged in a major construc-tion project as outlays are made during the con-

struction period. Under the low demand growthscenario 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 loadis 5,500. The first year of the scenario IS 1990 and continues u ntl I

2000. A 800 MW coal plantIS assumed to start-up in 1992. Apul-verized coal plant is the technology examined, The only differencesbetween the two types of plants are:

Small LdrgeC a p a c i t y 100 MW 500 MWL e a d - t i m e 1 year 7 years

I $ITwo percent load growth i n theti rst 5 years and O percent i I Ithe last 5 years. Edison Electrlc Inst]tute, Strateg~c /mp/icatJorrs ot’

6 L

1990 1992 1994 1996 1998Years

SOURCE Office of Technology Assessment

small modular plants results in a considerably bet-ter interest c overag e ratio trend, even with a 10percent capital cost premium (per kilowatt) asso-ciated with the smaller plants. The primary rea-son fo r the differenc e in financ ial performa nceis the a bility of the sma ller plant to trac k de ma ndgrowth. Under the low demand growth scenario,

the interest c overag e ratio for the large p lant isrelatively low bo th d uring the c onstruc tion pe riodof the plant20and during the p eriod that the sys-tem has high reserve margins. Use of a low-highdemand scenario2lnarrows the difference. In-deed, the interest coverage ratio trend for thelarge p lant surpasses the sma ll p lant t rend a fterthe large plant comes on-line in 1997.

Summay

The new t ec hno log ies add ressed in this assess-

ment have the potential to compete economicallywith conventional generating technologies, e.g.,pulverized coal, combustion turbines. The newtechnologies which are most likely to providelower cost power are AFBC, IGCC, geothermal,and wind power. Fuel cells and photovoltaicscould compete favorably with peaking technol-og ies suc h a s c om bustion turbines. Storag e te c h-nologies could also compete effectively withthese peaking technologies. In addition, most ofthe generating technologies considered in thisassessment offer the small-scale modular featuresmany utilities are seeking, although many are sub-

jec t to significant c ost and pe rformanc e uncer-tainty.

A more serious impediment to utility invest-ment in these new tec hnologies for the next10to 15 yea rs is tha t m ost o f them are not likely tocompete effectively with other generally morecost effective strategic options—life extension andrehabilitation of existing generating facilities, andincreased reliance on loa d ma nag eme nt. Thesestrategic options are being aggressively pursuedby many utilities. OTA analysis of these optionsindicates 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.






tion, wind, geothermal, AFBC, and hydro. Addi-tional activity is occurring in solar thermal electricand pho tovo ltaics. Tab le 4-4 show s the insta lledcapacity breakdown for the new tech nologies in1985. Wind power and AFBC are the subject ofthe m ost a c tivity.

Characteristics of NonutilityProducers

Nonutility involvement in new tec hnology d e-velopment is being initiated by both industrialfirms and third-party investors. Industrial invest-ment in new technology projects is primarily un-de rtaken to reduc e the co st of m eeting electri-cal a nd/ or proc ess hea t ne ed s. Either revenuesfrom power sales to electric utilities or the avoid-ance of electricity purchases can make a projecteconomic. By contrast, third-party investment in

these technologies is organized by entrepreneurswho obtain financing and develop projectsasprofit-making ventures from sale of the electri-city and any byproduct steam. Both types of de-velopment have occurred in recent years—withindustrial involvement centering on cogenerationand third-party investment principally occurringin cogeneration, low-head hydroelectric dams,and wind power.

In order to gauge the level and type of currentnonutility power generation, OTA sponsored asurvey24conducted by the Investor Responsibil-ity Resea rch C enter (1 RRC). The trends and char-acteristics in the I RRC sample provide insight intothe nature of the industry and the direction it ap-pears to be headed.

IRRC sent a survey form to current and projected nonutility power producers in the wind,solar thermal electric, geothermal, and photovol-taici ng

q

q

industries.25It a sked questions on the fo llow -topics:

ownership,financial structures,

24 I n v e s t o r Responsibi[ ity Research Center, Survey of ~on-Uti/ityE/ectric Power Producers, OTA contract 433-7640, July 11, 1984.

25A total of 4S companies (25 current and 20 projected produc-ers) responded to the survey. IRRC also surveyed the biomass andhydroelectric small power industries. The remaining technologieshighlighted in this report (fuel cells, AFBC, and ICCC) were not suffi-ciently commercialized or deployed in 1983 to be surveyed.

q generating plant characteristics,q vendor agreements,q operational data, andq purchase agreements with utilitiesFigure 8-6 shows the breakdown by technol-

ogy of the survey respondents. Note that wind

power companies represented 76.7 percent ofthe respondents, and geothermal power came ina distant second at 11.6 percent. I n terms of to-tal installed capacity, the disparity is even greater.By the end of 1983, the IRRC sample reports thatwind pow er acc ounted for over 134 MW of c a-pacity.2b

The survey results reveal two important indus-try characteristics which could affect industryhealth and the impact of Federal policy in the mid1980s. First, most companies involved in nonuti!-ity power projects are relatively young—less than

3 years old. Sec ond , these c om pa nies a re q uitesmall, typically maintaining generating capacityof less than 6 MW. Any significant changes i n taxand reg ulato ry policy co uld severely affec t theoperations and profitability of these young firms.

zbcornparisorl o f this reportedcapacity with the 239 MWrepot-tedin D. Marler, “Windfarm Update .. .117 Megawatts and StillGrow-ing, ’’Alternative Sources of Energy, No. 63, September/October1983, suggests that the IRRC sample contains a little over one-halfof the industry in 1983.

Figure 8-6.—Survey Responses by Technology

SOURCE: Office of Technology Assessment



230 NewElectric Power Technologies: Problems and Prospects for the 1990s

Figure 8-7 shows the cross-section of owner-ship of current and projected non utility produc-ers. The m a jority (78.6 pe rcent ) of t hese p rod uc -ers are privately owned companies, most ofwhic h a re sma ll in size a nd we re formed stric tlyto sell power to utilities. Far fewer publicly heldcompanies and subsidiaries, particularly moreestablished, older, and larger firms, have enteredthe m arket as yet.

The survey respo ndents were a lso a sked abo utthe financing methods they have used to capital-ize a nd op erate their gene rating fa c ilities. The re-sponses from the currently producing companiesfall generally into four major categories: soleownership, joint ventures, partnerships, and leas-ing. Partnerships are the most prevalent, account-ng for half of the p rojec ts surveyed . Sole o wne r-

ship ranked second—29.4 percent; joint venturesand leases accounted for 14.7 and 5.9 percent,

respec tively. This c ross-sec tion ind ica tes tha t mostof the current projects, i e., wind farms, are gen-erally financ ed with p rivate investor c ap ita l, al-though over one-quarter of the respondentsnoted that they have used a mixture of financ-ing metho ds such as sole owne rship a long w ithpartnerships.

The survey indica tes that the project loc at ionof most of the current and anticipated nonutiiity

Figure 8-7.— Nonutility Ownership: Current andProjected Companies

projects represented in the survey is California(see figure 8-8). California represents an evenlarger portion of nonutility capacity–over 90 per-c ent o f the 1983 rep orted insta lled c ap ac ity. Theprimary reasons are the availability of high utilityavoided cost rates, tax credits (State and Federal),and California’s generally supportive reguIatoryenvironment for alternative energy development.

Wind power represents all of the reported 1983insta lled capa c ity of 134 MW in the survey. Theaverage wind farm in the survey had an averagec ap ac ity of 5,8 MW, Figure 8-9 show s tha t w hilesma ll compa nies do minate the market in termsof total projects, in terms of installed capacitylarger companies represent a much greater shareof the industry.

The yea r of initial genera tion for most c om -panies has been within the last 3 years. AlthoughPURPA and the business renewable tax creditswere first passed in 1978, significant nonutilitygeneration did no t oc c ur until 1982 be c ause o fcourt c halleng es to PURPA a nd slow imp lemen-tation by States. As mentioned earlier, most ofthe companies involved in nonutility productionare less tha n 3 years old; over 60 pe rcent’ of thecompanies in the survey started producing in1982 and 1983 (see figure 8-10).

Figure 8-8.—Survey Responses by Project LocationNew 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 . 2

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 f2 —

46,0001 —o ~ t 1

0 - 5 5 - 1 0 1 0 - 2 0 2 0 - 5 0Size categories (MW)

SOURCE: Off Ice of Technology Assessment

Figure 8-10.— Initial Year of Generation: CurrentlyProducing Companies

1984 (4.30 /,) 1976 (4.30/, ) 1980 (8,7°/0)

Hence, investor interest will increase if nonuti]itypower project investments offer potentially highreturns relat ive to othe r investment op tions. Butthe rationale for the investment will vary accord-ing to the types of investors. Additional consider-ations for investors include tax status, timing ofthe investment, cash flow patterns, and mainte-nance of a balanced portfolio of risky and non-risky investments.

Financing Alternative TechnologyProjects

Investment in nonutility generation projects canbe initiated through a variety of financing struc-tures. For a corporation (industrial or commer-c ial), the tw o m ajor vehicles are c ap ita l invest-ment with internal funds, and project financ ing(sometimes called “third party financing”). Cap-ital investment by a corporation usually involves

the use of retained earnings, equity, or debt is-sues to finance a generation project. Projectfinanc ing, on the othe r hand , looks to the c ashflow and assets associated with the project as thebasis for financ ing. Priva te investors oft en investin technology projects through tax shelter syn-

SOURCE Off Ice of Technology Assessment.

Nonutility InvestmentDecisionmaking

Investment in power generation equipment ina nonutility environment is generally not verydifferent tha n othe r long -term investment d ec i-sions. Investors, either individuals or corpora-tions, are primarily interested in maximizing theirrisk-adjusted return on their invested capital.

on the size and financial strength of the indus-trial firm, the rationale for investment, and theriskiness of the tec hnolog y. A large c orpo rationwill be more willing and able to finance a projectwith retained earnings than a small industrial firm.A large firm usually has more retained earningsavailable for discretionary investment. If a cor-poration has a stake in the development of a tech-nology, e.g., the c orporation is a vendor of thetechnology, successful ownership of a projectsuch a s a p hotovo ltaic array o r wind farm mayattract future investment by third parties and lead

to inc rea sed profits for the c orporation. A p rojec tdirec tly related to a firm’ s ma nufac turing p rocess—e. g., providing process steam or electricpow er d irec tly to an industrial operation–is a lsomore likely to be financed internally. But a projectoperated strictly as a small power producer is less




likely to be owned solely by a corporation. in-vestments in projects that are more associatedwith a firm’ s princ ipa l line of business (e.g ., sa lesexpenditures or plant expansion) are more likelyto receive higher priority. In addition, if the tech-nology under consideration is perceived as risky,an industria l firm may seek pa rtners or guaran-tees from vendors to share the project risk.

The m ethod s of p roject financ e a re pa rticularlyappropriate to the financing of distributed elec-tricity generation. As mentioned earlier, projectfinancing looks to the cash flow associated withthe project as a source of funds with which torep ay the loan, and to the assets of the projectas collateral. For suc cessful projec t financ ing, aproject should be structured with as little recourseas possible to the sponsor, yet with sufficientcredit support (through guarantees or undertak-ings of the sponsor or third party) to satisfy

lenders. In addition, a market for the energyoutput—electrical or thermal—must be assured,preferably through contractual agreements; theproperty financed must be valuable as collateral;the project must be insured; and all governmentap provals must b e a vailable.z’ There are fo ur ma-

jor forms of project finance applicable to newtec hnology projec ts: leasing, joint ventures,limited partnership, or small power producer (seebox 8C for definitions).

Another ownership structure often used inwind turbine farms is an organized system ofindividual turbine sales, also known as soleownership (or “chattel”). Under this structure theprivate investor owns only one turbine.28 Theproject developer organizes the wind farm, sellsthe wind turbines to prospec tive investors, andprovides maintenance services.

Required Project Characteristics

Every non utility generation technology project,whether it is structured through traditional projectfinancing techniques or third-party entrepreneurs,must meet several requirements before it will beac c ep ta ble t o investors. These req uirem ents fallinto three key areas: risk reduction, firm fuel and

lzp. K. Nevitt, project F;rxincing (London: Euromoney PublicationsLimited, 1979).

Z8R. Ceci, “Investing in Windpower: Ownership or Partnership, ”Alternative Sources of Energy, No. 71, January/February 1985,

power sales contracts, and sufficiently high prof-itability (before or after taxes depending on theinvestor),

There are several forms of risk involved in newelectric generation technology projects.29Theyinclude among others:

1.

2.

3.

4.

In

Machine Risk: Will the technology performas predicted, i.e., produce the estimatedpower, meet availability targets, and not suf-fer catastrophic failure, all within appropri-ate installation and operational budgets?Resource Risk: Will the site actually havesufficient fuelstocks (e.g., low-cost coal orgeothermal brine) or quality resource (e.g.,wind speeds and distribution) for the dura-tion of the project? Will year-to-year fluctu-ations be great?Politica / Risk: Will the “rules of the game”regarding tax credits and deductions, salesprices to utilities (or others), zoning or-dinances, or other permitting regulationschang e for the wo rse d uring the c ourse o foperation?Ene rgy Price Risk: Will the oil market softenfurther? Will the utility be allowed to con-vert to coal or other low-energy cost options?

order to finance a new nonutility project,these risks must b e e ither mitiga ted or incorpo-rated in contingency plans. Common risk reduc-tion techniques include vendor guarantees, take-or-pay contracts with utilities, and guarantees on

project profitability from the project sponsors.Nevertheless, not all of the risks in projects uti-lizing new tec hnolog ies can be e liminated . Thehigher the level of risk, the higher is the returnon investment d emand ed by investors.

The most critical requirement for nonutilitygeneration projects is the guarantee of stable fuelsupply and pow er sa les contrac ts. Fuel supply,whether it be natural gas, coal, or geothermalbrine, must be assured for the duration of theproject at reasonable, predictable prices. Evenmore important than fuel supply contracts are

power sales contracts with electric utilities. With-out long-term, power sales contracts, project de-—.———

29M. LOtker, “lvlaklrlgthe Most of Federal Tax Laws: A NewWayto Look at WECS Development, ”Alternative Sources of Energy,No. 63, September/October 1983, p. 38.




‘Merrill Lynch Capital Markets,F?oject Financing (New York: Mer- rill Lynch Capital Markets, 1984).

zAlliance to Save Energy, Tbird-l?wtyF inancing: #ncm”ng h@t-ment in Energy-E ficient Industrid Projects (Washington, DC: US.Department of Energy, November 1982), DOEKW24448-T1.

kilowatt-hour sold, will allow investors to calcu-

ual, partnership or corporation, owns thegenw+ation project but is not the ultimateLiset of the power. The SPP may sell theelectricity produced to the local utility orother users, or may lease the generatingequipment itself to a user. The SPP shouldbe able to sell its electricity at high pricesand have sufficient tax liability (usuallydue

A “major reason that limi&i partnerships areattractive ownership options is that tax ben-efits are distributed to partners who can

—.~“lbld,




Another requirement for the financing of newtec hnology projec ts is a suffic iently high rate ofreturn to attract capital. Generally, the nominalinternal rate of return (l RR) for a project must bebe twee n 20 and 30 pe rc ent.31For example, asc an be see n in figure 8-11, windm ills fall be twe enreal estate and venture capital on the investment

risk continuum. Since the IRR is sensitive to taxand financing, an equally important determinantof profitability is cash return on the capital asset.Ca sh return on c apital assets is ob ta ined by re-moving tax benefits and debt and concentratingon the straight c ash-on-cash return. A minimumreq uired c ash-on-ca sh return of 5 perce nt a fteroperating expenses is typical. 32 If debt financingis used, the project must show a favorable debtservice coverage ratio to obtain debt at reason-able terms. Most suppliers of debt capital requireat lea st a 1 .2:1 coverage ratio. 33

31Thi~ nominal range translates roughly into areal IRR range of15 to 25 percent if a 5 percent inflation rate is assumed. Thus, 15percent will be used as the required rate of return or “hurdle” ratein the following analysis.

32R. A. Lyons, “Raising Equity: A Broker-Dealer Guide For theProject Developer, ”Alternative Sources of Energy, No. 69, Sep-tember/October 1984, p. 20.

JJEdward Blum, Merrill Lynch Capital Markets, personalcommu-nication with OTA staff, Aug. 28, 1984.

Figure 8-11 .—Investment Risk Continuum

Certificates Real Windmil ls Ventureof deposit estate capital

Degree of risk

SOURCE: American Wind Energy Association, briefing for congressional com-mittee staff, Washington, DC, Jan. 18, 1985,

Comparative Profitability

The p rima ry basis for cross-tec hnology co mp ar-isons that follow will be the profitability of newtec hnology p rojec ts to b oth institutiona l and in-dividua l investors. The sourc e fo r the t ec hnologycost and performance estimates are the detailedtables included in appendix 8A to this chapter.Cross-technology comparisons based on pro-

jected costs and performance will be presentedfirst, followed by a discussion of the sensitivityto these results to key parameters. AlternativeFederal policy scenarios, e.g., tax policy, will alsobe examined.

The tec hnologies examined in this sec tion w illbe geothermal power, wind power, solar photo-voltaics (concentratorsJa), solar thermal electric,fuel cells, and atmospheric fluidized-bed com-bustion (AFBC). (Integrated coal gasification/com-bined-cycle (lCCC) plants addressed elsewhere

in this assessment will not be included in this anal-ysis because the technology is currently gearedtoward the utility market, and cogeneration-sizedIGCC plants are not expected to be deployed inthe 1990s.) All the technologies listed above areassumed to produce just electricity, except fuelcells and AFBC for which cogeneration applica-tions are examined. Neither of these latter twotechnologies currently qualify as small-power pro-duc ers und er PURPA, and , henc e, were co nfig-ured a s cog ene rators for the a na lysis, Com bus-tion turbine-based cogeneration, currently theprimary technology used in new cogeneration ap-

plications, is used as the conventional alternativeagainst which the new technologies are compared,

Basic AssumptionsComparisons among technologies will be made

prima rily b y a ssessing their brea keven c ost a ndperformance. Breakeven analysis determines thecapital cost and electricity production parame-ters nec essary for a projec t to c over bo th c ostsand req uired return on investment. A stand arddiscounted cash flow methodology was also usedto compare technologies, and check the results

jATrac king concentratorsystems were chosen for the base casenonutility comparison because initial results indicated that they willpenetrate the grid-connected power generation market first withthe highest profit.





236 q New E/ectric Power Technologies: Prob/ems and Prospects for the 1990s

The sec ond ana lysis ap proac h, ca lculat ion ofthe required avoided cost revenue rate, providesa good basis for comparison of cost effectivenessacross the technologies. in addition, the analy-sis can determine whether a new technologyproject will be econom ic with a pa rticular utilityor sta tew ide buy-ba c k rate. Figure 8-13 show s theresults of this analysis with a 15 percent real re-quired rat e o f return (or a pp roxima tely 20 pe r-

cent nominal) and no Renew ab le Tax Credit.These results mirror the results listed above.AFBC, geothermal, and combustion turbines areclearly economic throughout their cost ranges atbuy-back rates above 4 cents/kWh. At its ex-pected cost and performance levels, wind couldbe profitab le a t b uy-ba c k rate s ab ove 6 c ents/ kWh. If w ind p ow er achieves its mo st o ptimisticca pital cost and ca pa city facto r range s, wind



Ch. 8—Conventiona/ v. Alternative Technologies: Utility and Nonutility Decisions q 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




24

22

20

18

16

14

121

10

8

6

Solar

4

2

0Fuel

parabolic cellCombustion

turbinedish

TechnologyNOTE: Assumes 2°/0 real fuel escalation, 1OO /. Investment Tax Credit, 5-year ACRS depreciation, a 50V0 tax bracket, and 150/. real rate of returnSOURCE: Office of Technology Assessment.

c ould req uire o nly a 4 ce nts/ kWh rate. The b rea k-even b uy-ba ck rat e for solar photo voltaics andfuel cells drops below 10 cents/kWh only at theirmost optimistic cost and performance values. Forsolar thermal electric, the breakeven rate is above10 cents/kWh throughout its cost and perform-ance range.

Rate of Return Analysis

In ad dition to brea keven a nalysis, a sta ndarddiscounted cash flow methodology was used toderive profitability, i.e., real internal rate of re-turn. Internal rate of return (l RR) can easily becompared to rates realized by investors, althoughits calculation and interpretation are not withoutproblems. The most serious problem is the sen-sitivity of IRR to changes in the debt structure,

and other financial parameters (e.g., repaymentsched ules, lea sing, etc . ).39 Since no attemp t wa sma de by OTA to structure the financ ing of a g ivennew technology project in order to gain the bestrate of return—the basic cross-technology cashflow model assumes established debt and equityportions for the project, no leasing, and a set Fed-eral tax rate40 —the calculate d rate s of return inthis analysis will be different from and typicallybe low the rates of return ac tually ac hieva ble.

The results of the c om pa ra tive p rofitability ana l-ysis are inc lude d in figure 8-14. Also listed in arethe b ase c ase a ssump tions rega rding ta x rates,

Jglndeed, many analysts place more weight on payback periodsand net present value.

@For the basic comparisons, the tax rate is set at the average Fed-eral tax percentage.



Ch. 8—Conventiona/ v. Alternative Technologies: Uti/ityand fVonuti/ity Decisions 23 9

c

Figure 8-14.—Technology Profitability Range: Nonutility Ownership—West

K“Best case”

“Most likely”

t i$ W o r s t c a s e )

I I

the near future a re expec ted to be developed inthe Sta te. ) The reg iona l fuel pric es we re d erived

This figure shows the attractiveness of AFBC-

from utility-reported data compiled by the Energy ba sed cog eneration. Throughout its expec ted rate

Information Administration .41 The regional asof return range , AFBC is c learly the m ost p rofita -b le new tec hnolog y. These profitability ranges

QITheSe data Were compiled by EIA forOTAon NOV. 27, 1984. also show the potential for solar photovoltaics




and fuel cells to achieve high rates of return 42 un-de r the be st c ase sc ena rio. The c ap ac ity contri-bution and d eployment of these “ clean” tec h-nologies could be sizable if capital costs arered uce d and reliab ility increased for these twotec hnologies. On the othe r hand , if they do not

oc c ur, these tec hnologies do not c omp are asfavorab ly with the other technolog ies and ma ynot b e d ep loyed in significant numbers.

Wind power is currently the major source ofnon utility generation, other than cogeneration.The results shown in f igure 8-12 see m to explainthis market dominance—wind power comparesfavorably with the other technologies. Geother-mal power is also expected to achieve favorablerates of return.

Sensitivity to Uncertainty

The nonut ility profita bility values listed abo veand shown in figure 8-14 were subjec ted to thesame sensitivity analysis framework that was con-ducted on utility Ievelized costs presented earlier.The primary purpose of this sensitivity analysisis to e xam ine the cause of the wide rate o f re-turn ranges shown in figure 8-14 for each tech-nology.

In ge neral, the results of sensitivity ana lyses ofthe key factors—capital cost, O&M cost, capac-ity factor, heat rates, and electric-thermalratio 43 —affecting the profitability of the technol-

ogies indicate that the most critical are: capitalcost, capacity factor, and heat rate. If the non-utility project cogenerates, then the electric-therma l ratio be c om es very imp ortant . The rela-tive importance of each of these parametersvaries according to duty cycle, relative heat rate,and capital intensiveness.

General economic conditions and Federal pol-icies can also significantly affect the profitabilityof non u tility p rojec ts. The sensitivity of the se e c o-nomic factors—avoided costs, fuel costs, fuel costescalations, tax credits, Federal tax rate, debt por-

4ZA 1‘favorable” o r “ sufficiently high” rate of return is assumedto be above a 15 percent real (20 percent nominal) “hurdle rate. ”

qJThe electric-thermal ratio measures the relative production ofelectricity and steam from acogeneration unit. A high ratio indi-cates that the unit produces relatively more electrical energy thanthermal energy.

tion, and debt interest rate–were subjected tosensitivity analysis. The most critical factor wasthe avoided energy cost rate. This is not surpris-ing since the energy credit is the major sourceof revenue for nonutility technology projects.Next in importance are the Federal tax credit

(both investment and energy credits), the Federaltax rate, and avoided capacity credits. As was in-dicated by the relatively high sensitivity to heatrates, relative fuel costs are also important for fuel-intensive technologies such as combustion tur-bines. Sensitivity to tax credits is examined fur-ther below.

These results highlight three main factors thataffect the development of new generation tech-nologies. First, policies geared toward increasingreliability and availability, lowering initial capi-tal costs, and increasing efficiency (e.g., heat rate)will have the greatest impact on the future mar-ket p ote ntial in the no nutility sec tor. Sec ond , lo-cating a project in a region or State with highavoided costs is crucial to project profitability. Fi-nally, Federal tax policy can significantly affectchanges in the profitability of non utility projects.

Sensitivity to Federal Tax Policy

The existenc e of Fed eral ta x benefits for renew-able energy projects has been instrumental in thedevelopment of the current nonutility industry.Both the nonutility IRRC survey and the previoussensitivity analysis resuIts emphasize the impor-tance of Federal tax credits. Not too surprisingly,the respo ndents to the IRRC survey ad voc atedtheir continued existence. AA

Federal tax treatment of non utility investmentis currently in flux. The current business energycredits are due to expire on December 31, 1985.Failure to extend these c redits will ma rked ly re-duc e p roject p rofitab ility and probab ly c ause a nindustry shake-out. In ad dition, the Treasury De-partment has proposed a massive “tax simplifi-cat ion .“ This proposal, among other things,would, if enacted, repeal the 10 percent invest-

ment Tax Credit.

wThe 1 RRC survey was discussed i n greater detail earlier in thissection.



Ch. 8—Conventiona/ v. Alternative Technologies: Utility and Nonutility Decisions 241

These ta x po lic ies we re ana lyzed with the OTAcash flow model. Cross-technology profitabilitywas

1.

2.

3.

4.

5.

calculate d fo r five ta x polic y alternatives:No Ta x Inc entive s–No tax credits, and 15year SOYD45 depreciationACRS Depreciation–No tax credits, 5-yearACRS dep rec iationInvestmentTa x Crec / it-Sam e a s (2), with 10percent ITC10 percent Renewable Tax Cred it—Same a s(3), with 10 percent RTC15 percent Renewable Tax Cred it—Same a s(3), with 15 percent RTC.

Case 5 represents current policy. Table 8-1presents the results of this analysis. Figure 8-15graphically shows the change in profitability(cumulative) upon stepping through the fivecases. As can be seen, profitability changes dra-

ma tic ally a mong the five p olic y c ases. Unde r themost likely case scenario, if a 15 percent real rateof return (20 perce nt nominal) is assume d to b ethe hurdle rate, AFBC and combustion turbineunits a re likely to be ec ono mic under the No TaxIncentive case. Inclusion of a 5-year ACRS allowswind po wer to bec ome ba rely profitable. TheRenewab le Tax Cred its cause a dramatic increasein profitability. For example, wind powerachieves a real rate of return in excess of 25 per-c ent with a 15 percent ta x credit. Geotherma lpower also is economic with its 10 percentRene wa ble Tax Cred it. The o ther new renewa b le

tec hnologies–pho tovo lta ic s and solar therma l–a lso b ene fit from the Rene wa ble Tax Cred its, butremain the technologies with the lowest IRR.

q5sUm o f years Dlglts.

Summary

Generation of electric power by nonutility en-tities has become an important alternative to elec-tric utility power generation. The existence of awide va riety o f ma rkets and interested investorsoutside electric utilities increases the likelihoodthat m any of the new tec hnologies c onsideredin this study will be deployed. OTA analysis oftechnology profitability indicates that wind powerand AFBC-based cogeneration compete favora-bly with conventional technology–combustionturbines—under expected conditions. Because ofcurrent and expected profitability, the commer-c ialization of wind p ower techno logy has goneforward. And investor interest in AFBC shouldspeed its commercialization as well.

Our analysis shows that the renewable energytax credit coupled with recovery of full utilityavoided costs by non utility power producers havebeen crucial in both the initial commercial de-velopment and the deployment of the new gen-erating tec hnologies. Should a voided c ost ratesbe low or uncertain, their development and ap-plication will be retarded. Conversely, highavoided costs, stimulated perhaps by rising oiland gas prices or shrinking reserve margins, mightsubstantially accelerate their deployment. In ad-dition, without continued favorable tax treatment,development of much of the domestic renewablepo wer tec hnology industry will prob ab ly be de -layed significantly. In p articular, without existingtax inc entives, ma ny of the sma ll firms involvedin development projects will lose access to ex-isting sources of capital. Even large, adequatelycapitalized firms may lose their distribut ion ne t-works, leaving the industry struggling to survive.

CROSS-TECHNOLOGY COMPARISON

Overview cannot be addressed in a cost or profitability anal-ysis. 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 com-tec hno log ies c overed in this a ssessme nt. The e m- parisons in this section are based on informationphasis in here will be on the nonquantifiable conta ined in chapters 4, 5, 6, and 7, along withcharacteristics of the technologies, i.e., those that previous sections in this chapter.




Table 8-2.—Alternative Tax Incentives: Cumulative Effect on Real Internal Rate of Return

Real internal rate of return (percent)Photo- Wind Solar Fuel Combusti on Atmospheri c

Tax incentive Geothermal voltaics turbines thermal cells turbine fluidized-bed




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 focusedon the relative c osts and profitability of the de -veloping technologies. Usually, most utilities andinvestors p lac e the g reatest emp hasis on thesemonetary values when making investment deci-sions. Nevertheless, a host of additional issues canaffect and, in some cases, determine the choiceof electric power technology. These issues in-clude environmental impacts, fuel availability,and mo du larity, am ong othe rs. Tab le 8-3 disp laysa variety of quantitative and nonquantitative char-acteristics of the technologies under consid-erateion.

The m ost striking a spec t o f this ta b le is the widevariation in the cost, performance, resource, andenvironmental attributes evidenced by the differ-ent tec hnologies. The ne w tec hnologies vary fromsmall, short lead-time technologies such as wind

power to large, longer lead-time technologiessuch as IGCC; from capital-intensive, less mature

technologies like fuel cells to low cost per unitpower, commercial technologies such as geother-mal; and from site-specific technologies such asgeothermal to more easily sited technologies suchas photo volta ics. This va riation amo ng the te c h-nologies makes easy classification of the technol-ogies difficult. Trad e-offs be tween imp ortant char-ac teristics suc h a s cost, environmenta l imp ac ts,and lead-time must be made prior to selectionof a pa rticular technology. Nevertheless, a fewinsights concerning these cross-technology issuescan 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, thepotential environmental impacts from these tech-nologies are significant. AFBCS and IGCCS requiresizab le qua ntities of w ate r and land , produc e sig-






nificant amounts of solid waste, and emit air pol-lutants. The lat ter, however, can be controlledbe low c om pe ting, solid fuel tec hnolog ies. Theseenvironmental characteristics will likely limit thedeployment of these technologies to remote ap-plications outside of urban areas, possibly tononattainment areas (u n less emission offsets areavailable). While these technologies have greaterenvironmental consequences than the other newtechnologies, the IGCC and AFBC represent twoof the most promising ‘‘clean coal” technologies.Therefore, when com pa red to c onventional coa lcom bustion, the IGCC and AFBC offer substan-tial environmental benefits.

Second, in general, the renewable technol-ogies—geothermal, wind power, solar photovol-taics, and solar thermal electric—have less severeenvironmental impacts than conventional gener-ation a lternatives. This a ttrac tive environm entalcharacteristic in combination with the small, mod-ular nature of most of the renewable technol-ogies, should ease siting of these technologies andaid d ep loyment. There are important d ifferenc esam ong these te c hnologies, though, in terms oftheir environmental impacts. Geothermal and, toa lesser extent, wind power create more environ-ment impacts than solar photovoltaics and solarthermal electric. For example, wind power instal-lations are highly visible, noisy, require largeamounts of acreage, and can cause erosion prob-lems in environmentally sensitive areas.

Finally, the two technologies which appear tobe the most desirable according to the charac-te ristics listed in table 8-3 are fuel ce lls and sola rphoto volta ics. These tw o te c hnolog ies are sma ll,modular technologies which can be sited in a va-

riety of locations without major environmentalimpact in relatively short periods of time. Photo-voltaic powerplants use a fuel that is inexhausti-ble (solar insolation), while fuel cells can use avariety of fuel types (natural gas, methanol, syn-thetic na tural ga s). In the c ase o f these tw o te c h-nologies, therefore, c ost a nd pe rformanc e w illalmost completely determine their market pene-tration.

Summary

Choice among the new technologies involvesmore than just comparison of costs or profitabil-ity. At the mic ro level, this de c ision is based onvery detailed analysis of engineering, and costanalyses, site-spe c ific cha rac teristics, a nd envi-ronme ntal impa c ts, amo ng o thers. At the mo regeneral level, the approach taken here, the tech-nologies must be compared with each other, bothin relation to their quantifiable and their non-quantifiable values.

This sec tion has highligh ted the c om p lex issuesassociated with deployment of the new technol-og ies. Com plicated variat ions exist a mong thetechnologies in terms of their cost, lead-time, andenvironmental impacts. On one hand, AFBC andIGCC are very co st c ompe titive, but their longlead-times and their relatively large impacts onthe environment could make AFBC and IGCChard to site. On the other hand, flexible, relatively

benign technologies like fuel cells and photovol-ta ic s are c urrently too c ostly to b e d ep loyed inlarge numbers. Actual technology choice will de-pend on specific utility concerns and circum-stances.

CONCLUSIONSNew electricity-generating technologies have AFBC and wind power, are in later stages of com-

the potential of being competitive with traditional mercializat ion, and could p rovide lower cost ortechnologies, 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 suchof the new technologies, specifically, small-scale as fuel cells and photovoltaics are uncertain. Al-




though these technologies are potentially com-petitive, uncertainties surrounding their cost andperformance will slow deployment.

A wide variety of cost-effective strategic optionsare also available to electric utilities. These op-tions include plant betterment and life extension,

load management, and interregional power pur-chases. OTA ana lysis indica tes that t hese op tionsare extremely competitive with the traditionalgenerating technologies, and are less costly than

the new technologies. Consequently, utilities willprob ably conc entrate o n these op tions p rior toextensive d ep loyment of the new, d evelopingtechnologies.

Investment decisions concerning the new tech-nologies will reflect more than just cost compar-isons. A variety of nonquantitative characteristics,particularly modularity and the level and type ofenvironmental impact, will influence investmentdecisions.

APPENDIX 8A: INVESTMENT DECISION CASH FLOW MODELSFOR CROSS-TECHNOLOGY COMPARISONS

Introduction

This append ix desc ribes the ana lysis me thod-

ologies adopted in this assessment for: 1 ) utilityIeve lized busba r co st c a lc ula tions, and 2) non-utility profitab ility mea sureme nt. These method -ologies are the ba sis for the c ost a nd profitab il-ity estima tes provided in chapter 8. The a na lysisap proa ch in these m od els is a mo d ified versionof the Alternative Generation Tec hnolog ies mod eldeveloped by Battelle Columbus Laboratories. 1

The m od ific ations ge nerally a llow the m od el tomore accurately calculate electric utility revenuerequirements and nonutility profitability meas-ures. The e stimat es prod uc ed by the se c alc ula-tions c an be c omp ared with utility-rep orted c osts

and nonutility-reported rates of return.

Electric Utility Levelized Busbar Cost

Since electric utilities are regulated, utilityshareholders receive a set return on their invest-ment. The revenue nec essary to prod uc e this setincome, often termed the revenue requirement,includes three major components: capital costcarrying charges, interest charges, and fuel andoperating expenses.

‘ Battel Ie Columbus Division,Fina/ Report on Alternative Gener- ation Technologies, Nov. 18 , 1983 (Columbus, OH: Battelle, 1983).

Capital Cost Carrying Charges 2

The c harge s assoc iated with a capita l invest-ment can be split into three basic categories: 1 )depreciation, 2) return, and 3) income taxes asso-c iate d with the investment.

An annual revenue stream is required to re-cover the initial capital cost of a new electric gen-eration facility. Book depreciation is the mecha-nism used to generate the funds needed for thiscarrying charge component. Book depreciationin year i (Dbi) is defined as

[1]

where I is the total capital cost of the facility (in-

cludes Allowance for Funds Used During Con-struc tion) and nb is the book life in years. Accu-mulated bo ok de preciation in year i (Cbi) is thesum of all the previous years’ depreciation, i.e.

(–1C b , = ,~, D b, [2]

The electric utility also earns a return on theinvested capital. The return on c ap ital in yea r i(Rl) can be found by multiplying the requiredrate of return k by the remaining undepreciatedbo ok va lue o f the fac ility. (The req uired rate of

2 This section draws heavily on Peter D. Blair, Thomas A.V. Cas-sel, and Robert H. Edelstein,Geotherrna/ Energy: /nvestrnent De- cisions and Commercial Development (New York: John Wiley &Sons, 1982) and Philadelphia Electric Co.,Engineering Economics Course (Philadelphia, PA: Philadelphia Electric Co., January 1980).




Figure 8A-1 .—Calculation of Capital Cost perKilowatt-Houd

180

160 - ? 5 %

140 “120 -

100 -

80 -

60 —

40 -

20

00 2 4

The third compo nent o f cap ital cost c arryingcharge is the income tax liability associated withthe p rojec t. The to ta l tax liab ility in yea r i c an bedetermined by multiplying taxable income by thecompo site ta x rat e t. The c ompo site tax rat e (t)is a w eighted combination of the Sta te ta x rat e(tsand Federal tax rate (t,):

t = t, + tt(l – t,)Tota l taxable incom e is found by d ed uct ing

debt interest (Kl) and ta x dep rec iation (Dti) ca l-

culated from the accelerated depreciation sched-ules,3from the revenues received4:T, = t(Db , + R, + T, – Kdl – Dt,) [4]

The c a lculation of tax liab ility is com plica ted ,however, by the use of accelerated depreciation.The use of ac c elerate d d ep rec iation proc ed ures

[8]




ment of an electric utility, which often computesFCRs for inte rnal p lanning purposes. While the reis no fundamental difference between Ievelizedbusbar costs calculated by either method, themethodology presented herein more easily cap-tures significant revenue requirement differenceson a yea r-by-yea r basis. Moreover, this me thodis more flexible in handling different equipmentlifetime s, ACRS c at eg ories, and levels of c ap italintensiveness associated with alternative tech-nologies.

Nonutility Profitability

Consistent cross-technology financial compar-ison for non utility electricity producers is bestachieved with profitability measures. AlthoughIevelized cost values are perhaps convenient forcomparative purposes, the financial communityge nerally uses profitab ility measures (rate of re-turn, payback period, and net present value) forinvestment decision making purposes. Measure-ments of no nutility p rofitab ility ca n b e de rivedin a more straightforward fashion than utility rev-enue requirement estimation—since nonutility in-come and taxation calculations are not compli-cated by tax normalization and regulated returnadjustments.

The analysis technique a dop ted for the proj-ec t is the standa rd d iscounted cash flow meth-odology accounting for the three major compo-nents of nonutility cash flows: revenue, operating

costs, and after tax income. The various profit-ability measures are calculated based on after taxcash flow.

Revenue

The revenue ac hieva ble from a new te c hnol-ogy project is assumed to be based primarily onprevailing utility avoided cost rates. Avoided costrevenue in year i (AR,) is based on both avoidedenergy and avoided capacity credits:

AR, = 8760AEiCFIC + ACIIC [15]

where AEI($/kWh) and AC, ($/kW) are theavoided energy value and avoided capacityvalues, respectively, in year i (determined by ap-plying a n assumed escalation to the b ase yea rvalue), CF is the capacity factor, and I C is the in-



Ch. 8—Conventional v. Alternative Technologies: Utility and Nonutility Decisions Ž 249




mee t when m aking new investment d ec isions. positive returns after discounting for the timeThe length of the p rojec t’ s pa yba ck period , the value of m oney, and 2) the relative level of in-number of years necessary for project revenues come provided by the project. All of these toolsto payback the initial outlay, is also used as a can be used to compare alternative investmentscreening tool. Net present value provides infor- projects.ma tion on: 1 ) whethe r the projec t will provide



Chapter 9

The Commercial Transition forDeveloping Electric Technologies



CONTENTSPage

Overview . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ....285GoalA: Reduce Capital Cost Improve Performance, and Resolve Uncertainty. . ......286Go al B: Enc ourage Nonutihty Role in Comm erc ializing Deve lop ing Tec hnolog ies .. ...290Go a lC: Enc ourage Inc reased Utility Invo lvement in Develop ing Tec hno logies. . ......295Goal D: Resolve Concerns Regarding lmpact of Decentralized Generating

Sources on Power System Operation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ... ... ...299

List of TablesTable No. Page 10-1. Policy Goals and Options . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..................28510-2. Alte rnative Tax Inc ent ives: Cumulat ive Effec t o n Rea l Inte rnal Rate of Return ....293

List of FiguresFigure No, Page 10-1. Tax incent ives for New Elec tric Genera ting Tec hnologies: Cumula tive Effec t

on Real Internal Rate of Return. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..291IO-2. Breakeven Utility Buy-Back Rates . . . . . . . . . . . . . . . . . . . . . ...................292



Chapter 9

The Commercial Transition forDeveloping Electric Technologies

INTRODUCTIONThis c hapt er d isc usses pa st d eve lopm ent of t he

electric generating and storage tech nologies ex-amined in this assessment, and discusses theircommercial outlooks. Factors which constituteserious impediments to widespread commercialdeployment in the 1990s–assuming a demand for additional generating or storage capacity’ –

are identified. Deployment levels will depend ona combination of changes in cost, performance,uncertainty, and other changes i n the com mer-c ial environme nt within which the te chnologiesare developing.

‘This assumption IS an important one, as a general lack of de-mand for additional generating capacity could itself constitute themajor impediment to the deployment of the technologies in the1990s.

STATUS AND OUTLOOK FOR THE DEVELOPING TECHNOLOGIESSolar Photovoltaics

History and Description of the Industry

Photovoltaic cells (PVs) first were developed inthe 19th century. In the 1950s and 1960s, a com-bination of technical breakthroughs and the needto power spacecraft stimulated substantial costreductions, performance improvements and widerapplications. During this period, Federal support,channeled primarily through the space program,was the dominant stimulus to the technology’sprogress.

In the 1970s PVs entered larger terrestrial mar-kets, the most important of which was power gen-eration in remote locations. A notable trend dur-ing the 1970s was the growing support for PVsby large petroleum-based co mp anies and theFederal Government. In 1978, Federal supportwas solidified by the passage of several key lawswhich provide for a program of research, devel-

opment, and demonstration and for direct Gov-ernment purchase of large numbers of solar cells. 2

‘The most important laws were: 1 ) the FederalPhotovoltaic Utl -Iization Act of 1978 (Public Law 95-619, Part 4); 2) the SolarPhoto-voltalc Energy Research, Development, and Demonstration Act of1978 (Public Law 95-590); and 3) the Department of Energy Actof 1978 (Publtc Law 95-238, Section 208).

From 1980 to 1985, about 30 laboratories acrossthe country were conducting PV research.3By1985, the price of PV modules decreased 80 per-cent (in constant dollars) from $35,400/kWe in1976 to $7,000/kWe in 1984; performance alsoimproved ma rked ly. The vo lume of sales increasedrapidly as world PV shipme nts increased ove r ahundredfold from 240 kWe in 1976 to 25,000kWe in 1984. Total revenues increased twenty-fold, from $6.8 million to $174 million during thsame period. Q

In the 1980s the PV industry changed consider-ably. By 1985, the industry consisted mainly ofcompanies which were affiliated withlarge mu 1-tinational petroleum-based corporations. By theearly 1980s, many companies sought to concen-trat e the ir op erations towards the raw ma terial

3Larry N. Stoiaken, “A New Generation ofPhotovoltaics. Com-mercialization EffortsGain Momentum, ’Alterna t ive sources of

Energy, vol. 67, May/June 1984, pp. 6-15.4See: 1 ) Strategies U n I i m ited,Arta/ysls of Equipment A4anufac-

turers and Vendors In the Electric Power Industry for the 1990s.Wi n d Turb/nes, Solar Thermal Electric,Photovoltaics (MountainView, CA: Strategies Unllmi ted , December 1984), OTA contractorreport. 2) Pau I D. Maycock and Vic S.Sherlekar, Photovo/taic Tech- nology, Performance, Cost and Market Forecast to 1995. A Strate- gic Technology & Market Ana/ysis (Alexandria, VA:PhotovoltalcEnergy Systems, Inc., 1984).

253




end of the production process, emphasizing cellor module production. At the other end of theproduction chain, however, decentralization oc-curred, i.e., companies sold off or closed downop erations involving other system compo nentstha n the PV a rrays them selves. As the tec hnol-ogies developed and market prospects changed,businesses also shifted emphasis among the differ-ent PV systems.

The market during the first half of the 1980sis depicted schematically in figure 9-1. During thispe riod the United Sta tes do minated world pro-duc tion, with Jap an ranking a distant sec ond . Theend-use markets for 1984 are broken down intab le 9-1. The ta ble highlights the imp ortanc e o fthe U.S. ce ntral sta tion ma rket b oth a s a frac tionof the U.S. ma rket and of the w orld ma rket. Theapplication of the Public Utility Regulatory Pol-

Figure 9.1 .–1984 World Photovoltaics Supply

I United States I I Europe I I Japan I Other

I World production1

18.5 MWpSOURCE: 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 q 255

Table 9.1 .—Estimated Magnitude of End”Use Marketsfor Photovoltaics, 1984

MWe(p) shippedMarket sector worldwideWorld consumer products. . . . . . . . . . . . 5U.S. off-the-grid residential . . . . . . . . . . . 2World off-the-grid rural. . . . . . . . . . . . . . . 0.2

Worldwide communications . . . . . . . . . . 5Worldwide PV/diesel . . . . . . . . . . . . . . . . 2U.S. grid-connected residential . . . . . . . 0.1U.S. central station and third-party

financed projects . . . . . . . . . . . . . . . . . 10

Total MW . . . . . . . . . . . . . . . . . . . . . . 24.3Japanese grid-connected. . . . . . . . . . . —

Total MW . . . . . . . . . . . . . . . . . . . . . . 25Price ($/Wp) . . . . . . . . . . . . . . . . . . . .Revenues ($ M) . . . . . . . . . . . . . . . . . $175

SOURCE Paul D Maycockand Vic S. Sherlekar,Photovo/faic Technology, Per- formance 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 Federaland Sta te (espec ially Ca lifornia ) tax po lic ies wa svery important in enco urag ing the d eploymentof photovoltaics in these facilities.

Federal support for photovoltaics during thefirst half of the 1980s shifted considerably in em-phasis. Direc t expend itures in support of photo-voltaics declined in importance after peaking in1980-81, but they continued to have a substan-tial effec t on the d evelopment oft he tec hnology(see table 9-2). While the Federal Governmenthas concentrated on high risk research and de-

Table 9-2.—Federal Program Funds in Support

velopm ent (R&D) with p otentially high p ayoffs,some direct support was provided elsewhere. Ex-port promotion was recognized as an importantelement in any program to encourage photovol-taics and assumed a more prominent positionamong Federal efforts in the 1980s. The Federal

Gove rnment a lso c ontinued to supp ort a ma jordemonstration project in California. As direct Fed-eral support declined, indirect support for photo-voltaics through tax incentives increased duringthis period and strongly influenced the rate ofprogress in the industry.

Industry Outlook and Major Impediments

The 1990s likely will witness rapid growth inthe application of hybrid photovoltaics/dieselpower systems in remote areas, primarily over-seas. Indeed, this market could dominate worldPV deployment during the p eriod . Also very im-po rtant will be g rid-connec ted PV plants in theUnited States and in Jap an. At the sam e time, theworldwide communications and consumer-prod-uc ts ma rkets wiII continue to be of m ajor signifi-canc e to the industry. The mag nitude and rela-tive importance of different market segments, andthe character of the industry itself, will dependheavily on whether or not the Federal Renew-able Energy Tax Cred it (RTC) is extend ed beyo nd1985. The exac t effec t of either ac tion, howe ver,is diffic ult to ac curate ly pred ict.

of Developing Technologies (millions of dollars)

Year1986

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 29.1Photovoltaics . . . . . . . . . . . . . . . . . . 5.2 21.6 59.7 76.2 104.0 150.0 152.0 74.0 58.0 50.4 57.0Solar thermal . . . . . . . . . . . . . . . . . . 13.2 20.6 79.1 114.7 109.3 135.0 120.0 56.0 50.0 43.9 35.5Geothermal. . . . . . . . . . . . . . . . . . . . 28.0 78.3 76.7 132.9 188.4 171.0 156.3 86.6 73.6 30.5 32.1AFBC . . . . . . . . . . . . . . . . . . . . . . . . . 2. 0a 7.0 21.2 24.5 23.6 25.9 11.4 0.3 4.9 1.4 18.7Surface coal gasification

(includes IGCC) . . . . . . . . . . . . . .116.3 117.7 143.2 208.2 122.4 123.3 70.0 54.2 39.0 36.5 32.0Fuel cells c . . . . . . . . . . . . . . . . . . . . n/a 3.0 17.8 33.0 41.0 26.0 32.0 34.5 29.9 42.3 40.8Batteries d . . . . . . . . . . . . . . . . . . . . . 2.9 6.8 9.7 11.2 15.3 20.3 13.9 12.9 12.8 12.8 8.4CAES . . . . . . . . . . . . . . . . . . . . . . . . . 0.0 0.6 1.2 4.5 4.5 3.2 2.1 2.0 0.0 0.0 0.0

20.844.828.412.017.3

15.09.36.30.0

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%T A estimate.bDoes not include support from the SyntheticFIJ@lS CorP.clncludes funding for all fuel cells R&D and is not restricted to phosphoric acidfuel cellsdThe funding levels listed are the estimated levels of suppo~ for all stationary batteries, including but not restricted to Iead-acid batteries andzinc-chlorlde batteries.

The estimates assume that roughly 50 percent of the funding for DOE’s Electrochemical ProgramIS applicable to stationary batteriesSOURCE U S Department of Energy,Congressional/ 8udgef Request” H’ 7986 (Washington, DC” U S. Government Printing Office, 1985) and the corresponding docu-

ments fo r prevelous years






The c umulat ive .effec t o f extension o f the RTCon market size and distribution could be consid-erable. Virtually all market segments would belarger, some considerably more important thanthey otherwise might be. Dramatic growth couldoccur in the volume of sales of photovoltaics foruse in PV/diesel hybrid systems in remote over-seas applications. This market qlJickly couldcome to dominate the international PV market,The U.S. central station market would also bemuch larger.

Extension of the RTCs also will affec t therela-tive importance of differentPV designs. Rapidgrowth in the deployment of concentrate sys-tem s could b e stimulate d , along with o ther sys-tems that are favored in central station appli-cations.

Continuation of Federal tax support also couldstrengthen the position of U.S. manufacturersover foreign compe titors—both here and over-seas. Overseas competitors, especially the Japa-nese, are moving rapidly ahead in PV—often withthe suppo rt o f the ir go vernments. Tax cred it sup -port c ould serve to slow the erosion of the U.S.position in the industry and perhaps even reversethe trend.

While the issue of the RTC dominates currentdiscussion of the outlook for the photovoltaicsindustry, a broad range of other factors will af-fec t the prospe c ts for photo voltaics during the1990s. These are discussed below.

Equipment Cost and Performance. -If PV sys-tems in the 1990s were identical to those avail-able today, they probably could not compete ex-tensively and successfully with the alternatives inU.S. grid -co nnec ted app lic a tions. Current leve lsof cost and performance are too high. Invest-ments in both R&D and in industrial capacity toma ss produce the t ec hnology will be required .The p resent sta tus of the t ec hnolog y and thec hang es nec essary for extensive c om mercial a p-plication in the 1990s are discusred in chapter 4.

The Risk of Ob solescenc e.–The tec hnolog iesof p hoto volta ics are evo lving rapidly. This rap idrate of change may discourage would-be inves-tors from investing in production lines out of fearthat their investments could quickly become out-dated in the event of technological breakthroughs,

Some industry observers think that this is the rea-son the U.S. industry has been reluctant to investin the fac ilities necessary to m ass produc e c rys-talline silicon modules. Instead, it largely hasopted for the longer term payoff which might beobtained from the less mature amorphous silicontechnology. Should progress in the amorphoustechnology prove slower than expected, the rela-tive lack of emphasis in the U.S. industry on com-mercial production of crystalline silicon may de-lay commercial deployment of photovokaics, andforeign competitors, most likely the Japanese,may seize the opportunity to increase their mar-ket sha re by selling c rysta lline silico n mod ules inthe United States and ab roa d.8

Solar Resource Assessment.—The currentknowledge of the solar resource in the UnitedStates is insufficient for the optimum design andsiting of PV plants. The best available informa-tion is the SOLMET data , ba sed on severa l yea rsof readings at 26 sites.9The SOLMET data givesmonthly averages of solar insolation for each hourat typical geographic locations.

While such figures are useful for calculatinggeneric capacity factors and peak system outputsfor a particular region, the characteristics of a par-ticular site may be significantly different than theaverage. Before utilities can integrate photovol-taics into their operations, they must have adetailed understanding of PV operating dynamics,based on a minute-by-minute understanding of

the insolation patterns at a site.10

Also, to op timize the design o f PV mod ules, itwill be necessary to understand much moreabout the detailed spectral and directional dis-tributions of light energy as a function of time-of-da y and da y-of-the-year. Suc h information notonly influences the decision of whether or nottracking systems are cost effective, but it also af-fects the detailed design of the cells, since the

‘Roger G. Little, President, Spire Corp., testimony presented inhearings held by the Subcommitteeon Energy Development andApplications, 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. GovernmentPrinting Office, 1984),No. 106, june 6, 7, and 13, 1984, pp. 386-389.

9Roger Taylor, Photo~’o/talc Systems Assessment: An /ntegratedPerspective (Palo Alto, CA: Electric Power Research Institute, Sep-tember 1983), EPRI AP-3176-SR.

IOlbid.




light absorption and current carrying capacity ofthese cells must be carefully matched to the so-lar spectrum.11

Cost and Performance Data.–A serious ob-stac le to t imely de ployment of photovo ltaics inany application is the lack of accurate and use-

ful information about the technology and its eco-nomics. What are the specific capital costs of aspecific PV system? How will it perform at a spe-cific locality? What kinds of operating and main-tena nc e expenses might be incurred ? This prob -lem a lrea dy ha s be en a n ob stac le in oversea sap plicat ions where investors often do not knowenough about PV cost and performance or lackthe analytical means to adequately compare pho-tovoltaics to conventional alternatives .12

Standards.–The lack of standard definitions,testing methods, and other criteria relating bothto PV modules and balance of system equipmentrepo rtedly has hindered d evelopment a nd de-ployment. it is thought by some tha t the ap pli-cation o f standa rds ultima tely will expe dite thec omm ercial ap plic ation of the tec hnology. Sev-eral groups are working on such standards,though who should set and enforce them is amatter of considerable controversy within the in-dustry.

Warranties.–The extent to which warrantiesare a vaiIab le, and the na ture o f suc h wa rranties,will strongly affect the commercial success of PVsystems in the 1990s. It was not until late 1984that anyone in the industry offered even a limitedwarranty and an Underwriters Laboratories list-ing for a PV module.13Vend ors wiII be reluctantto provide strong extended warranties until thetechnology has been adequately proven in realconditions. This requirement likely will put rela-tive newcomers such as amorphous-silicon mod-uIes at a disadvantage until sufficient experience

—.—110TA staff interview withCharles 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 onScience and Technology, U.S. Congress, Hearing on the CurrentState 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.14The a bility to provide e xtend ed wa r-ranties will be influenced greatly by the amountof capital available to the industry, which in turnwill depend on market size and profit margins.

Utility Energy and Capacity Credits, and in-terconnection Requirements.—Grid-connected

PV plants can be owned by utilities or by others.As discussed earlier with wind systems, low energycredits, low capacity payments, and stringent in-terconnection requirements discourage deploy-ment by nonutilities. Even where the possibilityexists tha t c redits couId d rop d uring the lifetimeof a project, investment is discouraged. Also, anydifficulties (such as delays) encountered in seek-ing to obtain favorable credits or interconnectionrequirements discourages nonutility deployment.

Overseas Markets.–Overseas markets willserve to enc ourag e m ass produc tion of PV sys-tems and hence lower costs. The larger marketalso will serve to indirectly stimulate technical de-velopment which could lead to further reducedcosts or improved performance. As a result ofsuch improvements the exploitation of overseasmarkets could help ensure that U.S.-made sys-tems remain competitive in the domestic market.

Current evide nc e sugg ests tha t the U.S. pho to-voltaics industry is not as successful as it couldbe in overseas markets; as mentioned earlier, thesituation will be exacerbated with the scheduledtermination of the renewable energy tax credits.Meanwhile, competitors–especially the Euro-peans and the Japanese–are more actively andsuccessfully developing these markets, often sup-ported by favorable government programs. Fail-ure to fully exploit export markets could slow thede velopm ent of U.S. pho tovo lta ic s, extend theperiod required before extensive grid-connectedapplications will occur, and increase the likeli-hoo d t ha t large seg me nts of the U.S. ma rket w illeventua lly b e served by foreign vend ors.

14’’lntense Competition Among Five Silicon Technologies Seenfor PV : Maycock, ”Solar Energy Intelligence Repoti, Apr. 2, 1984,p. 110.




Solar Thermal Electric Plants


By 1879, the French had converted solar radi-ation into thermal energy and produced smallquan tities of e lec tric po we r. Thoug h this wo rk ledto the operation of several demonstration units,the devices proved to be prohibitively expensiveto build and operate, and the idea of producingelectric power from solar thermal energy waslargely abandoned. Not until nearly 100 yearslater was hea t d erived from the Sun widely c on-sidered as a means of producing electric power.

A variety of solar thermal electric technologiesare now being developed. But as discussed inchapter 4, their current status and prospects dif-fer substa ntially. The solar po nd t ec hnolog y fac esmany limitations that make widespread commer-c ial ap plica tion w ithin th is c entury unlikely. Theprospe c ts for three o ther tec hnologies–centralreceivers, parabolic troughs, and parabolic dishes

—are bright er. The histo ries of these te c hno log iesin the United States have be en shap ed by theFed eral role in the ir deve lopm ent. Their prospec tsin the 1990s likewise probably will also dependheavily on Federal activity between now and theend o f the ce ntury.

Direct Federal sponsorship of the technologiesrose rapidly in the 1970s, spurred by the desireto develop technologies which were less vulner-able to fuel disruptions and price increases, and

which had less severe environmental impactsthan many conventional technologies. But directFed eral supp ort ha s dec lined from $135 millionin 1980 to less than $36 million in 1985 (see ta-ble 9-2). The imp ac t of t he d ec line w as offset inpart by an increase in indirect support in the formof tax incentives during the first half of the 1980s.The e ffec ts of c onservation, whic h mo de rate dconventional fuel prices, also dampened theprospec ts for near term-c om me rcial success.

During the latter half of the 1970s and the early1980s, the central receiver technology progressedrapidly, culminating in 1982 with the operationof a 10 MWe p ilot p lant, the Solar One p ilot fa-

I Jl(en Butti and John Perlin, A Go/den Thread (New York: vanNostrand Reinhold Co., 1980).

cility. Eighty percent of that project’s costs werepaid by the Department of Energy (DOE). Theplant, while no t of c ommercial scale, has op er-ated quite suc cessfully.

Private sector involvement in the central re-ceiver technology has primarily involved electric

utilities as well as equipment developers and ven-dors. These a nd other priva te inve stors, however,have been unwilling to invest in a commercialplant without Government subsidy, until they hadevidenc e of a successfully op erating c lose-to-commercial unit. Yet neither the private nor pub-lic sec tor pa rticipant s, alone o r in c oope rationwith each other, have been willing to finance acommercial demonstration unit. Various partieshave sought ways around this impasse; othershave disbanded and moved away from the tech-nology, assuming tha t the c ombined effec ts ofFederal spending cutbacks, the impending expira-

tion of the renewable energy tax credits, andother factors preclude extensive commercial de-ployment in the near term.lb By mid-l 985, workon the central receiver technology was confinedprima rily to fede rally supp orted resea rc h a nd de -ve lop me nt a t DOE’s Ce ntra l Rec eive r Test Fac il-ity and on fed erally funded efforts at the SolarEnergy Research Institute to develop low cost anddurable heliostats.

The parab olic troug hs, meanwhile, prog ressedmuch further into the market place. By the early1980s, the Federal Government had funded nearly

a dozen experiments and demonstrations. Thetechnology had reached the point where it wasnearly rea dy for co mm ercial app licat ions.

The relatively short lead-time of the technol-ogy allowed the Luz Engineering Corp. to initi-ate two projects which could be completed soonenough to exploit the Federal renewable energytax c red its even if they expired as planned at theend of 1985. Bec ause the projec ts we re in Ca li-

lbThe central receiver teams at Martin Marietta, Boeing, Rock-well, and to a large extent McDonnell Douglas are being disbanded.In addition, the government and utility support teams atSandia

Livermore,Sandia Albuquerque, Jet Propulsion Laboratory and Elec-tric Power Research Institute also are being disbanded and the per-sonnel 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 Elec- tric, Photovo/taics, op. cit., 1984).



260 q New Electric Power Tec hnolog ies: Prob lerns and p rospec ts for the 1990s

fornia, the y c ould a lso e njoy Sta te t ax ince ntives,favorab le solar insolat ion levels, and high utilityavoided co st energy pa yments. I n Dece mb er1984, the first of the two plants, known as SolarElec tric Ge nerating System-1 (SEGS-1) and c apa -ble of producing 13.8 MWe, had begun operat-ing. By Feb ruary 1985 construct ion of a sec ond33 MWe pIant (SEGS-11) was initiated and was ex-pected to begin operating by late 1985 or early1986. Luz designed these systems, coordinatedthe p rojec ts and wa s an investme nt p artner inthem . The rema inder of the investme nt wa s pro-vided mostly by large institutional investorsthrough a limited partnership. The system’s per-formance was guaranteed for 20 years by Luz in-dustries (Israel) Ltd., the parent firm, which alsoprovided an insurance policy for the project.Southern Ca lifornia Edison ag reed to purcha sethe power for 30 years. C)ther than the Luzprojects, private sector involvement in the troughtechnology is limited.

Federal support for parabolic dishes developedsomewhat later than for the central receiver andtroughs. As a result, their development has laggedbehind that of the other solar thermal electrictechnologies. However, the efforts of over halfa dozen firms, coupled with direct Federal sup-port and other favorable conditions (includingFed eral and State tax incentives and the provi-sions of PURPA) fo stered rap id d eve lopm ent ofthe technology, especially during the first half ofthe 1980s. Notable was the fact that among thefirms whose support of parabolic dishes increasedduring the period were several who previouslyco ncentrated on either the c entral rec eiver orparabolic troughs.17

By mid-l985, a privately financed commercialdish facility had been installed by the LaJet EnergyCo. in southern California. It was financed by theparent company, La Jet, Inc.–a privately heldpetroleum exploration, drilling, and refining com-pany–and through limited partnerships. Mean-

1 zMcDonnell Douglas, now a major supporter ofthe dish tecl-r-nology, 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 tech-nology. Acurex still is working on trough technology, but it is em-phasizing the use of the technology for industrial process heat orcogeneration.

while, other commercialization efforts were pro-ceeding, the most important of which appearedto be the joint venture of McDonnell Douglas,an a erospa ce co rporation ac tive in the energyfield since the early 197os, and United Stirling,AB, a Swedish manufacturer of Stirling engines.


As discussed in chapter 4, widespread commer-cial deployment of solar thermal electric technol-ogies is unlikely unless costs are reduced, andperformance improved. Moreover, investor in-terest is not likely to be forthcoming until per-formance is demonstrated.

As with photovoltaics, wind, and g eothermaltechnologies, the Federal Government’s policiesstrongly influence the o utlook for the solar ther-mal electric industries. Without either an increase

in direc t Fed eral support or an extension of therenewable energy tax credits beyond 1985, noneof the solar thermal technologies is likely to beused much commercially in the 1990s.18 After1985, the limited solar thermal electric industrywhich exists today is likely to shrink rapidly. Thecommercial activities of Luz in solar troughs andLa Jet in parabolic dishes probably would be cutback substa ntially, as wo uld the effo rts of o thersmaller, entrepreneurial companies in the indus-try. Only the large st c ompa nies ma y be ab le tosusta in the involvement required to suc cessfully

deploy the technology in the 1990s.l9

Even with increased direct Federal support andfavorable tax policies, with the necessary cost andperformance improvements, and with commer--—.—-—.——

laThiS was reflected in the testimony of Frank F.Duquette be-fore the U.S. Congress on Mar. 1, 1984. He stated that:

The nearer term technology at this stage of development, stillre-qutres Federal support to reduce technical risk and valldate com-mercial or near commercial applications, Prtvate industry is unableto assume the entire burden of completing the R&D tasks remalnlngfor this current generation of technologies.

(Frank F. Duquette, Chairman, Solar Thermal Division, Solar EnergyIndustries Association, testimony presented to the Subcommitteeon Energy Development and Applications, Committee on Scienceand Technology, U.S. Congress, Mar. 1, 1984. )

Igsee: I ) Strategies Unlimited,Arta/ysis of Equipment MarrUfac-turers 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 /ncentiveson the Commercialization of Solar Thermal Electric Technologies (LiVermore, CA: Sandia National Laboratories, August 1983), SAND83-8178.




cial demonstrations, success is still by no meansguaranteed for these technologies in the 1990s.There are othe r po tent ial impe diments to the irdeployment. Among these might be problems re-lating to energy credits, capacity payments, andinterconne c tion requireme nts. Prob lemat ic toocould be the lack of widespread experience withthe technology; and licensing and permitting de-lays (am ong which e xtensive land imp ac ts andac cess to wa ter might figure imp ortantly).

In some cases, problems also may develop withrega rds to the Fuel Use Ac t. The lead ing troug htec hnology, that emp loyed a t the SEGS-I and IIplants in California, requires natural gas to sup-plement the solar energy in producing steam forthe steam turbines. Currently, the Fuel Use Actprohibits the use o f ga s and oil in many ne w g en-erating facilities except u rider special conditions.While exemptions to the law may be ob tained ,the law could delay or even prohibit construc-tion of oil- or gas-using facilities.

The following sections discuss for each tech-nology some of these impediments as well asproblems which are crucial to the individual tech-nologies,

Central Receivers.—For the central receivertechnology, one impediment stands out amongall others—the lack of a commercial-scale dem-onstration plant, Unless such a plant is initiatedvery soon and begins operating before the endof the decade, the prospects for this technology

in the 1990s are very limited. Should a demon-stration plant be initiated later than this, it willbe extremely difficult in the time remaining toovercome the many other obstacles blocking sig-nificant contribution by this technology to powerproduction in the 199os. In particular, the lackof a commercial demonstration project in thenea r future is likely to lea d to the c ontinued dis-banding of organizations originally established todeploy both a demonstration plant and subse-quent commercial units.

Several at temp ts to financ e d emo nstration units

by private sources have been initiated but havefailed. Hence, it appears unlikely that such plantswiII 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 in-

Without timely Government action, this technol-og y’s prospec ts are likely to b e seve rely Iimitedduring. the 1990s. Other major impedimentswhich could limit deployment, even if there isprompt construction of a demonstration plant,are: 1 ) the high cost of heliostats, 2) technicalproblems with the central receiver and othercomponents, and 3) various nontechnical prob-lems relating to such things as licensing and per-mitting.

Parabolic Troughs and Dishes.–Unlike theponds and central receivers, parabolic dishes andparabolic troughs, financed by private investorsa ssisted by Sta te a nd Fed eral rene wa b le energytax credits, already have been deployed and op-erated in commercial-scale units. Both for dishesand troughs, the combination of cost and per-formanc e c harac teristics and numerous unce r-tainties at p resent mitiga te ag ainst p rivate sec tor

investment tha t is not in some m anner accom-panied by Government support. How these con-ditions will change over the next 5 to 10 yearswill depe nd on the interac tion of a co mp lex ofvariables. Estimates and opinions of what willhappen range widely; each technology and eachparticular subvariety of technology has its propo-nents and detractors.

Generally speaking, capital costs must be re-duced and performance improved if the technol-og ies are to b e d ep loyed w idely. To some extent,this can be fostered by research oriented towards

incremental improvements of the commercial-scale systems now operating. Also necessary willbe adequate information on the solar resources.And if the technologies are to be extensively de-ployed in the 199os, perhaps the most pressing

divlduals. See for examp’-: 1 ) L.K. Ives and W.W, Willcox, “Eco-nomic Requirements for Central Receiver Commercial ization, ”Proceedings of STTF (Solar Thermal Test Facility) Testing for Long Term Systems–Performance Workshop, Jan. 7-9, 1984 (Albuquer-que, NM: National Technical Information Service,july 1984), PCAl 5/MF AO1, pp 61-67; 2) Edgar A. DeMeo, “Molten Salt Solar-Thermal Systems, ”EPR/ )ourna/, vol. 8, No. 12, December 1983,pp. 38-41; 3) McDonnell Douglas, “Response by McDonnellDouglas to General Workshop Discussion Questions, ” submitted

to OTA in response to written questions submitted in connectionwith 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, preparedfor U.S. Department of Energy,jan, 31, 1984; and 5) C.j. Wein-berg (Pacific Gas & Electric), letter to Howard S. Coleman (Depart-ment of Energy), dated Dec. 21, 1984.




need is to reduce uncertainty and to increase de-mand to the point where economies of scale candrive costs down.

The extent to which unc erta inty will be re-duced by the 1990s depends heavily on theamount of additional capacity instaIled for each

of the systems during the next 5 years. Shouldthe tax credits be extended, additional trough anddish systems probably will be installed, servingto reduce considerably the importance of uncer-tainty as an impediment to commercial deploy-me nt. The m ounte d -engine d ishes in pa rticular—where unc ertainty now is espe c ially g rea t—couldbenefit from greater deployment of c omme rcial-scale units, and improved commercial prospectsmight result. Under such conditions, the mounted-engine parabolic dishes could eliminate the cur-rent lead enjoyed by p arabo lic troughs am ongthe solar thermal technologies. If the engines per-

form well, the pa rab olic dish tec hnology c ouldprovide serious compe tition to the troughs andto other generating alternatives in the 1990s.

Without either sizable tax credits or greater di-rec t Government supp ort, howe ver, fewe r andpe rhap s no a dd itional trough or pa rab olic dishunits may be installed. Indeed, the private enter-prises whic h a re present ly pursuing the tec hnol-ogies may completely cease activities in supportof the technologies altogether. Our market anal-ysis suggests that only one of the parabolic dishdevelopers is likely to maintain a significant ef-

fort to supp ort the tec hnology if the renewa bleenergy tax credits cease to be available at the endof 1985.21

Wind Turbines


Wind turbines first were used to generate elec-tricity in Denmark nearly 100 years ago. Later,in the early 1930s through the late 1950s the tech-nology was deployed in the United States, pre-dominantly 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 Tur- bines, Solar Thermal Electric,Photovoitaics, op. cit., 1984; PeterB. 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 electri-city provided, the wind turbines ceased to be anattrac tive o ption. By the 1960s and ea rly 1970s,technical progress slowed to a crawl and deploy-ment continued at only a very low level.

Interest in wind turbines resurfaced in the

1970s when energy costs skyrocketed, fuel sup-plies became uncertain, and environmental con-c erns grew . The resurge nc e w as strong est in theUnited Sta tes and in Europe , espec ially in Den-mark. During the early 1970s, major governmentp rog rams bo th in the United Sta tes and a b roa demphasized the development of large, multi-megawatt wind turbines, though important workapplicable to smaller machines also was sup-ported. Outside of government-subsidized pro-grams, smaller units with ratings less than 100kWe were favored, as these offered the most im-mediate commercial applications.

By mid-May 1985, wind turbines–mostly smallunits—with a total rated capacity of over 650MWe were installed nationwide. Most–about550 MWe—were in California’s wind-farms,which became the focus of the worldwide windturbine industry. Several basic interrelated ele-ments appear to have shaped development dur-ing this period.

First, developers of the large multi-megawattwind turbines encountered serious technicaldifficulties. In the United States, the Federal Gov-ernment c ut ba ck its direc t supp ort of wind re-sea rch a nd d eve lopm ent (see tab le 9-2). The in-dustry, heavily dependent on Federal support,shifted away from the large machines when theFederal aid receded and concentrated on smallwind turbines which afforded a more immediatecomm ercial promise.

Sec ond, a co mb ination of favorable c ircum -stanc es in California p rompte d rap id g rowth inthe deployment of grid-connected wind turbines.Among these circumstances were the adoptionof PURPA Section 210, high electric-utilityavoided costs, availability of an excellent andaccessible wind resource which had been care-fully a ssessed , favorab le Fed eral a nd Sta te ta xtreatment; and favorable treatment by the Cali-fornia Energy Commission and public UtilityCommission.



Ch. 9—The Commercial Transition for Developing Electric Technologies 26

Finally, technical development of smaller sizedwind turbines proceeded very rapidly as costs de-c lined a nd p erforma nce improved . The extreme lyfavorable conditions in California encouraged theinitial commercial deployment of equipmentwhich wa s new and not fully proven. The p roc -esses of research, development, and commercial-izat ion c am e to ge ther into o ne step as Ca lifor-nia’s wind farms became de facto open-airlaboratories. While this greatly accelerated thedevelopment of the technology, it also led toinevitable mechanical faiIures and inadequaciesassociated with an emerging and immature tech-nology.

In 1984, there were about 100 wind turbinemanufacturers worldwide. They were mostlysmall, independent businesses dedicated exclu-sively to the wind industry, and owned andoperated by risk-taking entrepreneurrs without ex-tensive business experience, 22Most of the c om-panies had limited financial reserves, and de-pended on company growth to cover their pastdebts and provide working capital. Approxi-mately 70 of the companies in 1984 providedmostly turbines of sizes less than 50 kWe. About30 companies were active in wind farms and ofthese, six accounted for 95 percent of the worldwind-turbine sales in 1983.23

I n other wo rds, the w orld wind-turbine indus-try presently consists of many small firms, but itis dominated by a few manufacturers who pos-

sess an advantageous combination of adequateequipment and financial resources. However,even these six companies are relatively small. Forexample, Energy Sciences, Inc., the third rank-ing U.S. supplier in 1983, sold $17.5 millionwo rth of wind eq uipm ent in 1983. By c ompa ri-son, the sma llest c om pany on the Fortune 1000list had sales of over $122 million in 1983.24

Companies based in the United States domi-nated the world ma rket for wind pow er equip-ment in 1983, accounting for an estimated 72 per-

cent of world sales. But this position is beingeroded by foreign competition. By 1984, U.S.manufacturers accounted for 69 percent of worldsales of approximately $405 million. The declineof the U.S. position in world markets has beenparalleled by its decline in the domestic marketas well. The erosion of the U.S. industry’s mar-ket share is expected to continue. European ven-dors may achieve parity with U.S. producers inU.S. markets by the end of 1986 and surpass themby 1988. This appea rs possible d ue to a superiorcombination of equipment quality and cost, thelatter being greatly affected by the strength of theU.S. dollar. I n addition, European vendors havebeen very aggressive in exploiting foreign mar-kets.25

During the 1980s, the industry has been highlycompetitive; many companies have entered thebusiness and many others have withdrawn. Cur-rently, the number of firms is declining.

The grea t bulk of wind turbine ca pa c ity de -p loyed in the United Sta tes is financ ed by inves-tors other than the electric utilities and orches-trated by wind farm developers. While somedevelopers are independent of the turbine man-ufacturers (the open “merchant” market), a largeand growing share of the wind farms is directlyaffiliated with the turbine ma nufac turers them-selves.2b This “ cap tive” wind fa rm m arket a llowsvendors to: 1 ) c ap ture the de veloper’s profits,which g enerally exce ed their own; 2) reg ulate tur-

bine dema nd o ver the spa n of ea ch year so thatdemand is not overly concentrated at year-end;and 3) gain better control over adverse publicityrelating to turbine performa nce.

To d ate , ca pital for wind fa rm investment hasrarely come from public stock offerings or fromventure capitalists. Most investment has been inthe form of limited partnerships, either solddirec tly by the d eveloper or throug h brokerag efirms. Since 1982, ma jor brokerage houses ha vebeen involved and their importance in the indus-try has increased. Some developers, however,

Zlsee for e x a m p l e comments of 6ro r Iianson in A l t e r n a t i v e Sources of Energy, vol. 50,July/August 1981, p. 5.

IJStrategies Un]imited, Analysis d[qu ipment Manufacturers andVendori In the Electric Power Industry for the 1990s. Wind Tur- bines, Solar Therma/ E/ectric, Photovo/taics, op. cit., 1984.

241 bid.

l*lbid.ZbTh is Veflical Integration typically takes severalforms: the man-

ufacturer may itself obtain the land, utility contracts and capital re-quired for the wind farm; or 2) it may simply acquire a developer,or form exclusive relationships with a developer or an equipmentdistributor.




use so-called “chattel” sales to avoid dependenceon brokerage houses. Each of these financing ar-rangements has its advantages and problems, andaffects wind turbine deployment in a differentwa y. The m anne r in which financ ing is ob ta inedtherefore will continue to be of critical impor-tance to the industry. (See c hap ter 8 for more de -tails on financing arrangements. )

Industry Outlook and Major ImpedimentsAs mentioned earlier, wind turbines during the

first half of this decade have benefitted fromfavorable tax treatment; chapter 8 discusses theeffects of specific Federal tax provisions on windturbine economics and highlights their impor-tance. Potential tax changes, therefore, are ofconc ern to the industry. The ta x cha nge of mo stimmediate concern is the scheduled expirationof the Fed eral renewa ble e nergy ta x cred it (RTC)

at the end of 1985.Expirat ion o f the RTC is likely to result in a ma-

jor shake-out in the U.S. wind industry. Barringunexpected increase in electric utility involve-ment, demand for wind turbines probably willd rop sha rply, and ma ny sma ll firms are likely toc ollap se. Only la rger firms with sufficient c ap italto further develop medium-sized turbines andweather a period of intense competition and rela-tively low sales will survive. Though the size ofthe industry and the variety of firms could begreatly diminished, and though technical progressis likely to b e slowe d c onsiderably, ma ny indus-try ob servers believe tha t the industry co uld sur-vive, and perhaps even benefit, from a termina-tion or phase-d ow n of the RTC.

Though the RTC has stimulated technical de-velopment and commercial deployment, whichotherwise c ould not ha ve o c c urred in the ea rly1980s, they also have been abused by some in-vestors as short-term tax shelters.27 Such abusehas prompted Federal tax fraud investigations andhurt the reputation of the industry.28

Zzsee statement of Bill Adams, San Gorgonio Farms, as quotedin “San Gorgonio Farms (SGF) Will Install 53 Carter Wind SystemModel 225’s, ”Wind /ndustry News Digest, vol. 4, No. 4, Feb. 15,1984, p. 3.

28Largely in r e s p o n s e to tax-shelter abuses, the American WindEnergy Association established an ethics committee to monitor theindustry and discourage behavior which harms the long-term in-terests of the business. See: Burt Solomon, Windmillers Clean UpAct, ”Energy Dai/y, vol. 13, No. 12, Jan. 17, 1985, pp. 1 and 3.

Alternatives to a simple extension of the cur-rent Federal credits have been suggested. Onewould gradually phase-out the tax credits overseveral years; this might help the industry com-plete the c om me rc ial transition from sma ll tax-subsidized turbines to unsubsidized and eco-nomic medium-sized units. Another would estab-lish a system of credits based on energy produc-tion rather than capital investment;29these arediscussed in greater detail in chapter 10.

Aside from the imme diate issue of the RTC,other possible circumstances could also slow thedevelopment and dep loyment of com petitive,medium-sized turbines in the 1990s. Problems re-lating to the following could arise.

Equipment Qua lity.—Tec hnica l imp roveme ntsare necessary if wind turbines are to competewithout subsidy. While improvements are beingma de , ce ssat ion o f the RTC a t the end of 1985and of the California tax credit several years lateris likely to seve rely red uc e the c ap ital ava ilableto finance development and production of newwind turbine designs. Moreover, the likelihoodof smaller markets will reduce the opportunityto actually deploy the units and thereby gener-ate the data necessary for further improvement.The d ifficulty in financ ing the red esign and ma n-ufacture of new equipment probably will be par-ticularly severe among the small wind turbinemanufacturers.

Wind Resource Information.–Detailed windresource informat ion is c ruc ial to the g row th ofwind-farms around the country. While currentmeteorological data allows identification of po-tential sites,30 detailed site-specific informationmust still be ga thered for a t lea st 1 to 3 yea rs toadequately assess the potential of specific sites.While site-specific information is being generatedat a rapid pace, the lack of such information stillcould hinder deployment in the 1990s.3’ The

z~strategiesunlimited, Ana/ysis of Equipment Manufacturers and Vendors in the Electric Power Industry for the 1990s. Wind Tur- bines, Solar Thermal Electric,Photovohaics, op. cit., 1984.

~OBattelle, pacific Northwest Laboratories,Application ~Xarqdesfor Wind Turbine Siting Guidelines (Palo Alto, CA: Electric PowerResearch Institute, March 1983), AP-2906.

31 See: 1 ) j BF ScientificCorp., Ear/y Uti/ity Experience With Wind Power Generation: Goodnoe Hi//s Project (Palo Alto, CA: ElectricPower 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).




need for wind assessment extends to prospectiveexport markets as well, where data are especiallyinadequate. 32

Land Access and Cost of Access.—Access towind-swept land has in some instances been aproblem. 33 Furthermore, costs of access have in-

creased substantially. Development of the windresource presupposes access at an acceptablec ost. These p ote ntial prob lems ma y slow d ep loy-ment in the next 15 years.

Cost and Performance Data.–Current costand performance data are very important to pro-spective wind turbine investors as well as to util-ities, public utility commissions, and the turbinemanufacturers themselves. At present such dataare difficult to obtain, precluding accurate predic-tion of wind turbine cost and pe rformanc e p riorto d ep loyment. Efforts are b eing ma de in someStates to increase the information available oncurrent machines. 34 Where performance data areavailab le, use is often limited by inconsistenc iesand other problems.

Standard Definitions and Performance Leveis.–The effec tive use of p erforma nce d ata often islimited by inconsistencies; standard definitionsmight assist investors and others in comparing windturbines with each other as well as with compet-ing ge nerat ing tec hnolog ies. The va lue of suc hstandards is enhanced when they are provided byan independent and trustworthy source. Of evengreate r value might b e the estab lishment of m ini-mum standard performance levels which turbineperformance must meet in order to receive certifi-cation. Many industry observers believe standardsshould b e a pp lied to the industry, though there isdisagreement over who should impose the stand-ards 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 Researchin-stitute, 1982J, subcontractor report, SE R1/STR-21 1-1827.

IIR. ), Noun, et al., ut;l;ty Siting of WECS: A Preliminary LegallReg-u/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 basisby all windproject operators in the State, The American WindEnergy Association is developing a voluntary national reporting pro-gram similar to California’s mandatory program,

Warranties.–Investors, in view of the past poorperformance of some wind turbines, are reluctantto invest in hardware unless it is accompanied bya strong warranty. This essentially shifts part of therisk of owning and operating a wind turbine backto the vendor. Because current technology is im-mature, however, such warranties are in themselvesrisky and could lead to high costs for vendors. in-deed, some manufacturers have been driven outof business because of these costs. 35 While vendorscan purchase “warranty insurance, ” this insurancehas become progressively expensive as insurershave become more cautious with wind turbines. 3b

Should the industry be short of c apita l during thenext 15 years, the warranty issue could constitutean important impediment to industry expansion.

Government Permits and Licenses.–Wind farmpromoters are expected to encounter problems asthey seek approval for their projects from Federal,

Sta te, a nd loc al reg ulato ry ag enc ies. The most seri-ous problems are likely to be at the local level,where wind farms have already encountered pub-lic opposition because of visual and environmentalimpac tso

37

Transmission Facilities.—Without access totransmission facilities, even the most attractive sitecannot be 1 inked to the grid. Major transmissionfacilities often require lead-times of 3 to 10 years.Clearly, if candidate wind sites do not alreadyhave easy access to transmission lines, seriousde lays ma y be enc ountered. Wide spread wind

turbine deployment in the 1990s will either belimited to a rea s which a lrea dy ha ve a ccess totransmission lines, or if currently remote areas areto be developed, efforts to extend transmission

‘35For example, see: 1 “How Wind Power Cracks Up, ” NewScientist, Apr. 12, p. 31; 2) Arthur D. Little, Inc.,Wind Turbine Per- formance Assessment (Palo Alto, CA: Electric Power Researchin-stitute, 1984), Technology Status Report No. 7, EPRI AP-3447; 3)Larry Stoiaken,“The Small Wind Energy Conversion System Mar-ket: Will 1984 Be ‘The Year of theSWECS’?” Alternative Sources of Energy, vol. 63, September/October 1983, pp. 10-23; and 4) Strat-egies Unlimited,Ana/ysis of Equipment Manufacturers and Ven- dors 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 RelevantInsurances, ” Alterna t ive Sources of Energy, vol. 72, March/April1985, pp. 56-59.

~TSee Chs, 4 and 7 for furtherdetails.




facilities to those areas must be initiated withinthe next dec ad e.38

Utility Energy and Capacity Credits, and in-terconnection Requirements.– Low energycredits, low capacity payments,39and stringentinterconnection requirements discourage deploy-ment by nonutilities. Even where thepossibility exists tha t c redits could d rop d uring the lifetimeof a project, investment is discouraged. Also, anydifficulties (such as delays) encountered in seek-ing to obtain favorable credits or interconnectionrequirements discourages non utility deployment.

Overseas Markets.–Over the next decade, for-eign markets are likely to be important outletsfor wind turbines, espec ially sma ll ma chines forremote applications;40 under some conditionsthey could be crucial to the survival of majormanufacturers. Already, exports account for a siz-able share of turbine sales by U.S. manufacturers,and current evidence indicates that many are ac-tively developing overseas markets. 41 The prom o-tion by the companies themselves and by othersof oversea s sa les appea rs to c onstitute a ma joropportunity to nurture the industry and to in-directly foster further refinement of the technol-ogy. Difficulties in exploiting these markets (in-cluding problems relating to foreign competition)therefore could severely damage the industry, re-ducing its capacity to supply the domestic mar-

— . . . —lsFO r example, th e lack of t r ansmiss ion capac i ty in California

r epor t ed ly p reven ted deve lopmen t o f some p r ime wind s i t e s .Source: OTAstaff conversation with MikeBatham, California EnergyCommission, November 1984.

JgFor a discussion of capacity credits in the wind industry, seeFred Sissine, Wind Power and Capacity Credits: Research and im-plementation Issues Arising From Aggregation With Other Renew- able Power Sources and Utility Demand Management Measures (Washington, DC: Congressional Research Service, 1984).

qosee: I ) Birger T. Madsen,“Danish Windmills: A View From theInside, ”Alternative Sources of Energy, vol. 69,September/October1984, pp. 24-26; 2) S.K. Griffith, et al.,Foreign Applications and Export Potentia/ for Wind Energy Systems (Golden, CO: Solar EnergyResearch Institute, 1982), subcontractor report,SER1/STR-21 1-1827;3) Les Garden, “The Overseas Market: Does the Post-Tax-CreditTransition Start Now?”Alternative Sources of Energy, vol. 69,Sep-tember/October 1984, pp. 28-30; 4) LarryStoiaken, “InternationalMarketing: 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 Mutualin-terest’ With Chinese for 40 Darrieus Turbines, ”50/ar Energy /nte/-/igence Report, Jan. 21, 1985, p. 24; 2) LarryStoiaken, “The SmallWind Energy Conversion System Market: Will 1984 Be ‘The Yearof the SWECS’ ?“ op. cit., 1983; 3) LarryStoiaken, “Going interna-tional, ”Alternative Sources of Energy,vol. 63, September/October1983, pp. 24-25.

kets with turbines of acceptable quality and inthe qua ntities de ma nde d for the 1990s.

Geothermal Power

History and Description of the IndustryIn 1904, Italy became the first country in the

world to use geothermal energy to produce elec-tricity. In 1923 geothermal resources were tappedin the united Sta tes to p rod uce elec tric po wer.At that time, a small, remote 250 kWe unit be-ga n gene rating power for a Ca lifornia ho tel at TheGeysers. Over 35 years elapsed, however, beforefurther c ap ac ity was insta lled in the United Sta teswhen, in early 1960, the first grid-connected geo-thermal unit be ga n to generate p ower at TheGeysers. During the following 20 years, furtherdevelopment occurred and by the end of 1983,1,300 MWe of geothermal capacity were on-linein the United State s—more c ap ac ity than in anyother country. Worldwide, about 3,400 MWewere op erating.42

Most U.S. geothe rma l develop ment, loca ted atThe G eysers in Ca lifornia , emp loyed d irec t stea mconversion technology. As discussed in chapter4, however, most U.S. geothermal resources areof lower quality than those found there and can-not be exploited with the conventional technol-og y used at The Geysers. As deve lopm ent a c tiv-ity progressed in the 1960s, the need for differenttechnologies for lower quality resources becameevident. Further geothermal development in-c rea singly would req uire other eq uipm ent suchas the developing technologies considered in thisassessme nt—dua l flash a nd binary systems.

While the need for technological progress wasapparent in the 1960s, it was not until recentlythat these new technologies began to be de-ployed in the United States. Several factors, in-cluding problems regarding Federal leasing pol-icies and technological questions, served toimpede the development of the lower qualitygeothermal resources. Progress in these matters,along with the passage of PURPA, favorable Fed-

42 Ronald DiPippo,“Development of Geothermal Electric PowerProduction Overseasr ” Energy Technology Xl, Applications& Eco- nomics: Proceedings of the Eleventh Energy Technology Confer- ence, Mar. 79-21, 1984, Richard F. Hill (cd.)(Rockville, MD: Gov-ernment Institutes, Inc., August 1984), pp. 1219-1227.




eral and State taxes, and high avoided costs,brought commitments to the technologies dur-ing the first half of the 1980s. By the end of 1985,a single 47 MWe (net) dual-flash geothermal unitwill be in place. One large (45 MWe, net) binaryplant will have been installed and at least 30MWe o f sma ll b inary plants will b e o perating. To-

gether these will account for about 122 MWe,or ab out 7 perce nt of to ta l U.S. insta lled ge othe r-ma l cap ac ity at the end of 1985 (about 1,780M We43).

Important to these technological developmentshas be en the Fed eral Government’ s supp ort ofthe industry since the mid-1970s. The first majorFederal assistance came in the form of the Geo-therma l Loa n Gua rantee Prog ram. This soo n w ascoupled to stepped-up support for research anddevelopment (see table 9-2). From 1973 through1983, approximately $1 billion was spent on geo-

thermal power by the Federal Government, roughlymatching industry’s expenditures. Direct Federalexpenditures in support of the technology, con-centrated in DOE and its predecessor agencies,grew from $3.8 million to $171 million in 1980;however, as of fiscal year 1985 this had droppedto $32.1 million. The rec ent de c line in direc t Fed -eral expenditures was partially offset by increasesin indirect Federal support of the industry throughvarious tax incentives, including the RenewableEnergy Tax Credit.

Discovery of geothermal resources has longbeen associated with oil exploration and devel-op ment in this c ountry, When g eothe rma l ac tivitypicked-up in the 1960s, several oil companies en-tered the geothermal business. Since then, theoil industry has continued to be deeply involvedwith geothermal development, and indeed heav-ily dominates the industry. At the same time, agroup of smaller, independent enterprises hassought to develop geothermal power, usually bypursuing the relatively marginal resources.

Among the businesses in the geothermal indus-try is a core of about two dozen companies ca-pable of sustaining the full effort required to bringgeothermal 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, ar-chitectural and engineering firms, and the Elec-tric Power Research Institute (EPRI), which sup-port the development and deployment of thetechnology. 44

Until the late 1970s, geothermal developmentwas carried out through cooperative ventures be-tween field d eve lope rs and elec tric utilities. Thefield developers located the resource and thenworked with the electric utility and architect-eng ineering firms to d esign and c onstruc t a po w-erplant. The field d eveloper then would ta p thegeothermal resource and deliver the hot wateror stea m “ over the fence ” to the e lec tric utility.Since 1978, though, PURPA, favorab le ta x trea t-ment, and high a voided costs have stimulate dnonutility investment in power generation proj-ects, and purely nonutility projects have become

prevalent in Oregon, California, and Neva da .Industry Outlook and Major Impediments

By the yea r 2000, a tot a l U.S. geotherma l ca -pa c ity from 2,600 to abo ut 6,800 MWe ma y bein place. A sizable portion of this could consistof the developing technologies discussed in chap-ter 4. Most will be located in California, HawaiiArizona , New Mexic o, Neva da , and Utah.qs Thedegree to which the potential will be realized de-pe nds on a variety o f c ircumstance s.

As with the other renewable energy technol-ogies, the status of various State and Federal taxincentives will strongly influence deploymentlevels. As mentioned in chapters 4 and 8, the taxincentives make geothermal investments muchmore attractive and have been especially impor-tant in advancing the technologies during the

44Vane E. Suter, “Who Will Develop the Governmental Re-sources?” Proceedings: Seventh Annual Geothermal Conference and Workshop, Altas Corp. (cd. ) (Palo Alto, CA: Electric Power Re-search Institute, 1983), EPRI AP-3271, pp. 7-10 through 7-13; andVasel W. Roberts, “EPRI Geothermal Power Systems Research Pro-gram, ” Proceedings: Eighth Annua/ Geotherma/ Conference and Workshop, Altas Corp. (cd.) (Palo Alto,CA: Electric Power ResearchInstitute, 1984), EPRI AP-3686, pp. 4-1 through 4-3.

qsvasel Roberts and Paul Kruger, “Utility Industry Estimates ofGeothermal Energy,”Proceedings: Eighth Annual Geothermal Con- ference and Workshop, Altas Corp. (cd.) (Palo Alto, CA: ElectricPower Research Institute, 1984),EPRI AP-3686, p. 4-27 through 4-31.




early 1980s.46Elimination or reduction in the sizeof the tax incentives—or even the possibility ofsuch changes—is likely to slow deployment.

Important too will be other government activ-ities at the Federal, State, and local levels. Thelevel of direct support for R&D will continue to

be a key determinant of technical progress in theindustry. Also influential will be the many formsof reguIatory control government agencies exertover the activities required to deploy geothermaltechnologies. Because of the importance of gov-ernment, and the numbe r and diversity of rele-vant agencies, the degree to which their activi-ties are coordinated will be equally important .4’

Other factors that may impede the deploymentof geothermal technologies in the 1990s include:

Equipment Cost and Performance.–As dis-cussed in chapter 4, dual-flash and binary-cycle

tec hnologies are relatively imma ture. Co st red uc-tions and pe rformanc e imp rovem ents in somec ases ma y be nec essary, not o nly with the e quip-ment used in actually producing the electricpower, but in some cases also in the technologyreq uired to deliver brine to t he surfac e. The rat eat which progress occurs depends strongly on theam ount of cap ital devoted to R&D.

Three fac to rs ma y reta rd R&D inve stment. First,the members of the geothermal industry most ca-pable of shouldering R&D investments–those af-filiated with the petroleum companies–may notinvest the necessary capital, 48 partly because ofthe c urrent soft p etroleum ma rket, Sec ond , ac tiv-ity in the geothermal industry is affected heavilyby nonutilities, whose investment levels are in-

— . ..—dGSubcommittee on Energy and Mineral Resources,Senate Com-

mittee on Energy and Natural Resources, U.S. Congress,Geother- mal Energy Development in Nevada’s Great Basin: Hearing to Ex- amine the Current Status and Future Needs of Nevada Geothermal Energy /ndustry (Washington, DC: U.S. Government Printing Of-fice, 1984) Sparks, Nevada, April 17, 1984,S.Hrg. 98-801,

dTAlex Sifford, Background Geotherma/ /formation for the 1985Energy P/an (Salem, OR: Oregon Department of Energy, February1985), mimeo, and James Ward, “Geothermal Electricity in Cali-fornia, ” Transitions to Alternative Energy Systems–Entrepreneurs,

New Technologies, and Social Change, Thomas Baumgartner andTom 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 Pro- gram Accomplishments, Industry Response, and Projected Impact on Resource Development (Philadelphia, PA: Tech necon AnalyticResearch, Inc., 1983).

.

fluenc ed strong ly by State a nd Fed eral tax pol-icies. possible c hange s in the po lic ies, the mo stimmediate of which is the expiration of the Fed-eral renewable energy tax credit, will greatlydiminish geothermal investment. Third, the Fed-eral Government, which historically has been themajor source of R&D funds, has sharply cut itssuppo rt (see ta ble 9-2).

Technology Demonstration.–Beyond the geo-thermal demonstration plants already being builtor operating, very little additional capacity isplanned with the developing geothermal tech-nologies. Should few additional plants be de-ployed in the next 5 to 10 years, the lack of ex-tensive commercial experience is likely to impederap id expa nsion of c apac ity in the 1990s, sincethe associated risks may be perceived as too high.Difficulties in g aining ac cess to ad eq uate infor-mation on cost and performance could also slow

timely deployment of developing geothermaltechnologies in the 1990s.49

Geothermal Exploration, Resource Identifica-tion and Assessment.–Once a geothermal re-source is discovered, more precise informationon the quality of the resource is needed in orderto assess the economics of site development andto optimize plant design. This requires that re-source qualities be measured further and the in-formation analyzed. The lack of site measure-ments and adequate analytical capabilities arec onsidered ma jor imped iments to the develop-

ment of geothermal power.Federal Leasing Requirements.–A consider-

ab le portion of the g eothe rma l resource in theUnited States lies under Federal lands. The leas-ing of this land, administered by the Bureau ofLand Management, is characterized by two re-quirements which ma y imp ede dep loyment ofge otherma l tec hnolog ies. First, no single lea se-holder may hold leases covering more than20,480 acres in any specific State. SO This report-

4W .s. Department of Energy, Geotherma/ Progress Monitor (Washington, DC: DOE,1983), Report No. 8; and testimony of JonWellinghoff (Consumer Advocate, State of Nevada), p. 5 in Sub-committee on Energy and Mineral Resources, Geofherma/ EnergyDevelopment in Nevada Great Basin: Hearing to Examine the Cur- rent Status and Future Needs of Nevada’s Geothermal Energy in-dustry, op. cit., 1984.

SOThe 197o Geothermal Steam Act, however, does allow the Sec-retary of Interior to raise the statewide acreage limitation after Dec.24, 1985. Indeed, in April 1985, the Department of the Interior pro-posed that the limitation be raised to 51,200 acres.




edly has slowed the rate at which resources canbe assessed and at which development can oc-c ur. Sec ond , primary lea se terms are for 10 yea rs;a leaseholder must develop the land within thatperiod or lose the lease. This may inhibit com-mitments to develop particular geothermal re-

sources.5

1Utility Energy and Capacity Credits, and inter-

connection Requirements.—As with the othertechnologies discussed so far in this chapter lowenergy c red its, low c ap ac ity p aym ents, and strin-gent interconnec tion req uirements discouragedeployment by nonutilities. Even where the pos- sib ility exists that credits cou Id drop during thelifetime of a project, investment is discouraged.Also, any difficulties (such as delays) encounteredin seeking to obtain favorable credits or intercon-nection requirements discourages non utility de-ployment.52

Transmission Capacity .—Like wind resources,geothermal resources often are located in areaswhich are not readily accessible or located neartransmission fac ilities. Moreo ver, in som e cases,the g eothermal resources are fa r from the m ar-kets offering the highest a voided c osts. The la c kof adequate transmission facilities connecting theresources with markets and/or institutional mech-anisms for wheeling power to these markets isconsidered a major impediment to the further de-

— .—s]See: 1) J. Laszlo, “Findings of U.S. Senate Hearings on Geo-

thermal Development in Nevada, ”Proceedings: Eighth Annual Geo-therrna/ Conference an d 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 Gov-ernmental Resources?” Proceedings: Seventh Annual Geothermal Conference and Workshop, op. cit., 1983; 3) Subcommittee onEnergy 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, Sen-ate 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 Geother-

mal Development in Nevada, ”op. cit., 1984, and Subcommitteeon Energy and Mineral Resources,Geothermal Energy Develop- ment in Nevada’s Great Basin: Hearing to Examine the Current Sta- tus and Future Needs of Nevada’s Geothermal Energy Industry,o p .cit., 1 9 8 4 .

ployment of geothermal technologies of any kind,espe c ially in Oreg on and Nevad a.53

Leasing, Permitting, and Licensing Delays.–Where geothe rma l de velopm ent is planned onFederal property, considerable delays may be oc-casioned in securing the necessary lease. Further

delays also may result as the requisite licensesand permits are obtained from various publicagencies. 54 Problems regarding water consump-tion and subsidence in particular may occasiondelays, particularly in agricultural areas.55 To-gether, these time-consuming steps may limit theamount of capacity which could be deployed inthe 1990s.

Fuel Cells


The c urrent ma jor efforts to de velop the fue lc ell for grid-connec ted ap plic ations in the UnitedSta tes a re sp lit be twe en na tural ga s and e lec tricutilities. The elec tric utilities are p ursuing the useof fuel cells in central station applications, whilegas utilities have concentrated on relatively small,“onsite” fuel cells which would increase marketsfor natura l gas.

As with photovoltaics, the initial commercialimpetus behind fuel cell development in theUnited States was the space program in the 1950sand 1960s. Efforts to develop fuel cells for ter-

. — — —53See:, 1 ) J. Laszlo, “Findings of U.S. Senate Hearings on Geo-thermal Development in Nevada, ” op. cit., 1984;2) C.j. Weinberg,“Role ofUtilities, Resource Companies, and Government: Discus-sion Group Report, ” Proceedings: Seventh Annual Geothermal Conference and Workshop, Altas Corp. (cd. ) (Palo Alto, CA: Elec-tric Power Research Institute, 1983),EPRI AP-3271, pp. 7-26 through7-27; and 3) Subcommittee on Energy and Mineral Resources, Geo-thermal Energy Development in Ne~ada’s Great Basin: Hearing to Examine the Current Status and future Needs of Nevada Geother-ma/ Energy /ndustry, op. cit., 1984.

Sdlncluded in the information required for facility licensing andpermitting is baseline data on the environmental conditions at asite. For more information, see AlexSifford, Background Geother-ma/ /formation for the 1985 Energy Plan,op. cit., 1985.

JSFor a discussion of th e water issue in the Imperial Valley,Where

considerable deployment of dual-flash and binary systems may oc-

cur in the 1990s, and where agricultureis very important, see: De-partment of publ ic Works, Imperial County,Water for Geother- mal Development in Imperial County: A Summarizing Report (ElCentro, CA: Imperial County, June 1984), special report, DOE Co-operative Agreement DE-FC03-79ET271 96.




restrial applications multiplied during the mid-1960s, but by the end of the d ec ad e m ost hadceased with one notable exception. In 1967 agroup of gas utilities formed a n orga niza tions todevelop equipment that somehow could counterthe e lec tric po wer industry’s c ap ture o f the g asindustry’s ma rkets. This and sub seq uent p rogramsculminated in the current effort in which the GasResearch Institute (GRI), funded by the gas in-dustry, and DOE are deploying and testing forty-six 40 kwe fuel cell cogeneration units. Severalunits of this size also were installed in Japan. Con-currently, GRI and DOE are funding a coordi-nated multi-yea r resea rc h p roject expec ted toyield an “early entry” onsite fuel cell system withan e xpe c ted outp ut of ab out 200 to 400 kWe.

Mea nwhile, since 1971, fuel ce ll ma nufac tur-ers, e lec tric utilities, 57 the Electric Power ResearchInstitute, the Federal Government and others

have sought to develop and deploy multi-mega-watt fuel cell power facilities. By 1978, a 4,5 MWeprojec t was initiate d in New York City. The NewYork unit suffered from delays in gaining localreg ulatory app roval. These d elays exce ed ed thestorage life of the power section so that the unitcould not be operated without refurbishment. Asa result, the project was abandoned in 1984.Ano ther similar, but imp roved unit wa s insta lledin Jap an. That unit, ma de by the sam e m anufac -turer which prod uced the New York installat ion,ha s op erat ed very suc c essfully since Ap ril 1983.Currently, plans are being laid both in the United

Sta tes and in Japa n to first de velop a nd d ep loycommercial demonstration units, and then to ini-tiate c omme rc ial prod uc tion of fuel cells lat e inthe 1980s or early 1990s.

In the rece nt years a numbe r of coo pe rativeagreements between Japanese and U.S. firmshave evolved, perhaps the most important ofwhic h is the joint venture be twe en United Tec h-nolog ies and Toshiba. The tw o c om pa nies have

JbThe Team to AcfVar-rCeResearch on Gas Energy Transformation(TARGET).

JTElectric Utilityeffotis in support of the fuel cell have been medi-

ated in part through the Electric Utility Fuel Cell Users Group, anassociation established about 5 years ago. The group, now con-sisting of over 60 members, works closely withEPRI, fuel cell ven-dors and others to promote the use of fuel cells among electric util-ities. 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 commercialpo werplant design and deve lopme nt ac tivity. Thisalliance may lead to an agreement to constructa fuel cell production faciIity in the United Statessometime in the near future.58 The substantialcapital and technological capabilities of these cor-porations enhance the prospects that the hurdles

faced in early commercialization may be success-fully and readily overcome.

Government involvement on both sides of thePac ific ha s bee n extensive. In the United Sta tes,Federal funding has been divided between mili-tary/space applications and support of civiliancommercial uses. The support for civilian appli-cations has emphasized the use of fuel cells intransportation and in electric power generation;this support has emanated from DOE and itspred ec essor ag enc ies. The DOE prog ram of grea t-est importance to the near-term commercial pros-

pects of the fuel cell is the Phosphoric Acid FuelCe ll Prog ram. The Na tiona l Aeronautics andSpace Administration (NASA) -Lewis ResearchCenter has been designated by DOE as the leadc enter for the p rogram.

DOE’s funding for fuel cells is summarized inta ble 9-2. DOE’s sup port pea ked in 1984, when$42.3 million were spent on the technology. Avery substantial portion of the funds has beendedicated to the phosphoric acid technology– which is the most promising technology for ini-tial co mm ercial pe netration. While DOE spe nd-ing on fuel cells dropped only slightly in fiscal year1985, a substa ntial reduc tion to $9.3 million ha sbeen proposed for 1986. Under the latter pro-po sal, suppo rt for the phospho ric ac id tec hnol-og y is eliminate d altog ethe r.59

Although som e fuel c ell resea rc h a nd de velop-ment took place in Japan during the 1960s and1970s, the current Japanese fuel cell program did

——.—~13p.J, Farris, Business Planning Staff, International FuelCells (u n-

published memorandum forOTA staff), June 18, 1985. For moreinformation on these U.S.-Japanese efforts, see: Peter H u nt Asso-ciates, Analysis of Equipment Manufacturers and Vendors in the Electric Power Industry for the 1990s as Related to Fuel Cells (Alex-andria, 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 FredSissine, Fuel Cells for Elec- tric 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 theae gis of the Ministry of Internationa l Trade a ndIndustry (MITI), the ag enc y’s “Moonlight Projec t”initiated a coordinated program directed towardsthe development of fuel cell technologies for va-rious applications. Al I of the Japanese equipment

manufacturers are working u rider this program,as are severa l Japanese ut ilities.While the Japanese have in the past lagged be-

hind the U.S. program, it appears that the cur-rent Japanese program has narrowed the gap.This results in pa rt from the a tte ntive o bserva tionof a nd pa rtic ipa tion i n U,S. efforts. The Japanesehave learned from U.S. successes and mistakes,while providing their own refinements and modifi-cations.


The fuel c ell ind ustries in bo th the United Sta te sand Japan are positioning themselves for substan-tial com mercial de ployment of fuel ce lls in the1990s. At the cost and performance levels whichthe fuel cells may achieve, extensive markets forboth central station and dispersed applicationscould develop.

Deployment in Japan, fostered by the govern-me nt (MITI), co uld b e q uite rap id. Pa rticula rly im-portant in this regard is the close working rela-tionship the Japanese fuel cell developers havewith the c ount ry’ s elec tric p ow er comp an ies. Thiswill ease the difficulties the manufacturers mightencounter in the early stages of commercial transi-tion. Over the next 15 years the well-coordinatedJapanese effort probably will place that country’sfuel cell manufacturers in a position comparableor perhaps superior to their U.S. counterparts bar-ring significant increases in this country’s efforts. 60

In Japan, fuel c ells using p rima rily imp orted nat-ural gas are expec ted to provide a few percent-age points of total generating capacity by 1995,and could provide 7 to 8 percent of generatingcapacity at the beginning of the 21 st century. 61

‘“Ernest Raia, “Fue l Ce l ls spark Utilities’ Interest, ”ll;gh Tech-nology, vol . 4 , No. 12, December 1984, pp. 52-57.

G! N, Floriuchi et al., “Applicat ions of Fuel Cel l Power PlantsinJapanese 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 a t which fuel ce lls are d ep loyed in theUnited States probably will be slow at first, untilconfidence among potential investors is built up.The length of this transitiona l pe riod is a ma tte rof speculation. It is likely that the first commer-cial units will not be erected until investors areconvinced these early commercial systems willoperate well, Since both the small (200 to 400kWe) and large (multi-megawatt) demonstrationunits will not be installed until the latter part ofthe 1980s, operating experience sufficient to justify initia l co mm ercia l orders prob ab ly will notdevelop until the beginning of the next decade.It is likely tha t the prop osed termination of Fed -eral funding of p hospho ric ac id fuel cell de vel-opment will slow this process and perhaps weakenthe industry’s competitive status with the Japa-nese; but it is not clear how serious the effect willb e e

6 2

The p oten tial ma rket in the United Sta tes is verylarge. An EPRI study of the potential utility mar-ket suggests that fuel cells could provide as muchas 65,000 MWe of generating capacity by 2005. 63

At the same time, circumstances favor non utilityde velopm ent too. Substantial ad vanta ge s areassociated with dispersed cogeneration applica-tions under nonutility ownership. Investors, ledby the gas utilities and perhaps the fuel cell man-ufacturers themselves, could stimulate rapidgrowth in nonutility applications in the1990s.64

By the mid-l990s, total experience around the

country and in Japan could be sufficient to trig-ger rapid growth in the technology in the late1990s. With very favorable conditions, thisgrowth c ould o c c ur even soone r. Various imped i-

—GzROhert L. civlak, et al., /mpacts o(’ Proposed Budget c’utS in

Selected Energy Research and Development Programs (Washing-ton, DC: Congressional Research Service, 1985).

GjElectric power Research Institute (EPRI), 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. Wein-

gart, “integrated Commercialization Analysisfor New Power Gen-eration Technologies, ” Energy Technology X/, ApplicationsandEconomics: Proceedings of the E/eventh Energy Technology Con- ference, Mar. 19-21, 1984,Richard F. Hill (cd.)(Rockville, MD:Gov-

ernment Institutes, Inc., August 1984), pp 188-205; and “Industrial,Commercial Sites Eye Fuel Cells, ”Coa/ Technology Report, Jan.23, 1984, p. 2.




ments, however, could delay extensive commer-cial deployment until after the close of the cen-tury. These impediments are listed below.

Equipment Cost and Performance. -As wasdiscussed in chapter 4, current evidence suggeststhat it is possible to mass produce fuel cells, tosell them a t ac ce pta ble price s, and to op eratethem without excessive problems. However, thisis by no means certain. Demonstration plants arenecessary to reduce the uncertainty to a levelmore acceptable to investors. Further researchand development, aimed at incremental improve-ments in the equipment, would increase the pos-sibility that c ost and p erformance will fall withinthe necessary ranges in the 1990s.

Perhaps the most important imp ed iment fac -ing the fuel cell is the lack of an initial marketsufficient to justify mass-production. Without a

sizable initial market, only small numbers of rela-tively expensive fuel cells can be manufactured.These must b e sold a t high price s–thereb y inhib-iting demand—or the manufacturer must, in theshort term, operate at a loss. The time it takesto overcome this problem will, perhaps morethan any other factor, determine the rate of com-mercial application of fuel cells in the 1990s.

Technology Demonstration.–The successfuldemonstration of both small and large fuel cellswill be of critical importance to stimulating in-vestment in the technology. Demonstration unitswill be needed to encourage the initial round oforders,

Utility Energy and Capacity Credits, and in-terconnection Requirements.–As mentionedab ove , a m ajor market for fuel ce lls lies outsidethe electric utilities. Like other grid-connected,nonutility applications initiated under PURPA,low energy credits, low capacity payments, andstringe nt interco nnec tion requirements d isc our-age deployment by nonutilities. Even where thepossibilityty exists that credits could drop duringthe lifetime of a project, investment is discour-ag ed . Also, a ny d ifficulties (such a s de lays) en-countered in seeking to obtain favorable creditsor interconnection requirements discouragesnonutility deployment.

Licensing and Permitting De[ays.–ln the longterm, licensing and permitting delays are likelyto be minimized by virtue of the technology’srelatively low environmental impacts. However,othe r c irc umsta nc es might lengthen d elays. Thetechnology will in many instances be installed in

areas where powerplants have not been tradition-ally sited a nd in highly po pulated areas wheresafety considerations are likely to be heavily em-phasized. Moreover, the technology is new andregulatory officials are not well acquainted withit. The 4.5 MWe facility which was installed inNew York was the subject of many unexpecteddelays; similar problems could develop with fu-ture p lants.

Integrated Gasification/Combined=Cycle Plants

History and Description of the IndustryThe integ rated ga sifica tion/c ombined -cyc le

plant (IGCC ) is a relatively new comb ination o fcomponents—gasif iers, gas turbines, and steamturbines—which themselves have been aroundin some form for a long time. Steam turbines havebeen used to generate electrical power since1930 in the United Sta tes, and now are used togenerate more electrical power worldwide thanany other tec hnology.65

Gas turbines were not used for commercialge neration of elec tric po wer in the United State s

until 1961. Spurred by the need for fast-startinggenerating capacity and encouraged by the shortlead-times typical of gas turbines, utilities in the1960s and ea rly 1970s dep loyed ma ny of theseunits.66

Coal gasifiers were being used commerciallyby the early 1800s. By 1930, there were about11,000 coal gasifiers in the United States. Thesewere used to produce gas for both light and heatin cities as well as for industrial uses. From the1930s through the mid-l950s, development con-

bsBased on telephone conversation between Brucew. Morrison,V.P. Atlantic Region, Westinghouse Electric Corp., and OTA staff,May 16, 1985.

661 bid .




tinued, especially in Germany and the UnitedStates. The b asic de sign of large c omm ercia l ga s-ifiers which today form the basis for IGCC devel-opments originated during this period.b7

With the ava ilab ility in the United Sta tes of lowcost, reliable supplies of natural gas in the late1950s and the 1960s, activity involving coal gasifi-cat ion in the United State s wa s ma intained a t onlya very low level, though it co ntinued to b e im-portant in the steel industry. Greater interest con-tinued overseas, however, where circumstancesfavored the technology’s development.

The 1970s brought renewe d interest in ga sific a-tion for various applications, including electricityge neration . The use of co a l gasifiers in elec tric itygeneration offered some important advantages.It allowed for greater reliance on domestic coalresources, less dependence on oil or gas, and its

environmental impacts were less severe thanthose of more conventional coal-fired equipment.In ad dition, co upling a c oa l gasifier to a c om-bined-cyc le system ap pea red to m eet the grow-ing de ma nd for highly effic ient g eneration.

But the economic use of gasifiers in electricityproduction required technical improvementsover earlier commercial technologies, In responseto this need, advanced gasifiers have been de-veloped . Several prime ca ndida tes for app lic a-tion in IGCC systems for the 1990s have emerged;these gasifiers have either beenused commer-cially in some application, or are in advancedstages of development. Each has specific advan-tag es and d isad vantage s. The princ ipa l corpo ra-tions de velop ing g asifiers included Texac o, Inc.,Shell, the Allis Chalmers Corp., Dow Chemical,the British Gas Corp. (BGC), Kellog Rust (the KRWgasifier), and Lurgi Gesellsc ha ften. The la tte r twoco rpo rations have c oop erated in the deve lop -ment of a single gasifier design known as theBGC/Lurgi gasifier.

The c urrent sta tus of ga sifica tion systems be -ing developed by these corporations is sum-marized in table 9-4. Activities directed towards

the development and commercial deployment of

G7synthetic Fuels A s s o c i a t e s , Inc., Coa/ Gasification SyStemS.’ AGuide to Status, Applications, and Economics (Palo Alto, CA: ElectricPower Research Institute, 1983), EPRI AP-3109.

the gasifiers have not been directed just to IGCCsbut to a considerably broader range of appli-cations.

Among the major gasifier systems which hadoperated in nonelectric applications in the UnitedStates by mid-l985 were the Illinois Power Co. ’sWood River fac ility, whic h used a KILnGAS ga sifierde velope d by the A llis Cha lme rs Corp. p rimar-ily for IGCC a pplications; and Tennessee Eastma nCo. ’s ga sific a tion p lant in Kingsport, Tennessee ,which used Texaco gasifiers. Other importantga sific ation plants have b een o pe rate d b y theTennessee Valley Authority; and by the GreatPlains Gasification Associates in Beulah, NorthDakota. Ma ny of these p rojects have rec eivedFederal support through DOE or the SyntheticFuels Corp. Coal gasification meanwhi!e has beenpursued ove rsea s a s we ll.

Only one typ e o f ga sifier, de velop ed by Tex-aco, had by mid-1985 been deployed in an IGCCinsta lla tion i n the United Sta tes—the Co ol Wate rProject, the world’s first demonstration of anIGCC using commercial-scale components. Con-c ep tua l stud ies and othe r ac tivities c onc erningthis plant began in the mid-l970s and in 1979Southern Ca lifornia Edison a nd Texaco signed a nag reem ent w hic h formally initiated the p roject.

The effort later was joined by EPRI, BechtelPower Corp., the Japan Cool Water Program Part-nership, the Empire State Electric Energy ResearchCorp. (a group of New York Sta te utilities), SOHIO,and Gene ral Elect ric . Sizab le loans were p rovidedby banks in the United States and Japan. EPRI hasma de the g rea test funding c ontribution to theprogram.

As the project progressed, oil prices dropped.Avoide d c osts, the b asis for the p urc hase priceof po wer prod uce d b y the plant, conseq uentlywould not be as high as was originally anticipatedby the projec t spo nsors. They w ere c om pe lledto obt ain price supp ort gua rant ee s from the Syn-thetic Fuels Corp. These amo unted to a ma xi-mum of $120 million, to be p rovided during the

plant’s demonstration period, running throughJune 1989.68

bapaul Rothberg, Synthet/c Fuels Corp. and National Synfue/s policy (Washington, DC: Congressional Research Service, 1984), IssueBrief Number IB81 139.




Table 9-4.—Status of Developing Gasification Technologies

Shell

Dow

q

q

q

q

1

uq Keystone (Johnston, PA) China

(2 gaslflers) (1 gasifier)

uKILnGAS (Wood River)

(1 gasifier)

SOURCE M Gluckman, Electric Power Research Institute personal communication, June 1985

Another IGCC unit soon will be under con-struction in Plaquemine, Louisiana. Designed byDow Chemica l, the plant is expecte d to b eginoperating in 1987 with a substantial contributionfrom the Synthetic Fuels Corp.–$62O million inprice guarantees. Most recently, three U. S.utilities—the Potomac Electric Power Co., the Vir-ginia Elec tric Pow er Co ., and the Detroit EdisonCo.–have initiated the steps which could leadto the de ployment of three IGCC units during the1990s.69

As suggested above, the development of gasifi-cation technologies has generally dependedhea vily on Fed eral supp ort through the Synthet icFuels 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 CoalGasification Combined Cycle Power Plant,” paper presented at theEPRI and Kernforschungsan lage julich Conference on Coal Gasifi-cat ion and Synthet ic Fuels for Power Generat ion, San Francisco,C A, April 1985.

has supported the development of gasificationthrough DOE and its predecessor agencies. Mostof this DOE support has been for research, de-velopment; and demonstration of surface coalgasification .70 As indicated in table 9-2, this sup-port peaked in 1978 at $208 million and has de-clined since to a proposed $15 million for fiscalyea r 1986.

Efforts in the private sector on behalf of theIGCC have emanated mainly from the equipmentdeve lope rs in the p rivate sec tor, interested utili-ties and EPRI. The vendors of both the turbinesand the gasifiers are large corporations whichhave funneled considerable capital into the re-search, development, and demonstration of their

prod uc ts, While the investments som etime s areTOsu~ace c o a l gasificationis distinct from underground coal gasifi-

cation. The latter involves technologies which are very differentfrom those considered here and are not candidates forIGCC sys-tems in the 199os.




directed primarily toward the application of theequipment to the IGCC (as was the case at theCool Water Plant), they usually are intended toadvance the technologies over a wider variety ofapplications.

EPRI has devoted a large portion of its budget

towards the development of the IGCC, boththrough numerous stud ies and through its fund-ing of the Cool Water Plant. EPRI also parentedthe Utility Coal Gasification Association (UCGA),a group of ut ilities interested in the IGCC. Formedby early 1983, the association collected and dis-semi nated information on the technology and itsapplications, and otherwise encouraged its de-ployment. The early commercial users of theIGCC probably will be among the association’smembers.

In addition to participation in the UCGA, some

utilities have been considerably more involvedin the tec hnolog y. Southern Ca lifornia Edison, fo rexample, invested heavily in the Cool Waterproject a nd ha s be en very ac tive in promotingthe IGCC.


Three p rima ry c riteria must b e m et if the IGCCis to make a sizable contribution to generatingcapacity in the 1990s. First, a number of utilitiesmust be convinced the technology will performas required over its entire 30-year lifetime. Sec-ond, the combination of cost, performance, andrisk will have to be superior to tha t of b oth con-ventional and other developing technologies—including atmospheric flu idized-bed combustion(AFBC), Third , projec ts p robab ly must be initiate dno later than late 1993 if they a re to com e on-line within the 1990s.

Taken to ge ther, these elem ents sugg est tha t ad -ditional utilities indeed may step forward over thenext 3 to 8 yea rs and initiate IGCC p lants. How -ever, the c urrent e videnc e sugg ests othe r fac -tors--the most imp ortant o f which a re d iscussedbelow–may weigh against initiation of manyprojects during the short time available. Conse-quently, there is a possibility that only a few–pe rhaps a ha lf-dozen or less–lGCCs will be op -erating in the United States by the end of thecentury.

Equipment Cost and Performance.–Many ofthe individual components of the IGCC havebeen commercially applied for many years.Among available components is equipmentwhich either already is adequate for IGCC appli-cations or probably will be in the near future.Other components, though, are relatively newand in fact may be unique to the IGCC. Evidencefrom the Cool Water plant experience to date andfrom other sources indicates that these compo-nents will perform adequately and will not in-volve excessive cost, However, experience withIGCCS is still limited, and while the Cool Waterperformance has been very good, many utilityinvestors ma y still lack sufficient confidenc e i ncomponent cost and performance estimates.Consequently, even if cost reductions or perform-ance improvements are not in fact necessary, un-certainty about equipment cost and performancemay be a serious impediment to timely in-vestment.

Cost and Performance Data/Technology Dem-onstration.—An important concern about theIGCC in the eyes of investors ove r the ne xt 5 to7 years will be the lack of demonstrated experi-ence with the entire system, and hence the lackof proven integrated cost and performance data.The Co ol Wate r plant a nd the Dow fa c ility prob -ably will be the only IGCCS to which investorsma y turn for a reference p oint,It ispe rhap s forthis reason an EPRI in mid-1984 tolda congressional subcommittee that the deploy-ment of at least one or two additional IGCC dem-onstrations in the United States, using perhapsthe BGC or Shell gasifiers, was a very high pri-ority in promoting clean coal utilization in the1990s,71others too have cited the need for fur-ther d em onstrations.72

T DWain spencer, Eectric Power Research Institute, testl monypresented in hearings held by the Subcommittee on Energy De-velopment and Applications, House Committee on Science andTechnology, U.S. Congress, Th e Status of Syrrthetic Fue/s and Cost-Shared Energy R&D Facilities (Washington, DC: U.S. GovernmentPrinting Office), No. 106, June 6, 7, and 13, 1984, p. 203.

Tzsee: 1 ) ‘‘Firmsplan CGCC Plant i n Michigan,Syrrfue/s Week,

vol. 6, No. 13, Apr. 1, 1985, p. 1. 2)“Va. Power Plans 400 MWCGCC 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, anda combined-cycle system to form a “coalgasificatiordcom binedcycle” unit or CGCC. The utility has proposed that the Federal Gov-ernment subsidize the project. It reported that even withoutFed-




Utilities, of course, will examine their own ex-periences and those of others with gas turbines,stea m turbines, and combined-c ycles, and willscrutinize gasifiers operating both here andab roa d in nonelec tric ap plications. The fa vora-ble experience with those components certainlywill help to reduc e the risks perceived by inves-tors, but they are unlikely to fully offset the lac kof experience with the IGCC itself.

Note tha t as experienc e with the Cool Waterplant accumulates, experience with AFBCs willbe accumulating much more rapidly as bothdemonstration and commercial plants come on-line under both utility and nonutility ownershipand under different operating conditions. It islikely that the AFBC, with its larger number ofoperating plants and its favorable cost and per-formance, will pose a formidable challenge to theIGCC for initial utility commitments.

Licensing and Permitting Delays.–A majorsource of delay for IGCCs couId lie in the licens-ing and pe rmitting p roce ss. Thoug h the e nviron-me nta l imp ac ts of the IGCC will be less seve rethan those of its conventional competitors, itnevertheless does have significant impacts on theenvironment. Concern over the impacts could re-sult in delays, particularly if the potential envi-ronme ntal impa c ts are not prec isely known byeg uIators, or where imp ortant reguIa tory issuesregarding the technology have not been satisfac-torily resolved,

For examp le, very little data are a vailab le onthe long-term leaching characteristics of gasifica-tion ash/sIag. Furthermore, the analytical toolsnecessary to adequately determine the possible

eral support, it would install the combined-cycle portion of the plantand operate it beginning in 1993. But the gasification portion ofthe project would be delayed without Government support; thesystem would employ natural gas instead of gas produced from coal.Referring to the gasification portion of the system, officials of theutility reportedly stated that “the technology is unproven and theutility decided that privately financing its early introduction in themarketplace would be ‘an unreasonable risk to (Virginia Power)ratepayers and stockholders. ’ “A company official was quoted assaying: “We are a risk averse industry. Without some Governmenthelp to defray the risk, our implementation of the gasification tech-nology would just have to wait. ”According to the utility, withoutGovernment assistance, the “conversion to coal gasification couldbe subsequently pursued when the technology and economics be-come favorable about ten years later or 2003. ”

impacts of the solid waste in a specific environ-ment, and to properly develop or assess meas-ures to m itiga te those imp ac ts, are lac king. Yetsuch data and methods are required to properlydetermine whether or not the solid waste shouldbe treated as hazardous or nonhazardous, andin evaluating specific plant proposals .73

Certainly mea sures can b e ta ken by g overn-ment authorities to expedite the IGCC’s progressthrough regulatory channels. ’d Regulatory bod-ies ma y provide an IGCC tec hnology with spe -cial treatment, as was the case in California withthe Cool Water project, Under such circumstances,de lays ma y be red uce d substantially. More im-portantly, constructo rs of initia l plants can wo rkclosely with regulatory bodies to ensure efficientresolution of potential concerns. If either of thesepaths are followed, the amount of IGCC capacityby the year 2000 could be substantially highertha n wo uld o therwise b e the case. If suc h is notthe rule, however, delays could result becauseof the newness of the technology that could seri-ously imped e the a bility of project promo ters tobring IGCCs on-line before the end of the century.

Stringency of Environmental Regulations.–A major advantage of the IGCC over its conven-tional competitors is its potential to operate withlower nitrogen oxide and sulfur oxide emissions,at incremental costs lower than those associatedwith equivalent emission reductions in a conven-tiona l coa l plant. Where em issions are seve rely

limited, the IGCC is able to capitalize on thisad vanta ge . Where such limitations are lac king,however, the IGCC is less able to successfullycompete with the more conventional alternatives.The lack of stricter regulations which requirelower emissions consequently may reduce incen-

TJMasood Ghassemi and George Richard, “Regulatory Require-ments for Land Disposal of Coal Gasification Waste and Theirim-plications for Disposal Site Design, ”Energy Sources, vol. 7, No.4, 1984, pp. 357-376. The authors state that “. . . environmentalissues involving disposal of these wastes may constrain the com-mercial development of gas supply technologies” (p. 358).

Zdsee: 1 ) MasoodGhassemi and George Richard, “Regulatory Re-quirements for Land Disposal of Coal Gasification Waste and TheirImplications for Disposal Site Design, ” op. cit., 1984. 2)ArturoGandara, “Environmental Considerationsin Siting Alternative FuelGenerating Facilities, ”California Energy Commission News and Comment, No. 13,spring 1984, pp. 4-18 (reprint of testimony pre-sented to the Advisory Committee on Federal Assistance on Alter-native Fuels, Oct. 31, 1983).




tives to more extensive deployment of IGCCs inthe 1990s.

Fuel Use Restrictions.–An IGCC plant typi-ca lly will require a ccess to natural ga s. If the in-stallation is built in stages, the gas turbines canbe installed first and can use natural gas as an

interim fuel until the g asifiers a re c om p leted . Also,natural gas can be used during the lifetime of theplant to replace or supplement the synthetic gasproduc ed by the g asifiers. As explained ea rlier,the Fuel Use Ac t p rohibits the use o f na tural ga sunder certain co nditions. An exemption wouldbe required from the Federal Government whichwould permit the use of natural gas in an IGCC.This c ould c ause d elays in a projec t, and de nialof an exemption may even lead to project aban-donment.

Atmospheric Fluidized-BedCombustors

History and Description of the IndustryIn the early 1920s, fluidized beds were applied

for the first time in Germany to produce com-bustible gases from coal. Subsequent develop-ment led to their use in “ cracking” the heavyfractions of petroleum, first in 1942 and exten-sively thereafter. Further efforts led to their ap-plica tion to othe r industria l uses and eventua llyto p rod uc e stea m. The first c om me rc ial fluid ized -be d bo iler be ga n op eration in Franc e in 1955.Serious deve lopm ent of fluidized -bed boilers d idnot begin in the United States until 1965.75

By 1976, DOE was funding the construction ofthe first industrial-sized AFBC boiler in the UnitedStates–a 30 MWe pilot plant in Rivesville, WestVirginia. Several more small industrial AFBCswere built in the late 1970s and early 1980s asthe technology progressed rapidly and smallAFBCs became competitive with conventional

options in the marketplace. Coincident with theemergence of small AFBCs during this period wasthe implementation of PURPA, which set thestage for a rap id increase in the dep loyment ofAFBCs in cogeneration applications.

By early 1985, over 2,200 AFBCs were opera t-

ing in China, and between 200 and 300 wereoperating or under construction elsewhere in theworld, mostly in Western Europe, Japan, and theUnited States. Most of those outside China weresmall industrial units. Over 40 small AFBCs wereoperating or under construction in the UnitedStates by early 1985, and by mid-1985, over adozen privately financed commercial AFBC co-ge nerato rs we re b eing b uilt in the United Sta tes.Unit sizes of these U.S. plants range from 15 to125 MWe; none of these fully commercial unitsis owned by a n elec tric utility. ’G

The electric utilities are, however, showing agrow ing interest in the tec hnolog y. The thrust o futility-sponsored R&D has been the developmentof AFBCs with capacities in excess of 100 MWefor retrofit to existing po we rplants or for entirelynew plants. Toward this end, three demonstra-tion projects are currently under construction.Two are retrofit units be ing inco rporate d into ex-isting plants .77 The third is a 160 MWe demon-stration unit a t t he Tenne ssee Valley Authority’ s(TVA) Shawnee Steam Plant in Paducah, Ken-tucky. The retrofit units will begin operating in1 to 2 yea rs; the TVA unit is expe c ted to be firedfirst in 1989.

Central to the utility efforts has been the Elec-tric Power Research Institute. By 1977, EPRI hadbuilt a 2 MWe pilot plant. This was followed bya 20 MWe plant which began operation in 1982.EPRI now is partly funding all three of the abovementioned demonstration projects.

75helton Ehrlich, “Historyof the Development of theFluidized-Bed Boiler, ”Proceedings of’ the 4th International Conference on Fluidized-8ed Combustion, Dec. 9-11, 1975 (McLean, VA: MITRE

Corp., May19761, Publlcatlon M76-36,pp . 15-20; and A.M. Squires,“Contrlbutlons Toward a History of Fluldlzatlon, ” Proceedirrgs ofthe 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 ChemicalEngineers,1983), pp. 322-353.

TbFor a comprehensive review of the current status of AFBC’S,see: Bob Schwieger, “Fluidized-Bed Boilers Achieve CommercialStatus Worldwide, ”Power, vol. 129, No. 2, February 1985, pp.S-1 through S-16.

‘These are the Colorado Ute 100 MW e Nucla unit, scheduledto begin operating In 1987; and the Northern States Power Co. ’s125 MWe Black Dog Unit 2, expected to beIn operations in 1986.Note that one small retrofit unit already has operated. Thisis theNorthern States Power Co.’s French Island Plant, Unit #2. The 15MW e retrofit began operationIn 1981.




The Fed eral Gove rnment to o has supp orted thetechnology with a program which first led to theconstruction of the Rivesville plant in 1976 andsubsequently to a series of pilot and demonstra-tion facilities. Federal support peaked in 1980 atalmost $30 million and has dropped sharplysince . By far the large st p ortion of Fed eral fund-ing for the AFBC no w is channeled into the TVA160 MWe demonstration plant–$30 million ofthe $22o million required for that project.

The industry which supplies AFBCs is large andwell established. About 50 companies sell theindustrial-sized boilers worldwide. Often, theseare the same companies which sell conventionaltec hnolog ies. The a do pt ion of the AFBC b y thesefirms is likely to facilitate its deployment in theUnited Sta tes.


Four ap plica tions of the AFBC may b e imp or-tant o ver the next 15 yea rs: grass-roo ts elec tric -only plants, retrofit electric-only plants, cogen-era tion insta lla tions, and nonelec tric systems. Theelect ric-only units are likely to be de ployed byutilities, whereas the cogeneration and nonelec-tric units probably would be built and operatedby nonutility investors.

Current evidence suggests that the electric-onlyretrofit units, and cogeneration plants and non-electric facilities financed by non utilities may verywe ll dom inate the AFBC m arket in the 1990s. The

rapid accumulation of operating experience withthese units and their short lead-times—substan-tially shorter than those which wou Id character-ize large 100 to 160 MWe grass-roots, electric-only units’ B—makes their near-term prospectsvery bright.

The small AFBCs are being deployed exten-sively and many are expected to be initiated overthe next dec ad e. The ma rket ap pe ars to b e vig-orous and growing, and suppliers abound. Nobarriers unique to these small units are expectedto impede deployment, though some problems

zsRetrofit u nits i n many cases involve verylittle regulatory delay,as they are deployed at preexisting plants.Cogeneration units andnonelectric units commonly are very small, are not owned by util-ities, and are not subject to the same extensive regulatory delayswhich characterize large utility owned projects.

common to nonutility technologies—such as thead eq uac y of PURPA avoided cost payments—may develop.

A substantial utility retrofit market has also beenidentified; strong evidence indicates that numer-ous pow erplants in the United Sta tes are ca ndi-

dates for AFBC retrofits. Most are small (less than200 MWe), old units which are co nfigured so a sto allow a retrofit. Retrofit units probably willdominate early utility involvement with the AFBC.By the 1990s there will be more operating experi-ence with retrofit units than with large grass-rootunits. Such retrofits appear to offer utilities a lowcost option for improving existing capacity; theyalso require less time to dep loy tha n the grass-roots plants. Commercial retrofits therefore couldbegin coming on-line before 1995, and largenumbers may commence operating before thec lose of the c entury.

By the ea rly 1990s, experienc e with the largeutility demonstration units, expected to beginoperating in the Iate 1980s, as well as experiencewith the smaller AFBCs outside the utility indus-try, may foster both technical improvements andutility confidenc e. The p rospe c ts ap pe ar to b ego od that extensive utility orde rs of large, c om -mercial, grass-roots plants could begin at thattime;79 these plants could provide substantialam ounts of e lec tric ity by the late 1990s. Delaysof a ny kind, how ever, may limit the p otential ofAFBC g rass-roots p lan ts within th is c en tury. Suc hdelays could be occasioned by problems or un-certainties associated with the performance of thelarger AFBC units, or by difficulties in the licens-ing or permitting process.

Compressed Air Energy Storage

Industry Description, History, and OutlookMa jor efforts in the United Sta tes on b eha lf of

c om pressed air energy storag e (CAES) be ga n inthe latte r half of the 1970s, stimulated by the Fed -eral Government, the Electric Power Research in-stitute, interested utilities, and others. Most

79seeRobert Smock, “Utilities Look to Fluid Bedas Next Stepin Boiler Design, ”Electric Light and Power, vol. 62, No. 7,July1984, pp. 27-29; and Taylor Moore, “Achieving the Promise ofFBC,” 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 pre-liminary engineering-design studies, completedin 1981, which investigated the utility-specific ap-plication of CAES to the three major storagemedia (hard rock, salt, and aquifer CAES). Shortlybefore these studies were finished, in November1980, the Soyland Power Cooperative, Inc., inDecatur, Illinois, formally committed itself tobuilding 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 Decemberof 1978. Since that time, the 290 MWe Huntorfunit has operated nearly 7 years without seriousproblems. Furthermore, a smaller 25 MWe CAESunit recently was completed in Italy. Despite thesuccessful operation o f the Germa n p lant, theconstruction of the Italian plant, and efforts in theUnited States to deploy CAES plants here, thiscountry still is without even a demonstrationplant. The Soyland s plant wa s canceled , andsince then no U.S. utility has initiated construc-tion of a CAES plant.

Federal support rapidly declined after peakingin 1978-79. Beg inning w ith fisc a l yea r 1983, DOEhas provided no support to the technology (seetab le 9-2). Others, howe ver, have c ontinued pro-motional efforts. Although no CAES plants arenow be ing constructed , EPRI and a private firmare currently performing an initial screening anal-ysis of CAES on 10 utility systems. EPRI also is

planning to provide funds in support of initialp lant siting stud ies with interested utilities and insupport of the installation of two or more soMWe “mini-CAES” plants.80 Additionally, fourc onsortia of architec t/ eng ineering firms, turbo-machinery suppliers and cavern builders havebeen formed to supply initial plants.81

These deve lopm ents sugg est t ha t seve ra l mini-CAES units could be initiated and built by theearly 1990s. There are, however, no strong indi-c ations that a ma xi-CAES plant (w ith a c ap ac ityof several hundred mega wa tts) will be initiat edin the next seve ra l years and will be on-line within

the first few years of the 1990s. Since a maxi-CAESplant will require a lead-time (including licens-ing and pe rmitting) o f ap proxima tely 5 to 8 yea rs,plans to build any commercial maxi-CAES unitsmust be underway no later than the end of 1994for contribution to generating capacity within thiscentury. Current evidence suggests that utilityorde rs wo u Id b e unlikely without a U.S. de mo n-stration p lant.

The prospec ts for mini-CAES p lants in the UnitedSta tes app ea r to b e muc h brighter. A mini-CAESplant req uires a lea d-time o f app roxima tely 4.5to 6.5 years. If several are initiated by theendof 1986, they could be on-line by mid-l 990. Ifextensive mini-CAES c apa c ity is to b e on-line bythe year 2000, however, plans to build suchplants should be initiated no later than mid-l990.This would allow approximately 5 years for thedemonstration units to operate and for a substan-

tial market de ma nd to d evelop.Suc h rap id g rowth in dem and is po ssible, given

the favorable Ievelized cost which might charac-terize CAES units (see chapter 8), and given thefact that many of the components are conven-tional and commercially available. Furthermore,the appropriate geology underlies 75 percent ofthe United States, so the market is potentiallylarge and varied. EPRI estimates that CAES tech-nology has the potential of supplying 4 to 8 per-cent of peak demand by the year 2000.82

To a ccom plish this will require tha t lead-time sbe kept short, and that other impediments be suc-c essfully c leared . The ma jor imp ed iments are d is-cussed be low. Unless these a re effe c tively andspeediIy eliminated, demand is more likely to in-crease gradually, with large numbers of ordersunlikely before the latter half of the 1990s.

Major Impediments to the CommercialDeployment of CAES Systems

The major impediments tohigh deploymentlevels for CAES by t he e nd of the c entury are o ut-lined below.

BODa\,ld Rigney, Electric Power Research I nstltute, ‘‘Notes onCompressed Air Energy Storage, ” provided to Brian E. Curry, North-east Utilitles, March 1985.

~’ Ibid.

82Robert 6. Schai n ker, Executive OL(erviek$t: C O f77pKS6’d Ai r

Energy Storage (CAES) Power P/anrs (Palo Alto, CA: Electric PowerResearch Institute, August 1983),mimeo.

38-743 0 - 85 - ]()




Uncertainty Regarding Plant Cost and Per-formance.–As discussed above and in chapter4, while all of the individual above-ground com-ponents with the exception of the recuperativeheat exchang er have b een emp loyed in othercommercial applications, the performance of in-tegrated 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 tem-perature on the reservoirs; these a t p resent arenot p rec isely know n.ss The p rime c onc ern is leak-age of the air from the reservoir. Until one ormore units have been installed and operated forat least several years, uncertainty will still trou-ble investors and is likely to strongly inhibit in-vestment in CAES.

Licensing and Permitting Delay s.–As dis-cussed in chapter 4, several regulatory problemsc ou Id d elay d ep loyment of a CAES p lant. Theseplants employ a gas- or oil-fired combustion tur-bine. The ope rato r of the p lant must ob ta in anexemption from the Powerplant and IndustrialFuel Use Act of 1978. Other delays might resultfrom environmental impacts; regulatory problemsmight a rise rega rding a tmo spheric em issions, we lldrilling and c onstruc tion, wa ter co nsump tion andc onta mination, and c ave rn exca vation. The rela-tive inexperienc e o f all conc erned p arties withCAES c ould further comp lic at e the lic ensing andpe rmitting proce ss.

B a t t e r i e s

Industry Description, History, and OutlookBatteries first appeared in the 19th century and

were quickly applied to railroads, telephones,and lights, Near the beginning of this century, theall-electric automobile appeared using batteries,but it was not until 50 years later that utilities usedbatteries to level loads in urban areas. For exam-ple, batteries were used in Chicago to compen-sate for the effects on the direct-current (DC) elec-tric system of elevators and lights in largedowntown build ings.84As the use o f DC power

~~DeCISOn FOCUS Inc., Compressed-Air Energy Storage: Commer-cialization Potential and EPRI Roles in the Commercialization Proc- ess (Palo Alto, CA: Electric Power Research Institute, 1982),EPRIEM-2780.

8~Jen ny Hopkinson, “The New Batteries, ”EPR/ journa/, vol. 6,No. 8, October 1981, pp. 6-13.

systems declined in the1930s, the use of ba tte r-ies by utilities declined as well.85

Over the past dozen years, however, batteriesfor stationary applications have been the subjectof renewed interest and development. Rapidtechnical progress has been made and batteries

may eventually be used extensively in grid-connected app lica tions to enhance p eak load ca -pacity.

At the forefront of battery development havebeen manufacturers in Western Europe, Japan,and the United Sta tes. Ofte n closely affiliated withthese R&D programs have been parallel effortsto develop batteries for mobile applications. Ef-forts directed towards stationary applications inthe United States have been led by DOE, EPRI,and interested utilities, as well as by battery man-ufacturers themselves.

DOE and EPRI together have funded the con-struc tion and op eration of the na tional Batt eryEnergy Storage Test (BEST) Facility in New Jer-sey as a national center where prototype batterymodules are tested and evaluated, along withothe r relat ed eq uipme nt. The fac ility first be ga noperating in 1982. By May 1985, both advancedlead-acid and zinc-chloride batteries had beentested in the fa c ility. Sod ium-sulfur (or be ta ) a ndzinc-bromide batteries are expected to be in-stalled around 1989 or 1990.

The Jap anese me anwhile have vigo rously de -veloped batteries under the auspices of MITI’sMoonlight program since fiscal year 1980. Thegoal of the program is to demonstrate two 1MWe, 8 MWh battery installations by 1990. Asis the case in the United States, both utilities andtheir customers have been identified as primemarkets. 86Alrea dy the b att eries are b eing usedby utility customers in Japan; the Japanese NationalRailways, for example, has installed a Japanese-

Bspeter A. Lewis, Elernerlfsof Load-Leveling Battery Design for System Harming, paper presented at the International Symposiumand Workshop on Dynamic Benefits of Energy Storage Plant

Operation.My Arlga, et al., Central Research Institute of Electric power in-

dustry (Japan), “Optimum Capacities of Battery Energy Storage Sys-tem for Utility Network and their Economics, ”Advanced Energy Systems–Their Role in Our Future: Proceedings of the 19th /nter-society Energy Conversion Engineering Conference, Aug. 19-24,1984 (San Francisco, CA: American Nuclear Society, 1984), paper849050, pp. 1075-1080.






ods, and under the variety of conditions expectedof actual commercial plants. Until such demon-strations have taken place, extensive investmentis unlikely.

Equipment Cost and Performance. -Until dem-onstrations have been completed, and experi-ence has accumulated, it will be difficuIt to pre-cisely identify cost and performance impedimentsto commercial applications of batteries. A keyvariable affecting the future of lead-acid batter-ies will be the price of lead; low prices will berequired to maintain acceptable costs.

For zinc-chloride ba tteries, the ma jor variab leprobably will be the level of demand for the largestationary batteries. Low costs will depend onmass production; mass production in turn will re-quire a sizable market. Vendors will be reluctantto invest in manufacturing capacity without strong

indica tions that the m arket wiII absorb the qua n-tities prod uc ed ; yet the market is unlikely to d e-velop until ma ss prod uc tion d rives prices do wn.This “ chicken-or-the-egg” dilemma ma y be theleast tractable of the impediments confronting de-velopers of the zinc-chloride battery in the 1990s.This problem is considerably less serious with thelead-acid battery because many of the lead-acidbattery’s components can be produced with ex-isting faciIities dedicated to pre-existing markets.Lead-acid battery prices therefore are less sensi-tive to initial demand for the large stationary units.

Utility Rate Structures.—The pric e c ustom erspay for the use of utility-generated electric powerduring peak periods may differ from the pricepaid during off-peak periods, A demand chargemay be imposed based on a customer’s peak de-

mand (cost/kWe). Or, the energy charge (cost/ kWh) ma y be higher during p ea k period s thanduring other times of the day. Hence, there is anincentive for the customer to shift c onsump tionaway from peak periods. One way of doing thisis with batte ries. With low d ema nd and energycharges or no incentive pricing, however, a bat-tery may not be justified. Or, even if the chargesare high at present, the possibility that they maydecrease (relative to off-peak rates) discouragescustomer investment in batteries. Current evi-dence indicates that both low charges and un-certainty over charges could be major impedi-me nts to custom er investments i n ba tte ries.95

Licensing and Permitting.–Generally, the in-stallation and operation of a battery unit willcause impacts far less serious than those associ-ated with most competitors. In most cases, fewregulatory delays are likely to result. But for zinc-

chloride bat teries, serious licensing a nd permit-ting d elays might occur as a result of the po ssi-bility that large volumes of chlorine or brominemight be released accidentally from a proposedbattery installation. Consideration of the possi-b le prob lems is not likely to stop de ploym ent inany particular instance. But d ifficuIties, pa rticu-larly with regulatory officials not well acquaintedwith the the technology or where the site is ina densely popuIated area, couId arise and causelengthy delays.

95 B e c h t e l Group , [ flc., @dS;~i/l~y Assessment of Customer-Side-of-the-Meter Applications for Battery Energy Storage (Palo Alto, CA:Electric Power Research Institute, 1982), EPRI EM-2769; and Elec-tric Power Research Institute, Uti/ity Battery Operations and Ap-plications (Palo Alto, CA: Electric Power Research Institute, 1983),EPRI-2946-SR.



Chapter 10

Federal Policy Options



CONTENTSPage

Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. ................253Sta tus and Out look fo r the Developing Tec hnologies . . . . . . . . . . . . . . . . . . . . . .......253

Solar Photovoltaics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ...........253Solar Thermal Electric Plants .., . . . . . . . . . . . . . . . . , , . . . . . . . . . . . . . . . . . ...259Wind Turbines . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .............262Geothermal Power. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..266Fuel Cefls . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .............269Integrated Gasification/Combined-Cycle Plants . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 272Atmospheric Fluidized-Bed Combustors. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 277Compressed Air Energy Storage . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ......278Batteries . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. ...280

List of TablesTable No. Page 9-1. E s t i m a t e d M a g n i t u d e o f E n d - U s e M a r k e t s f o r P h o t o v o l t a i c s , 1 9 8 4 . . . . . . . . . . . . . . 2 5 59-2. Federal Program Funds in Support of Developing Technologies . . . . . . . . . . . . , . .2559-3, Projected 1986 Photovol ta ic Shipments by Domest ic Manufacturers . . . . . . . . . . . .2569-4. Sta tus of Developing Gasif icat ion Technologies . . . . . . . . . . . . . . . . . . . . . . . . . . . . .274

List of FiguresFigure No. Page9-1. 1984 World Photovoltaics Supply . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .., ..254



Chapter 10

Federal Policy Options

OVERVIEW

Over the last several years, the need to diver-sify the electric ity generation m ix has bec om e in-creasingly clear, part of the strategy for meetingthis policy objective has been sustained devel-opment of new electric generating technologies.With considerable uncertainty in load growth aswell as other major policies affecting utility andnonutility decisions about new and existingpower generating capacity, the attainment of adiverse generation mix has taken on added d i-mensions. Because of this uncertainty, it may beprudent to accelerate the availabili ty of the tech-nologies discussed in this study so that they couldma ke a greater co ntribution in the 1990s thancurrently is expected.

Seeking diversity in electricity supply optionsis now not only being pursued to reduce depend-ence on oil but also in anticipation of the varietyof future circumstances as discussed in the chap-ter 3, such a s more stringe nt c ontrol of a ir pollu-tion emissions or increased availability of natu-ral gas. Developing technologies are of interestin the short term since they might contribute toensuring a reliable and economic supply of elec-tricity over the next two decades under a vari-ety of these future circumstances. Many of thesetechnologies also offer promise of fuel flexibility,increased efficiency, and other advantages. Anincreased contribution before the turn of the cen-tury, however, will require accelerated develop-ment of these new generating technologies, in-c luding p rog ress in a numb er of c ritica l area s. Thisis bec ause at the c urrent rate of d evelopment veryfew of the technologies considered in this assess-ment are likely to be d ep loyedextensively in the1990s,

This chapter discusses a range of alternativepolicy initiatives that could accelerate the com-mercial deployment of developing generating andstorag e te c hno log ies in the 1990s, The g oa ls andoptions are summarized in table 10-1. The firstthree:

Table 10-1 .—Policy Goals and Options

Reduce capital cost, improve peformance, and resolve uncertainty: 1. Increase Federal support of technology demonstration2. Shorten project lead times and direct R&D to near-term

commercial potential3. Increase assistance to vendors marketing developing

technologies in foreign countries4. Increase resource assessment efforts for renewable

energy and CAES resources (wind, solar, geothermal,and CAES-geology)

5. Improve collection, distribution, and analysis ofinformation

Encourage nonutility role in commercializing developing technologies: 1. Continue favorable tax policy2. Improve nonutility access to transmission capacity3, Develop clearly defined avoided energy cost

calculations under PURPA4. Standardize interconnection requirementsEncourage increased utiiity involvement in developing technologies: 1. Increase utility and public utility commission support

of research, development, and demonstration activities2. Strengthen provisions for utility subsidiaries involved

in new technology development3. Resolve siting and permitting questions for developing

technologies4. Other legislative initiatives: PIFUA, PURPA, and

deregulationResolve concerns regarding impact of decentralized generating sources on power system operation: 1. Increase research on impacts at varying levels ofpenetration2. Improve procedures for incorporating nonutility

generation and load management in economicdispatch strategies and system planning

SOURCE Office of Technology Assessment

A. Reduce capital cost, improve performance,and resolve unc ertainty,

B. Encourage nonutility role in commercializing developing technologies, and

C. Enc ourag e increa sed utility involvem ent indeveloping technologies,

are the primary goals; while the fourth:D. Resolve c onc erns reg arding the impa c t of

decentralized generating sources (and loadmanagement) 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 cha pters 4 and 8, the c urrentcost and performance characteristics (includinguncertainty) of developing generating and stor-age technologies considered in this assessmentgenerally do not yet compare favorably with ei-ther conventional generating options or otherstrategic options such as load management andlife extension of existing powerplants. Of particu-lar concern is the uncertainty in cost and perform-ance anticipated in early commercial utility ap-plications. Even in the case of load management,already being pursued aggressively by many util-ities, widespread deployment of load manage-ment in the 199os will depend on continued ex-perimentation by utilities to resolve operationaluncertainties; the refinement of load manage-ment equipment and techniques including ade-quate demonstration of communications andload control systems; development of incentiverate structures; and a better understanding of cus-tomer acceptance.

The following are a lternative p olicy op tionsaimed at reducing cost, improving performance,and resolving unc ertainty in both c ost a nd p er-formance.

Option Al: Increase Federal support oftechnology demonstration

A critical milestone in both utility and nonutil-ity power producer acceptance of new technol-og y is completion of a commerc ial dem onstra-tion prog ram. There is c onsiderab le de ba te in theindustry over what constitutes a demonstrationprogram, but usually two basic categories are dis-tinguished. One is a proof-of-concept phasewhich provides the basic operational data forcom mercial designs as well as test fa c ilities de-signed to prove the viability of the technology un-der non laboratory conditions, and to reduce costand p erformance unc erta inties. The other in-

volves multiple applications of a more or less ma-ture technology designed to stimulate commer-cial adoption of the technology. In theory thedistinction seems clear; in practice, it sometimesis not. Generally, though, activities in the first cat-

egory are necessary for demonstrating technicalfeasibility, and activities in the second categoryare necessary for demonstrating commercialreadiness and for accelerating acceptance by util-ities or nonutility power producers.

The length o f the a pp rop riate d emo nstrationperiod will vary considerably by technology,However, adequate demonstration periods (per-haps many years for larger scale technologies) arecrucial to promoting investor confidence. More-over, the nature of the demonstration program—i.e., who is participating, who is responsible formanaging it, and the applicabiIity of the programto a wide variety of utility circumstances—is cru-cial too, if utilities, in particular, are eventually

to b uy the tec hnology.Many utility decision makers argue that the per-

ceived and real obstacles to adoption of devel-oping generating technologies can be removedby “well-managed federally sponsored incentivesand projects.’” A key ingredient is the na ture ofthe relationship between government and indus-try in such ventures. A cooperative research anddevelopment (R&D) partnership has proven to bea key ingredient in many successful demonstra-tion p rogram s. Demonstration prog rams shouldhave the following characteristics:

q

q

q

The p rivate sec tor should have c onsiderab leinfluenc e in the selection of te c hnologies fordemonstration as well as principal respon-sibility for demonstration program designand management of the demonstration proj-ect itself.Private sector proprietary rights and owner-ship should be preserved, provided that suchprotec tion doe s not inhibit timely de velop-ment of the technology.Cost sharing b etw een g overnment a nd in-dustry has generally proved successful in en-suring both careful selection of the most

‘1. R, Straugh n, Directorof Research and Development, South-ern Cal ifornla Edison Co., testimony before the House Corn mitteeon Science and Technology, Subcommittee on Energy Develop-ment and Applications, June 13, 1984.



Ch. 10—Federal Policy Options q 2 8 7

c o m p e t i t i v e projects and timely completionof the projects .

F e d e r a I G o v e r n m e n t c o m m i t m e n t s t o ademonstration program should be stable andpredictable–i.e., once made, s u c h c o m m i t -ments shouId be honored for a sufficient

period in order to convince developers thatgo vernment is a ‘‘reliable partner. ’. First-of-a-kind,tuII-seaIe demonstration facil-

itiesshouId include support by all partnersinvolved i n the de mo nstrat ion p rog ram fornot only plant engineering and constructionbut also for extended plant operations.2

Sma ller modular plant d esigns, where p ossible,are very attractive for demonstration projectssince they normally require a smaller capital com-mitment than large central station designs. In ad-dition, successful demonstration projects have in-CIuded active participation from a wide range ofprivate sector interests such as architect-engineer-ing firms, equipment manufacturers, as well asthe utilities themselves when appropriate.

Option A2: Shorten project lead-times anddirect R&D to near-term commercialpotential

Virtually a ll of the tec hnolog ies considered inthis assessment offer the potential of sizable de-ployment in electric power generation applica-tions beyond the turn of the century.At the current rate of d evelopment, however, few of these

tec hnolog ies a re likely to be extensively p ut inplace in the 1990s. Under conditions of acceler-ated load growth in the 1990s, an increase in ora refocusing of current Federal research, devel-opment, and demonstration (RD&D) activitiescould accelerate the deployment of early com-me rc ial units for most of the tec hnolog ies c on-sidered in this assessment. This includes atten-tion not only to the technologies themselves, butalso to manufacturing techniques and equipmentnecessary to produce the technologies.

While the technologies considered here en-c ompa ss a wide range of sizes, sc ales, and levelsof tec hnolog ica l ma turity, for purpo ses of d iscuss-ing appropriate policy actions, it is convenientto divide them into two basic groups:

q

q

A

The first c onsists of tec hno log ies envisione dprimarily for direct electric utility applica-tions, including integrated gasification/com-bined-cycle (IGCC) plants, large ( >100 MW)atmospheric fluidized-bed combustors (AFBC),large (> 100 MW) compressed air energystorage (CA ES) facilities, large ( >50 MW)geothermal plants, utility-owned fuel cell pow-erplants, and solar thermal central receivers.

The sec ond group c onsists of te c hnolog iessuitab le eithe r for utiIity or non utility ap pli-cations, includingfuel cells and small ( <100MW) AFBCs in nonutility cogeneration ap-

plications, small (< 100 MW) CAES, windturbines, small ( <50 MW) geothermal plants,batteries, and other solar power generatingtechnologies such as photovoltaics and para-bolic dish solar thermal.characteristic of the first groupof technol-

ogies is the Iikelihood of long preconstruction andconstruction lead-times—up to 10 years. Althoughthese technologies have the potential for muchshorter Iead-times---5 to 6 years—problems asso-ciated with any new, complex technology mayrequire construction of a number of plants be-fore that potential is met. If the longer lead-timesare needed, deployment in the 1990s will belimited because of short time remaining to de-velop the technologies to a level acceptable toa broad array of utilities.

The techno logies inthe sec ond group a re likelyto have shorter lead-times and are often smaller ingenerating capacity. For increased contributionin the 1990s, however, most of these technologieswill require stepped up development to reducecost and resolve cost and performance uncertain-ties that concern utility decision makers and non-utility investors.

It is important to note that this division betweenthese two groups of technologies is not rigid.Some tec hnolog ies the first g roup c ould a lso b en-efit from accelerated R&D and some in the sec-



288 Ž NewElectric Power Technologies: Problems and Prospects for the 1990s

ond group could benefit from policies aimed atshortening lead-times. This overlap should beconsidered in applying policy actions to eithergroup.

Generally, though, the steps necessary to accel-erate c ontribution to elect ricity supp ly vary ac -cording to the t ec hnology. With the first g roupof technologies, it is necessary, first, to resolvecost and performance uncertainties within thenext 5 to 6 years; and second, to take steps toachieve the short lead-time potential for earlycommercial units. Uncertainties in cost and per-formance stem largely from the lack of sufficientcommercial operating experience to satisfy non-utility investors and utility decision makers. Util-ity dec ision ma kers, in particular, in the wake oftheir experience with nuclear power, are nowpa rticularly wa ry of new tec hnology, espe c iallylarge-scale technology, and they impose rigorousperformance tests on technology investmenta lterna tives. This c onserva tism c onfers added im-portance to advanced commercial demonstrationprojects, as mentioned earlier in option Al.

On the other hand, no significant accelerationof existing RD&D schedules for the basic designsof the IGCC, large AFBC, and utility-scale geo-thermal plants is likely to be required for thesetec hnolog ies to be rea dy for the 1990s. Their tran -sition from de monstration to ea rly c ommerc ialunits, howeve r, will have to be ac c elerate d if thetechnologies are to be used in serving demandgrowth in the 1990s if it occurs. Variations in basicdesigns or more advanced designs, however, willrequire additional R&D.

Lead-times being experienced by early com-merc ial projec ts in both g roup s of tec hnologieshave been longer than anticipated, partially dueto the time required for regulatory review. As reg-ulatory agencies become more familiar with thetec hnologies, and their environme ntal benefitsbecome clearer, the review process should be-come smoother and more predictable, althoughthis is by no means guaranteed as evidenced by

the history of o ther ge nerating te chnologies.Ifthere is accelerated demand growth, however,it may be necessary to take those actions to en-sure lead-times consistent with those possible forthese technologies. Such actions include work-

ing closely with regulators, and careful manage-ment of construction and early operation. By em-phasizing smaller unit size–200 to 300 MW–these actions would be made easier.The successof the Cool Water project shows that such ac-tions are possible and effective.

For the technologies in the second group,where cost and performa nce are of pa rticularconcern, one approach to accelerating develop-ment would be to increase or concentrate Fed-era l R&D e fforts on tho se t ec hno log ies. This c ouldbe pa rticularly effect ive for pho tovoltaic s, solarthermal pa rab olic dishes, and ad vanc ed sma llgeothermal designs.

Option A3: Increase assistance to vendorsmarketing developing technologies inforeign countries

The new ge nerating tec hnologies that a pp ea rto show the most promise for substantial deploy-me nt in the 1990s are those tha t c urrent ly serveor have the o pp ortunity to serve ma rkets othe rtha n the dom estic ut ility grid . Such markets areespecially important as long as demand growthfor new electric generating capacity is low andwhile cost and performance of these technologiesare uncertain in grid-connected applications. Forsome of these technologies these markets are for-eign. Efforts on the part of the U.S. Governmentto assist in establishing access to markets for newgenerating technology equipment in foreigncountries could be very important to the near-term viability of some of these technologies. Suchefforts might include support for formation ofrenewable export trading companies, loan guar-antees, information dissemination, and help with

joint venture and licensing applications in foreigncountries.

The p ressures of c om petition from foreign ve n-dors, many of which are heawly supported bytheir governments, as well as the current lack ofU.S. dem and fo r som e of the se new tec hnolog iesin grid-connected power generation applications

raises the c onc ern over the c ontinued c ommit-ment of U.S. firms to developing these technol-ogies. This concern is heightened by pendingchanges in favorable tax treatment for renewableene rgy sources. For som e dom estic firms who a re





290 q Ne w Electric Power Technologies: Problems and Prospects for the 1990s

GOAL B: ENCOURAGE NONUTILITY ROLE IN COMMERCIALIZINGDEVELOPING TECHNOLOGIES

Option B1: Continue favorable tax policy

The Renew able Energy Tax Cred its (RTCs) have

been an important contributor to the Federal pol-icy of supporting the infant renewable energy in-dustry. 8 While the RTCs ha ve b ee n in effec t since1978, they have only been utilized to a signifi-cant degree since 1981 for electric pow er projec tsand are only applicable to nonutility facilities. Forwind projects,in particular, the credits seemedto have spurred development significantly for tworeasons:

1. With the tax credits, projects with designspecifications using current cost and per-formance technology present competitive

rates of return for prospective investors, par-ticula rly in California whe re Sta te t ax c red itsand high PURPA avoided cost rates are ad-ditional incentives. Even if the design speci-fications for a prospective project are notrealized, as has been the case for a largenumber of first generation wind projects, thetax benefits alone associated with theseprojects, many of which were initiated to testinnovative designs, have been sufficient toa ttrac t c onsiderab le investme nt interest. Thishas been p articularly true fo r investors withincome from other investments.

For example, using OTA’s cost and per-formance estimates (appendix A), the cumu-lative tax benefits–including accelerateddep recia tion allowa nces (ACRS), InvestmentTax Credits (ITCs), and RTCs–shows thatwind turbines as well as geothermal projectsare attractive investment opportunities un-der all reasonable cost and performancescena rios. PVs be come compe titive und erthe “ be st c ase” scena rio. Some of the d e-

‘l The Energy Tax Act ot’ 1978; the long-term ‘‘suppoflof an in-f a n t i n d u s t r y ” mot l~a t ion f o r t h e r e n e w a b l e e n e r g y c r e d i tw as q u i t edifferent from the~ister tax credit

for conservation which was moti-vated by the short-termobjectiie tor encouraging energy conser-vat ton.

2.

tails of this analysis are illustrated in figure10-1.9

While the first generation wind prolects inCalifornia generally did not perform well,they served as the “test bed” for small windma chines (less tha n 200 kw) tha t ha ve no tbeen the focus of the Federal R&D program.Indeed, the w ind industry is currently mo v-ing from these first generation small ma-chines to medium-sized machines (200 to1,000 kW) as the technology matures.

The effect of the RTCs on internal rates of re-turn for solar, geothermal, and wind projects isshown in figure 10-1, including the “worst case, ”“most likely, ” and “best case” cost and perform-ance scenarios defined in chapter 4 and appen-dix A. It should be noted that special investmentstructures such as safe harbor leases or other taxleveraged vehicles can improve the attractivenessof the investment considerably by limiting riskand/or offering substantial tax benefits (as dis-c ussed in cha p ter 8). Suc h me c hanisms have b e-come more the rule than the exception in the in-dustry in the last several years. As renewabletec hnology m atures, the q uality of investmentswill improve regardless of the tax implications,if avoided cost rate s rema in sufficient a s show nin the figure. Figure 10-2 show s the breakeve navo ided c ost (b uy-ba c k) rate s nec essary to yielda 15 percent real internal rate of return.

The role of the RTC in ac celerating c om me r-cial development seems to have changed fromits original design, at least for the technologiesconsidered in this assessment. The original Fed-eral po licy wa s to provide direc t resea rch sup-po rt to d evelop the tec hnology and the RTC toaccelerate commercial deployment, With de-c reased Fed eral R&D support, the RTC a pp ea rs

9,41s0 see P. Blair, testimony presented In hearings held by Sub-committee on Energy and Agricultural Taxation,Committee on Fi-nance, U.S. Senate, June 21, 1985,



Ch. 10—Federal Policy Options q 291

Figure 10-1 .—Tax Incentives for New Electric Generating Technologies:Cumulative Effect on Real Internal Rate of Returna

No tax incentives

— —G e o t h e r m a l P h o t o W i n d S o l a r F u e l C o m b u s t i o n Atmos t )he r l c

to b e supp orting resea rch and de velopm ent inthe field as well as commercial development. Atthe sam e time , there a re instances where the RTChas prompted insta llation of inferior tec hnologytha t has little possibility of com mercial success.

These instanc es have b rought ab out c riticismof the RTCs, particularly for wind, that has re-sulted in proposals for an alternative PTC thatwould award the credit based on energy gener-ated rather than the initial investment. Thesecritics have argued that support of innovative de-signs is not the intent of the credits. Indeed, aPTC w ould d isc oura ge investm ent p rima rilyoriented toward exploiting tax benefits. More-over, it would ensure that whatever investmentsare made would be done so for energy produc-

tion p urposes. A PTC, however, ma y b e difficultto monitor, particularly in non-grid-connected ap-plications. In addition, whilePTCs may ensurebetter performance, it may slow technology de-

velopment and commercialization since investorswould be less likely to test innovative designs.Another implication o f the PTC, c omp ared withthe RTC, is tha t it favors tec hno log ies in ba se loa dcycle applications (with higher capacity factors)such as geothermal and penalizes those in inter-mediate and peaking applications such as windor solar. The trade-offs between PTCs and RTCSare illustrated in table 10-2.

The e vide nc e supp orting the relative effec tive-ness of tax incentives for stimulating investmenti n the electric utility industry itself is not as com-pelling as the nonutility case. For example, thede c rease in the Ievelized per kilow at t-hour bus-bar cost for the renewable technologies consid-ered in OTA’s assessment, with a 15 percent taxcredit over and above the existing tax benefitscurrently afforded to utilities, is less than 10 per-c ent for all ca ses. The relative lowe r effec tivenessis mostly explained by utility accounting practices




x

Wind Photo-voltaics

Fluidb e db

Solar Geothermal Fuel Combus t ionthermal c e l l sb t u r b i n eb

which spread the be nefits of the ta x c red it ove rthe life o f the fac ility rather than o ffering a sub-stantial front-end incentive. For e lec tric utilities,

other actions than tax preferences (discussedlater) may b e m ore effec tive in stimulating d evel-opm ent of new tec hnology.

Since the early 1970s, the Federal policy forenco urag ing the developme nt of a renewa bleenergy industry centered on an active R&D pro-gram to develop the tec hnology (pa rticularly ac -tive during the decade of the 1970s) coupled withthe tax credits (since the early 1980s) to spur com-me rcia l ap plic a tions. This ana lysis shows that withdeclining direct support from Federal RD&D pro-grams, the pace of renewable technology devel-

opment would slow considerably without theRTC. Indee d, w ithout the c redits, only the mo stmature renewable technologies at the best re-

source locations would likely be deployed throughthe 1990s. Even with the tax credits, the appli-cation of the renewable technologies considered

here will be highly reg iona lly dep end ent in the1990s (see chapter 7). In regions where the wind,solar, and geothermal resources are of high qual-ity, though, the renewab le c ould be imp ortantcontributors to both new and replacement gen-erating capacity.

Many industry observers argue that a gradualphasing out of t he RTC rathe r than their currentlyscheduled termination at the end of 1985 wouldgive the renewable power industry a betterchance to develop technology to the point whereit might compete effectively in the 1990s. in par-

ticular, a 3-year phase-out of the credit for windand geothermal could benefit those technologiesconsiderably and increase deployment in the



Ch. 10—Federal Policy Options

Table 10-2.—Alternative Tax Incentives: Cumulative Effect on Real Internal Rate of Return

q 2 9 3

Real internal rate of return (percent)Wind

turbines

4.1 “/019.19.9

14.916.817.919,0

11.615.514.519.1

5.95.1

11 .70/028.4

18.924.626.827.828.8

19.724.722.728.4

14.713.2

16.6 ”/035.5

25.231.934.235.236.4

25.631.628.935.5

20.518.6

Solarthermal

0.0 ’70

0.00.0

0.00.10.10.2

0.00.00.00.0

0.00.0

O .OO / O9.5

1.86.17.58.29.1

2.16.24.0 9.5

0.0 0.0

1 .7 ”/014“.4

6.610.211.812.713.8

6.711.28.7

14.4

3.73.3

16.90/o24.324.3

29.831.732.633.7

24.629.627.332.9

20.218.6

20.40/o28.6

28.634.937.037.938.8

29.134.432.237.9

24.122.3

24.833.9

33.941.043.244.344.7

34.740.238.143.9

28.926.7




1990s. For solar thermal and photovoltaics, how-ever, a 5-year or more extension or gradualphase-out would more likely be required.

Option B2: Improve nonuti[ity access totransmission capacity

Som e non utility po we r prod uc ers argue tha t ifproposed nonutility generating projects were in-cluded more explicitly in utility resource planningconsiderations, such projects might be betteraligned with proposed transmission expansionand reconfiguration plans. Coordination of non-utility g eneration with utility-owned generationmust be balanced against utility concerns aboutcontrol of generating sources for dispatching andmaintenance of system reliability.

Nonutility generating sources might also bemore prevalent if power from projects located inone utility service territory could be sent toanother utility service territory where, for exam -ple, avo ide d c ost p ayments were higher. Such“wheeling” of power, however, requires trans-mission c ap ac ity to be co mmitted to the projec tin the former service territory. At low penetra-tion levels of nonutility generating sources wheel-ing is not likely to be a serious problem. SomeState utility commissions have already madewheeling mandatory. At higher levels of penetra-tion, however, utilities might be forced to recon-figure or upg rade existing t ransmission c ap abil-ities to accommodate wheeling and the questionof allocation of costs for upgrades becomes anissue.

If the objective is to increase non utility powerprojects employing new electric generating tech-nologies, revisions to PURPA to modify thewheeling provisions originally enacted might bean effective way to encourage development ofsuch projects. Such modifications could givethese producers access to utility markets beyondthe service territory in whic h the projec t is sitedwithout negotiating complicated individualizedwhe eling ag reeme nts with the loc al utility. Suc hmod ific ations might a lso extend to ob liga tions onthe part of the utility in which a project is sitedto negotiate with prospective non utility produc-ers on the issue of transmission access.

Modifications to PURPA to broaden the wheel-ing provisions, however, would have to be care-fully constructed since the implications of suchmodifications vary greatly from region to regionas we ll as from utility to utility w ithin regions. Util-ity concerns about efficiency and control over thetransmission and distribution system must becarefully addressed in any proposed modifi-ca t ions.

Finally, streamlining of Federal licensing andpermitting procedures where such proceduresapply to transmission projects—i,e., on Federallands–could reduce the time it takes for PURPA-qualifying facilities to gain access to transmissioncapacity.

Option B3: Develop clearly defined and/orpreferential avoided energy costcalculations under PURPA

In chapter 8 the avoided energy (and capac-ity) cost tha t utilities pay to non utility producersfor generated power was identified as one of thekey fac tors affec ting the profitability of nonutil-ity power projects. Investors in nonutility powerprojects seek secure, long-term energy credit andcapacity payment agreements with utilities to en-sure a sta ble revenue stream fo r the project . InSta tes encourag ing non utility p rojec ts, e.g., Cali-fornia, standard agreements have evolved that areIevelized pricing contracts or fixed price sched-uIes negotiated for the duration of the proposedprojects. Such standard contracts have greatly in-creased nonutility generating activity in theseStates and co uld provide a mod el for other States.

In other States, public utility commissions havema nda ted m inimum avoided c ost rate s—e. g.,New York and lowa have minimum rate of 6 and6.5 cents/kWh, respectively, for small power pro-ducers which are generally above the prevailingavoided cost of the utilities. Attempts to removesuch rates through the courts have to date beenunsuccessful, although some appeals are stillpending. If the courts interpret the primary pur-pose o f PURPA’ s avoided cost p rovisions as en-co urag ing sma ll powe r prod uction, then ad op-tion of such mandatory rates could serve toaccelerate small power production substantially



Ch. 10—Federa/ Policy Options q 295

in Sta tes where these ra tes exist. If, on the otherhand, the courts rule that implementation ofPURPA’ s avoided cost p rovisions’ must c onsiderimmediate ra te savings for a utility’s custom ers,the future of such rates is less clear since publicutility commissions will be obligated to strike abalance between customer savings and incentivesfor small power producers. The outcome is ofc onsiderable importanc e to the rate of c omme r-cial deployment of new generating technologies.Legislative action to co-opt the courts’ decisionsin this area could serve to red uce unce rta inty,and in the process, accelerate deployment of newgenerating technologies that would qualify formandatory rates where they exist.

Option B4: Standardize interconnectionrequirements

As the penetration of nonutility owned andoperated dispersed generating sources (DSGs) in-creases in U.S. electric power systems, the im-plications for system operation, performance, andreliability are receiving increased attention by theindustry. For the most part, however, the tech-nical aspects of interconnection and integrationwith the grid are fairly well understood and mostutilities feel that the te chnic al prob lems can be

resolved with little difficulty. State-of-the-arpower conditioners are expected to alleviate util-ity concerns about the quality of interconnectionsubsystems.

Prior to 1983, most interconnection configura-tions were custom-fitted and no standardized

guidelines existed. Since 1983, however, thenumb er of app lic a tions from DSGS has increa sedand, as a result, more utilities are developing suchguide lines. These ind ividua l utility gu ide lines va rywidely, but a number of national “ mod el” guide-lines are b eing d eveloped by standa rd-settingcommittees (discussed in chapter 6), althoughnone has yet released final versions. Indeed, thesegroups are expected to continue to revise draftstandards. Even if a consensus standard doesemerge, however, widespread utility endorse-ment is still uncertain. As a result, DSG custom-ers are likely to face different and sometimes con-flicting interconnection equipment standards wellinto the 1990s. This lack of standardization mayhamp er bo th the use o f DSGs a s we ll a s the m an-ufacture of standardized interconnection equip-ment. Development of a set of national standardsfor interconne c tion that could b e flexibly interpreted for individual utility circumstances couldaccelerate deployment of non utility power proj-ects in many regions.

GOAL C: ENCOURAGE INCREASED UTILITY INVOLVEMENTIN DEVELOPING TECHNOLOGIES

Electric utilities on average currently spend lessthan 1 percent of gross revenues on R&D, con-siderab ly less tha n m ost othe r capital-intensiveindustries. Trad itiona lly, the response t o t his c on-cern is that equipment manufacturers and ven-dors are carrying the principal burden of R&D forthe p ow er industry. But, with the d ec line in newequipment orders in recent years, manufacturersare less likely to commit R&D to new productsfor which strong markets are not assured. As a

result, if R&D activity in new generating technol-ogies is to continue, at least a portion of the bur-den may fall on the utilities themselves. Withenvironmental and other pressures on utilities toconsider new technologies, how public utility

commissions treat cost of RD&D and of earlycommercial applications is a pivotal issue. Thefollowing are alternative strategies aimed at im-proving this regulatory environment.

Option Cl: Increase utility and public utilitycommission support of RD&D activities

increased RD&D activity in new generatingtec hnolog ies will require utilities and utility com

missions to agree on appropriate mechanisms forsupporting such activities. Direct support fromthe rate base for research activities, such as theallowance for contributions to the Electric PowerResearch Institute while desirable and important,

38-743 0 - 85 - 11




is not now at a level that would cause significantdeployment of these technologies by the 1990s.Allowance of or even encouragement of a higherpercentage of annual revenues to support RD&Dac tivities c ould b e a n important step in a c c el-erating commercial applications of new tech-nologies.

Even larger RD&D commitments, however, thatinvolve large capital investments for major dem-onstration facilities may only be justified by asharing of the risk between ratepayers, stockhold-ers and, if other utilities would benefit substan-tially, taxpayers. One mechanism for supportingsuch projects is to finance a portion of proposedproject with an equity contribution from the util-ity and the rest through a "ratepayer loan”granted b y the p ub lic utility comm ission. Thepublic utility commission might argue that a can-d idate demonstrat ion projec t is too risky for the

ratepayer to be subsidizing, particularly if otherutilities could benefit substantially from the out-come, but are not contributing to the demonstra-tion, i.e., sharing in the risk. In such cases, therec ould b e a Fed eral role. For examp le, the rate -pa yer contribution to the d emo nstration c ouldbe underwritten by a Federal loan guarantee, thustransferring at least a portion of the investmentrisk from the ratepaye r to the taxpaye r.

Finally, since high interest rates and high capi-tal costs have discouraged utilities from makinginvestments in new generating capacity, a widevariety of regulatory cha nges have b een sug-gested that would make it easier to resume con-struction programs. These include:

1.

2.

3.

rate b ase trea tme nt o f utility assets that ta keinflation into account—sometimes called“ trend ing” the rate b ase; l”allowance of some or all construction workin progress (CWIP) to be included in the ratebase; andadoption of real rates of return on equityco mme nsurate with the a c tual investmentrisk.

l~Trended rate base proposals are discussed in U.S. Congress,Office of Technology Assessment, Nuclear Power in an Age of Un- certainty (Washington, DC: U.S. Government Printing Office, Feb-ruary 1984), OTA-E-2 16.

These o ptions are a ll aimed a t eve ning out rateincreases (prevention of so called “rate shock”)and providing more financial stability for utilities.They would, howeve r, reduc e the a ttrac tivenessof smaller, modular generating technologies rela-tive to larger units since the options transfer someof the investment risk from the stockholder to the

ratepayer. While all capital projects—large orsmall—wou Id benefit by this risk transfer in termsof lower capital costs, the larger the project thegreater the net savings to the utility. Whether thisis sufficient to outweigh the benefits of smallerunits in a pe riod of unce rtain dem and growthwould depend on the particular utility and itslonger term outlook.

Option C2: Promote involvement of utilitysubsidiaries in new technologydevelopment

Som e e lect ric ut ilities are using (and ma ny a reconsidering) the use of regulated or unregulatedaffiliated interests (corporate subsidiaries or otherholding c omp any structures) to initiate new tec h-nology projects where they have identified aproject as an attractive investment opportunitybut riskier than more traditional utility invest-ments, i.e., the utility’s allowed rate of return isnot commensurate with the project’s perceivedfinancial risk. In practice, this usually amountsto a situation where the public utility commis-sion a grees to p ermit a projec t to p roc eed butdoes not give assurances that the entire final

project cost will be permitted to enter the ratebase.

Using an unregulated affiliated interest to carryout new technology projects allows utilities to fi-nance such projects with sources from the capi-ta l markets since higher ra tes of return ca n b eoffered to attract capital. It is also one exampleof how utilities are diversifying into other linesof business. As discussed in chapter 3, electricutility diversification activities are already wide-spread and growing. Most of these activities (74percent according to a recent Edison Electric in-stitute survey) involve fuel explorat ion and de-velopment, real estate, energy conservation serv-ices, fuel transportation, district heating andcogeneration, and appliance sales. A small per-



Ch. 10—Federa/ Policy Options q 297

centage (6 percent) do, however, involve alter-native technology projects. Generally diversifica-tion

1.

2.

3.

4.

has led to :A higher return for investors, increase inpric e-ea rnings ra tio a nd, as a result, an im-proved standing in the financial communityand a lowering in the cost of capital. Diver-sified utilities have consistently outperformednondiversified utilities in the stock market.More efficient use of company assets includ-ing labor, customer base, computational fa-ciIities, and services.Diversification, protection, and stable pric-ing of fuel supplies through diversificationinto fuel acquisition activities and alternativetechnology projects.An ability to take advantage of favorable taxbenefits not afforded to-regulated publicutiIities.

The problems of potential cross-subsidizationof unregulated projects from regulated interestshas to b e m onitored c losely by pub lic utility c om -missions as they allow utilities to become in-volved in diversification activities.

Option C3: Resolve siting and permittingquestions for developing technologies

To d ate , the rate of d ep loyment of some newgenerating technologies in both utility and non-utility applications is being lowered because lead-times being experienced by early commercialprojects have been longer than anticipated, par-tially due to the t ime req uired for reg ulatory re-view. As reguIatory agencies become more famil-iar with the tec hnologies and their environme ntalimpacts become clearer, the time to completesuch reviews could decrease, although as notedearlier this is by no means guaranteed. Action toeducate reguIators and all others who would ul-timately be affected by eventual deployment ofthe technology i n the course of demonstrationsmight reduce the lead-times of early commercialunits. For exam ple, c lose c oo rd ination w ith Sta te

and Federal regulatory agencies as well as pub-lic utility commissions during demonstration proj-ects shouId be a major feature of these projects.Finally, as noted for non utility projects discussedearlier, streamlining of Federal licensing and per-

mitting p roc ed ures where such p roc ed ures ap -ply to transmission projects could reduce lead-times considerably.

Option C4: Other legislative initiatives:PIFUA, PURPA, and deregulation

In addition to maintaining a continued pres-ence in research, development, and demonstra-tion as well as implementing environmentalpolicy affecting power generation, e.g., admin-istration of the Clean Air Act, several possible Fed-eral policy decisions affecting electric utilitiesco uld influence the rate of c omme rcial develop-ment of new generating technologies over thenext 10 to 15 yea rs. These includ e removal of thePowerplant and Industrial Fuel Use Act (PIFUA)restrict ions on the useof natural g as, extensionof c om plete PURPA Sec tion 210 bene fits to elec -tric utilities, and increased steps toward deregu-lation of power generation and bulk power trans-fers. All of these a c tions c ould inc rease the rateof deployment of developing generating technol-ogies, but their other effects have to be carefullyreviewed before a nd during implementation.

If increased availability of natural gas shouldoccur, a repeal of PIFUA or, at a minimum, amore liberal policy on granting exemptions inpower generation applications could, in additionto providing more short-term fuel flexibility fomany utilities, be a step toward accelerated de-ployment of “ clean c oal” tec hnologies such a sthe IGCC since they c an use na tural gas as aninterim fuel. In addition, some technologies suchas CAES and some solar thermal electric units usenatural gas as a supplementary fuel and may ormay not fall within the applicable size limits estab-lished by PIFUA automatically exempting suchinstallations from the Act. ’1 Where exemptionsare required, their acquisition introduces delaysor even the possibility that approval might bedenied.

Permitting utilities to participate more fully inthe PURPA Section 210 benefits of receiving

avoided cost in small power production wouldmost likely result in increased deployment of

I I Ch a nges i n PI F(JA wo u Id also affect non uti lity producers, asdiscussed in ch. 9.




sma ll modular power generating tec hnologies,pa rticularly cog eneration.12For example, utilitiesare currently Iimited to less than sO percent par-ticipation in PURPA qualifying cogeneration fa-cilities. In addition, ratepayers would likely seemore of the cost savings resuking from cogener-ation if utilities were allowed full PURPA bene-fits. Currently, ratepayers see only the difference,if any, between the avoided cost and the rate ne-gotiated between the cogenerator and the util-ity. The ow ner of t he qualifying fac ility reta ins therest of the excess over the cost of generating thepo wer. Similar b enefits would ac c rue to the rate -pa yer by utility pa rtic ipa tion in PURPA fo r othertypes of generating technologies to the extent thatcosts of power production fall below avoidedc osts.

In relaxing this limitation, potential problemsrequiring a ttention include ensuring tha t utilitiesdo not show undue preference for utility-initiatedprojec ts in suc h a reas as acc ess to transmissionor capacity payments. Moreover, project ac-counting would probably need to be more seg-rega ted from utility op erat ions tha n non-PURPAqualifying projec ts in order to e nsure tha t c ross-subsidization d oes not oc cur that w ould m akeutility-initiated projects appe ar m ore p rofitab leat the e xpense o f the rate pa yer. These c onc ernscan be allayed through carefully drafted legisla-tion or regulatiorls, or through careful State re-view of utility ownership schemes.

It should b e no ted , though, that granting of fullPURPA benefits to utilities would be viewed withdisfavor by most nonutility owners. In particu-lar, allowance of such benefits likely would causeavoided co sts to b e d etermined by the c ogener-ation unit or alternative generation tec hnologyitself rather than the fuel and/or capital costs of

I ZFor a more complete discussion, see U.S. Congress, Office ofTechnology 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 bya utility as is currently the case. Unless prospec-tive nonutility owners could produce power stillcheaper than these newly defined avoided costs,they obviously would not enter into any projects.This would c lea rly red uce the numb er of c og en-eration and alternative technology power projectsstarted by nonutility investors. This drop-off, how-ever, might b e mo re than c omp ensated by ex-panded utility involvement. It is also possible thatpotential cogeneration and alternative technol-ogy sites may go unfulfilled if utilities were al-lowed full PURPA benefits, since many of thesesite owners—industrial firms and large build-i rigs-may not want utility control over facilitieson the ir site. Here, too, c areful esta blishme nt o freguIations or contracts couId protect all partiesof interest.

Finally, as perhaps a logical next step to PURPA,

a number of proposals for deregulation of theelectric power business have been proposed inrec ent yea rs, rang ing from de regulation o f bulkpower transfers among utilities, to deregulationof ge neration, to com plete d eregulation of theindustry. While OTA has not examined the im-plicat ions of alternative deregulation p rop osalson the rate of commercial development of newgenerating technologies, such proposals wouldalmost c ertainly have a n impa c t. The experiencesof PURPA and the FERC Bulk Power Market Ex-periments will be important barometers for as-sessing the future prospects and desirability ofde regulat ing U.S. elec tric po wer g eneration.Itis important to note that allowance of full PURPAbenefits for utilities would be a significant steptoward deregulation of electric power generation,at least for smaller generation units.

1 jThis experiment deregulates wholesale bulk power transactionsamong four utilities in the Southwest; see “Opinion and Order Find-ing Experimental Rate To Be Just and Reasonable and AcceptingRate for Filing, ” Federal Energy Regulatory Commission, OpinionNo. 203, December 1983.



Ch. 10—Federal Policy Options q 299

GOAL D: RESOLVE CONCERNS REGARDING IMPACTOF DECENTRALIZED GENERATING SOURCES ON

POWER SYSTEM OPERATIONIn recent years, utilities that interconnect with

non utility power producers operating DSGs areconcerned about the potential impact of in-creased penetration of DSGs on overallp o w e rquality available in the utility grid as well asproper metering, effec t o n system dispa tc hingand control, short-term transmission and distribu-tion operations, and long-term capacity planning.

As utilities gain experience with DSGs on theirown systems, these concerns are being resolved.However, many utilities are only beginning togain this experience; the following options areaimed at addressing such concerns.

Option Dl: Increase research on impacts atvarying levels of penetration

While most of the problems associated with in-corporating DSGs into the utility grid appear tohave technical solutions, the cost and complex-ity of these solutions may vary considerablyacross utility systems. In particular, one concernis the potential impact on power quality of highlevels of p ene tration of DSGs on ind ividualdis-tribution feeders. Other issues include protectiveequipment performance, appropriate safety pro-cedures, system control at the distribution level,and impact on system generation dispatching pro-cedures. Most research to date indicates that atlow levels of DSG penetration–up to 5 percentof tota l installed c ap ac ity—there a re no ill effectson system operations as measured by indicatorssuch as the area control error (see chapter 6). Be-yond a 5 percent penetration, however, there isless agreement among researchers. Research onthe cond itions under w hich DSGs would signifi-cantly affect system operation over a wide rangeof utility circumstances would improve utilityengineers’ ab ility to a ssemb le ap propriat e a ndcost-effective interconnection configurations and

control procedures for mitigating potential im-

pa c ts. Such resea rch c ould he lp resolve c onc ernsand serve as a basis for implementing appropri-ate technology and procedures to accommodateincreased penetration of DSGs.

Option D2: Improve procedures forincorporating nonutility generation andload management in economic dispatchstrategies and system planning

Many of the prob lems assoc iated with incor-porating DSGs into the utility grid stem frommodifications to the grid necessary to accommo-date electric generation at the distribution level.Manage ment of “ two-way” p ower flows at thedistribution level has added a new level of com-plexity. Som e utilities have d eve lope d strategiesfor inco rpo rat ing DSGs into ec onom ic d ispa tc hstrategies but control mechanisms for coordinat-ing a large number of DSGs are generally notavailable. As the number of DSGs on a utility sys-tem increases, the complexity of this coordina-tion becomes more difficult and the need to au-tomate such procedures becomes more important.

Similarly, some recent research sponsored bythe Electric Power Research lnstitute14indicatesthat conventional utility planning models mayoverstate the reliability benefits of load control.Developing load management systems. 15 attemptto better integrate load management into hourlyscheduling of resources in energy control centers.As a result, these new systems also provide bet-ter control over load management resources and,hence, more reliability benefits.

I JElectric Power Research Institute (EPRI ), Eft’ecf Oi LOJd M a m g e -

r n e n t on Re/labi/ity (Palo Alto, CA: EPRI,july 1984), EPRI EA-3575.I $uch as B. F. Hastings, “The DetroitEdison Second Generation

Load Management System, ”Proceecilngs of the Institute ot [lec-trlcal and Electronm Engineers (IEEE) Summer Po\\er Aleeting, Paper

No. 84-SM-559-1 , jU!Y 15-20, 1 9 8 4 .





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:TableDe fin

Photovoltaics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Solar Thermal Electric . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Wind Turbines . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Geothermal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Atmospheric Fluidized-Bed Combustion. . . . . . . . . . . . . . . . . . . . . . .Integ rated Ga sificat ion/Comb ined-Cyc le . . . . . . . . . . . . . . . . . . . . . . .Fuel Cells . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Compressed Air Energy Storage . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Batteries. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

A-10: Summary Tables . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .tions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Page 304

306308309311312313315316317319




Table A-l.—Cost and Performance of Central Station Photovoltaics

May 1985 technology status Flat-plate ConcentratorCommercial

9.5MWegeneral characteristics

199520-4,730 MWe2

10 MWe4

2years 5

60-320 acres8

very Iittlegperformance parameters

90-100%10









308 NewElectric Power Technologies: Problems and Prospects for the 1990s

Table A.3.—Cost and Performance of Medium-SizedWind Turbines

May 1985 technology status



















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

199510 MWe

5-200 MWe

2 years67 acres

very little

95Y0intermittent

20-35%

30 years20-25%

$2,000 -$3,000/kWe

15-23mills/kWh

None

Commercial Commercial unit Commercial unit Commerci650 + MWe none none 223 MWe

1995 1995 1995 199520 MWe 50 MWe 50 MWe 7 MWe

1,500- 12-1,830 MWe2,900 MWe

1-2 years 3 years300-2,000 8-20 acres

acresnone 3 milllon gal/day

95-98%intermittent

20-35%

20-30 years —

$900-$1 ,200/

kWe6-14

mills/kWhNone

$1,300-$1 ,600/kWe

10-15mills/kWh

20-70mills/kWh

3 years8-20 acres

41 milliongal/day

$1,500-$1,800/kWe

10-15mills/kWh

20-70mills/kWh

1 year1 acre

85-90%base700/0

30 years7 0-90/0

$1,500-$2,000/

kWe10-15

mills/kWh20-70

mills/ kWh



318 q 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

TechnologiesFuel 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 199511 MWe 0.4 MWe

40-1,200 MWe

I n s t a l l e d U . S . c a p a c i t y none 100 MWeReference-system: generalReference year ., ... 1990 1990Reference-plant size ., 150 MWe 500 MWe

none

1990220 MWe

O MWe

5-8 years15 acres

360,000gals/day

90-98%

none 0.5 MWe 0.1 MWe

199050 MWe

1995 199520 MWe, 20 MWe,100 MWh 100 MWh

Reference year U.S. installedc a p a c i t y ( e s t . ) 510-735

MWeL e a d - t i m e 5-10 yearsLand required ., ., ~ ., 90-218

acresWater required ., 1.5 million

gal/day

200 MWe 0-100 MWe 0-600 0 -2 , 800MWe MWe

2 years 2 years0.2-0.3 0.2-0,3acres

11,000 200-300gals/day gals/day

5-10 years300-600 acres

3-5 years0,5 acres

2 years0.009-0.014

acrevery small

4,5-6,5 years3 acresacres

100,000gals/day

3-5 milliongal/day

very small

85%

base70% 30 years35-40%

8 0 - 9 0 %

variable40-75%30 years40-44%

80-90%

variable40-75%20 years36-40%

9 0 - 9 8 % 9 0 % 90%

peaking/inter, peaking/inter. peaking peaking10-20% 1O-2O% 10% 10%30 years 30 years 30 years 30 years

51%3 51%3 7 0 - 7 5 %3 6 0 - 7 0 %Reference-system: costsC a p i t a l c o s t 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 3-11mills/kWh mills/kWh mills/kWh mills/kWh

42-63 42-63 27-50 29-58mil ls /kWh mil ls /kWh mil ls /kWh mil ls /kWh

$700-$3,000/kWe

$950”$3,000/kWe

O & M c o s t s 7.66 6-12mills/kWh mills/kWh

Fuel costs ., ., ., 17 15-17mills/kWh mills/kWh

4,2-11.5mills/kWh

27-30mills/kWh

4.2-11.5mills/kWh

30-33mills/kWh



App. A—Cost and Performance Tables q 319

Definitions

These ta bles provide b asic information on ea chtec hnology. The d ata c onstitutes the b asis for imp ortantportions of the analysis. The cost and performancecharacteristics listed in the tables are not definitivepredictions. Rather they are reasonable approxima-tions of the status of the technology during the1990s,and are used to typify the technology during the lastdecade of the century. Great uncertainty surroundsthese numbers and they should be treated for whatthey are: educated guesses.

Where important subcategories of any particulartechnology exist, and where their characteristics dif-fer significantly from one subcategory to the next, thesubcategories are listed separately. For example, pho-tovoltaics are divided between flat-plate and concen-trator modules.

May 1985 Technology Status

This section provides information on the current sta-tus of the technology.

Level of Technology Development.–The technol-ogy already may be commercially deployed, or it maybe operating as a demonstration unit or pilot plant;or plans may be underway to deploy such units.

Installed Capacity .–This section of the table de-scribes the status of the technology as of May 1, 1985.Only capacity installed and operating at that time isincluded in the capacity totals.

Reference System: General Characteristics

Reference Year.— For each technology a referenceyear is established. For technologies with lead-times

of 5 years or less, the reference year is 1995. For thosewith lead-times longer than 5 years, the reference yearis 1990. All cost and performance figures refer to thetechnology as it might appear in the reference year.The c ost a nd pe rformanc e figures for that ye ar are ex-pected to typify the cost and performance of most ofthe units which are deployed and operating by theend of the century.

Plant Size.–The technologies examined in this re-port in many instances will be deployed in a varietyof sizes. The size listed in the tables is considered typi-cal of plants installed in the 1990s. Considerable var-iation may occur from plant to plant, but most capac-ity installed during the 1990s is expected to be similar

in cost and performance to the reference plant.1995 Deployment Level Scenario.–This is the to-

tal capacity expected to be operating by January 1 ofthe reference year. The estimates are important be-

1 The cletl n Itlon is th.lt prok Icied I n the Elect rlc Pow er Research I nstlt uteifsTe c h n i c a l Assessment Guide



3 2 0 • New Electric Power Technologies: Problems and Prospects for the 1990s

Capa city factorsfor intermediate systems are assumedto fall between the two systems, at around 20 percent.Where technologies are expected to operate undermore than one duty cycle, both are stated. Actual ca-pacity factors may be quite different form the nomi-nal values shown.

Lifetime.—This is the time over which the entireplant would be operated commercially.

Efficiency .-This is the annual average plant effi-ciency, defined as the ratio of total net energy pro-duced to total available energy contained in the fuelor resource.

Reference System: CostsAll 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 BulletinCost Index for electric utility construction:

D a t e Index1/1 /78 1597/’1 i78 1661/1 ,’79 1757/1 /’79 1831/1 1’80 1937/I /’80 I 991/1 )81 210

2 1 922 52 3 023 32 3 824 2

p l a n t c o s t o r

TPC) generally represent approximatebudgetary over-night constructed costs for the indicated location in-c luding an average allowa nce o f 5 to 10 percent forengineering and home office overhead and fee anda 20 to 25 percent allowance for overall contingence.

Thus:T P C = B a r e Erected Cost (BEC) X (1 .05 to 1,1) X (1 2 to 1.25)

C a p i t a l c o s t s d o n o t i n c l u d e i n t e r e s t a n d e s c a l a t i o n

d u r i n g c o n s t r u c t i o n , l a n d c o s t s , a n d o t h e rc o s t s s u c has royalties, preproduction, startup, initial catalyst/ chemical charges, and working capital.

O&M Co sts.–These a re “ first yea r” c osts, the av er-age 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 orfuel-cell stacks during the installation’s lifetime is in-cluded in the O&M costs.

Fuel Costs.— Electricity and fuel costs are first yearannual average costs based on a typical plant in thereference year. Electricity for CAES and batteries is as-sumed to be generated by a base load plant, at pricesexpected to range from 20 to 35 mills/kWh.z Fuelprices are based on 1983 fuel prices, with assumedreal escalation rate of 1 percent per annum for coal,and 2 percent per annum for oil and gas. The 1983fuel prices used in making the reference year estimatesare:

Fuel) (in dollars per million British thermal units (Btu))

Oi l

~Th IS IS based on an estl mate provided by WI Illam BI rk, Electrlc Power Re-search Institute, personal correspondence with C)TA staff, tMay 7, 1985 MrBirk indicated thatEPRI uses a figure ot 25 mills/kWh; for a range, he5ug-gested 20 to 30 mills/kwhThis analysis uses a range with a higher upperlimit, 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 plantsof 50 MWe capacity or larger, 1983



Index



Index

ACE. See Area control error CAES. See Compressed-air energy storage fac ilitiesAdjusted reserves, 187, 203, 204, 206 Ca lifornia-Southern Neva da Pow er Area (CSNPA), 183,Advanced lead-acid batteries, 122, 123, 125, 127, 281, 189, 210, 211

282 Advanced meters, 151-152AFBC. See Atmospheric fluidized-bed combustionAFUDC. See Allowancefor Funds Used During

ConstructionAlaska Systems Coordinating Council (ASCC), 211-212Allis Chalmers Corp., 273Allowance for Funds Used During Construction

(AFUDC), 48, 68Alternative technologies. See New technologiesAmorphous-silicon flat-plate modules, 79-80, 257ANMPA. See Arizona-New MexicoPower AreaAquifer reservoirs, 121, 122Area control error (ACE), 164, 177-179Arizona-New Mexico Power Area (ANMPA), 184, 189ASCC. See Alaska Systems Coordinating CouncilAtmospheric fluidized-bed combustion (AFBC)

commercial prospects, 22-23, 112-113, 115, 278

cost and performance, 115-117, 311current activities, 140environmental issues, 243, 245industry development, 277-278nonutility profitability analysis, 235, 236, 239overview, 112-113regional opportunities, 200technology, 113-115utility cost analysis, 224

Automatic generation control, 176-179Avoided costs, 23, 30, 35, 42, 69, 190-192, 240, 241,

294, 297-298

Balance of system (60 S), 83Battery Energy Storage Test (BEST) Facility, 280, 281Battery storage

commercial prospects, 24, 118, 122-123, 281-282cost and performance projections, 123-129, 316industry development, 280-281load management use, 157overview, 122-123regional opportunities, 200, 213technology, 20, 123, 127utility cost analysis, 224

Bechtel Power Corp., 273Beckjord Unit 1, 140BEST Facility. See Battery Energy Storage Test FacilityBGC. See British Gas Corp.Binary cycle systems, 23, 99-102, 267BOS. See Balance of systemBreakeven analysis, 234-238British Gas Corp. (BGC), 273, 275Brunner Island Station, 140Bubbling beds, 114-115Bulk power transactions, 30, 65-66, 203-208, 210-213,

215Bureau of Land Management, 268

Capacity margins, 187Capacity planning, 68-69Cash return, 234Central controllers, 154-155Central Hudson Electric & Gas, 172Central receivers, 24, 84, 88-89, 259, 261CG&E. See Cincinnati Gas & Electric Co.Cincinnati Gas & Electric Co.(CG&E), 140Circulating beds, 115Cogeneration, 23, 30, 42, 70, 112, 113, 115, 116, 165,

198-199, 204, 210, 212, 215, 270, 278Colorado Ute Electric Association, Inc., 140Combustion technologies. See Atmospheric fluidized-

bed combustion; Conventional technologies;Integrated gasification/combined-cycle powerplant

Commercial deploymentaccelerated development, 2-3advanced meters, 152

atmospheric fluidized-bed combustion, 112-113, 115,277-278

batteries, 122-123, 280-282compressed air energy storage, 121, 278-280demonstration needs, 34-35fuel cells, 102-103, 269-272geothermal prospects, 98, 100, 266-269industry factors and, 32-33integrated gasification/corn bined-cycle powerplants,

108, 110, 272-277new technologies, 3-4, 22-25photovoltaic systems, 78-80, 253-258solar thermal-electric powerplants, 86, 87, 89-91,

259-262tax incentives and, 36wind turbines, 92-93, 262-266

Commercial sector, 145, 150Communications technologies, 155-156Comparative cost analysis, 222-225, 246-248Comparative profitability analysis, 234-241, 248-250Compressed air energy storage (CAES)

commercial prospects, 24, 118, 121, 279-280cost and performance projections, 121-122, 315environmental issues, 121-122industry development, 278-279overview, 118-121regional opportunities, 200technology, 20, 118-121utility cost analysis, 224

Concentration photovoltaic systems, 78-79, 83, 257ConEd. See Consolidated Edison Co.Conservation, 64, 157, 188, 215Consolidated Edison Co. (ConEd), 173Construction costs, 44, 46Construction Work in Progress (CWIP), 48, 192Conventional technologies, 19, 25, 64, 141, 235, 236.

See a/so Load management; Plant betterment

323




Cool Water demonstration project, 22, 110-111, 273,275

Cooperative agreements, 3, 270Cost analysis, 222-225, 246-248Cost and performance

alternative technologies, 21atmospheric fluidized-bed combustion, 115-117, 311batteries, 123-129, 282, 316

compressed air energy storage, 121-122, 280, 315conventional generating technologies, 141data needs, 258, 265, 275-276fuel cells, 103-108, 272, 313geothermal systems, 98, 100-103, 268, 309improvement needs, 257, 268, 272, 275, 280, 282 integrated gasification/combined-cycle powerplants,

110-112, 275-276, 312photovoltaics, 79-84, 257, 258, 304plant betterment projects, 137, 139policy options, 286-289solar thermal-electric systems, 86-91, 306-307wind turbines, 23, 93-96, 265, 308

Cross-technology comparisonissues, 243, 245

nonutility producers, 234-241utilities, 224Crystalline silicon cells, 79, 257CSNPA. See California-Southern Nevada Power AreaCurrent harmonics, 163-164, 167CWIP. See Construction Work in Progress

DCP, See Design change packageDebt service coverage ratio, 62, 234Decision-logic technologies, 156-157Demand growth, 8, 44, 46, 59, 183, 185, 187, 203-207,

211, 212, 214, 227Demand management, 143Demand-subscription service meter, 152Department of Energy, 29, 171, 259, 267, 270, 273,

274, 277, 280Deregulation, 35, 298Design change package (DCP), 136Detroit Edison Co., 274Developing technologies. See New technologiesDirect control systems, 152Dispatchable applications, 19, 75Dispersed generation sources (DSGS), 29, 68

costs of interconnection, 169-170electric system operations factors, 176-179electric system planning factors, 174-176guidelines for interconnection, 170-174, 295interconnection issues, 162-165interconnection performance, 165-166interconnection requirements and, 258, 266, 269, 272overview, 161-162

policy options, 295, 299protection issues, 167-169regional opportunities, 211technology, 163

Distributed control systems, 154, 156Distribution planning, 175-176, 220-221

Diversification, 64, 66, 70, 296-297Dow Chemical, 273, 274DSGS. See Dispersed generation sourcesDual-flash systems, 97-99, 267Duke Power Co,, 140Dynamic stability, 179

East Central Area Reliability Coordination Agreement

(ECAR), 187, 188, 203ECAR. See East Central Area Reliability Coordination

AgreementEDA. See Energy Development AssociatesElectricity demand growth. See Demand growthElectric power industry, 7-8, 10-12, 58. See a/so

Nonutility power generation; Utility investmentElectric Power Research Institute (EPRI), 29, 147-149,

154, 171, 175, 267, 270, 273-275, 277-281, 299Electric Reliability Council of Texas (ERCOT), 183, 187-

200, 204Empire State Electric Energy Research Corp., 273End-use sectors, 143, 145-146Energy Development Associates (EDA), 281Energy Sciences, Inc., 263

Energy storage, 117-118. See also Battery storage;Compressed-air energy storageEnvironmental issues

atmospheric fluidized-bed combustion, 243, 245combustion technologies, 243, 245compressed air energy storage, 121-122cross-technology comparison, 243-244fuel cells, 245geothermal systems, 98, 100, 245integrated gasification/combined-cycle plants, 243,

245, 276-277photovoltaic systems, 80-81, 245plant betterment, 135, 139regional, 203, 205, 207, 214solar thermal-electric powerplants, 91, 245wind turbines, 93, 245

Equipment cost and performance, 257, 268, 272, 275,282

ERCOT. See Electric Reliability Council of TexasFederal Energy Regulatory Commission (FERC), 192, 211Federal Power Act of 1935, 43-44Federal support, 255, 259, 260, 262, 267, 268, 270,

273, 274, 278-280, 286-287FERC. See Federal Energy Regulatory CommissionFinancial performance, 46, 48-49, 55-56, 60-61, 68Financing, 46, 230-234, 259, 260, 263-264Flat-plate photovoltaic systems, 78-80, 83FLEXPOWER, 281Florida Power Corp., 140Fluidized-bed combustion, 20. See ako Atmospheric

fluidized-bed combustion

Flywheels, 118Foreign competition, 24, 257, 258, 263, 271, 280-281Foreign markets, 4, 258, 263, 266, 288-289Fuel cells

commercial prospects, 23, 102-103, 271-272cost and performance projections, 103-108, 313



Index q 3 2 5

environmental issues, 245industry development, 269-271nonutility profitability analysis, 235, 238, 240overview, 102-103regional opportunities, 200, 213technology, 20, 103utility cost analysis, 224

Fuel prices, 44, 225Fuel reliance, 194-195, 203-207, 209-212, 214-215Fuel supply contracts, 232Fuel Use Act. See Powerplant and Industrial Fuel Use

Act of 1978Full-avoided cost, 69

Gas Research Institute (GRI), 270General Electric, 273Generating capacity, 8, 25, 29-30, 61-62, 225, 229, 230Generation mix, 44 Generation system planning, 174-175, 220Georgia Power & Light Co., 168Geothermal Loan Guarantee Program, 267Geothermal power stations

binary cycle systems, 23, 99-102, 267

commercial prospects, 23, 98, 100, 267-269cost and performance projections, 98, 100-103, 309dual-flash systems, 97-99, 267environmental issues, 98, 100, 245industry development, 266-267nonutility profitability analysis, 235, 236, 240, 241overview, 96regional opportunities, 31, 199, 210, 212, 213technology, 20, 96-100utility cost analysis, 224

Government-owned power systems, 58Great Plains Gasification Associates, 273GRI. See Gas Research Institute

Harmonic voltages, 163-164, 167Hawaiian Electric Renewable Systems, Inc., 213Hawaii Electric Light Co. (HELCo), 178Hawaii region, 212-214HELCo. See Hawaii Electric Light Co.HFM. See High-frequency modulationHigh-frequency modulation (HFM), 167-168Houston Lighting & Power, 177

IEEE. See Institute of Electrical and Electronic EngineersIGCCs. See Integrated gasification/combined-cycle

powerplantsIllinois Power Co., 273Induction generators, 163-164, 169Industrial sector, 145, 150Information collection, 289Innovative rates, 147-148, 150Institute of Electrical and Electronic Engineers (IEEE), 29,

171Insurance coverage, 140Integrated gasification/combined-cycle powerplants

(IGCCs)

commercial prospects, 22, 108, 110, 275-277cost and performance projections, 110, 312environmental issues, 243, 245, 276-277industry development, 272-275overview, 108, 110regional opportunities, 200technology, 20, 108utility cost analysis, 224

Interconnectioncosts, 169-170definition of terms, 164issues, 162-165performance, 165-166policy options, 295, 299protection factors, 167-169requirement effects, 69, 258, 266, 269, 272standards, 29, 170-174, 295 See a/so Power transfers

Interest coverage ratio, 62, 227Internal rate of return (lRR), 234, 238-240International cooperation, 270Interregional transmission. See Power transfersInverters, 163Investment decisions. See Nonutility power generation;

Utility investmentInvestor-owned utilities (IOUs), 58, 64, 147, 212Investor Responsibility Research Center (lRRC), 229, 240IOUs. See Investor-owned utilitiesIRR. See Internal rate of returnIRRC. See Investor Responsibility Research Center

Japan Cool Water Program Partnership, 273Japanese programs, 270-271, 280-281Joint ventures, 233, 270

Kellog Rust, 273

LaJet Energy Co., 194, 260LaJet, Inc., 90, 91, 260Land access, 265, 268-269Lead-acid batteries, 122, 123, 125, 127, 281, 282Lead-times

atmospheric fluidized-bed combustion, 23, 117batteries, 123compressed air energy storage, 24, 122fuel cell systems, 104geothermal systems, 23, 98, 1 0 1integrated gasification/corn bined-cycle combustion,

22, 108, 110investment decisions and, 62photovoltaic systems, 81policy options, 287-288solar thermal-electric powerplants, 91wind turbines, 94

Leasing, 233, 268-269

Levelized busbar costs, 222, 224, 225, 246-248Lewis Research Center, 270Licenses, 192, 265, 269, 272, 276, 280, 282, 294Life extension. See Plant bettermentLifetime rate requirements, 55




Limited partnerships, 233, 260, 263-264Load control

activities, 148-151systems, 152-157

Load dependence, 68Load forecasting, 220Load-leveling, 117Load management

business strategies, 64constraints, 21, 157-158customer controlled technologies, 157dispersed source generation use, 299end-use sector variables, 143, 145-146innovative rate activities, 147-148, 150investment factors, 226-227load control activities, 148-151overview, 142-143peak load reduction potential, 149-151prospects for, 25, 28regional opportunities, 30, 188-190, 213-215, 226-227technologies, 20, 151-157variables, 146-147

LOLP. See Loss of Load ProbabilityLongevity improvements, 136Loss of Load Probability (LOLP), 54-55Lurgi Gesellschaften, 273Luz Engineering Corp., 259-260Luz Industries (Israel) Ltd., 260

MAAC. See Mid-Atlantic Area CouncilMcDonnell Douglas, 260MAIN. See Mid-America Interpool NetworkMAPP. See Mid-continent Area Power PoolMeters, 151-152, 168-169Mid-America Interpool Network (MAIN), 187, 195,

205-206Mid-Atlantic Area Council (MAAC), 183, 188-190,

204-205Mid-continent Area Power Pool (MAPP), 187, 200,

206-207Minimum revenue requirement approach, 222-225Moonlight program, 271, 280Mounted-engine parabolic dish, 90, 91, 262Municipal utilities, 58, 148

NARUC. See National Association of Regulatory UtilityCommissioners

NASA. See National Aeronautics and SpaceAdministration

National Aeronautics and Space Administration (NASA),270

National Association of Regulatory UtilityCommissioners (NARUC), 188

National Electric Code (NEC), 29,.171

Natural gas restrictions, 3, 35, 60, 211, 277, 297NEC. See National Electric CodeNERC. See North American Electric Reliability CouncilNew Source Performance Standards (NSPS), 135, 139New technologies

accelerated development, 2-3

advantages, 1-2, 67-68commercial generating prospects, 3-4, 22-25comparative cost analysis, 222-225, 246-248cost and performance, 21current activities, 25, 70, 129description, 20disadvantages, 2, 68-69industry characteristics, 32-33

investment in, 31-32, 42, 59-60, 227-228lead-times, 21-22nonutility profitability analysis, 234-241, 248-250overview, 19-21, 75policy goals, 33policy options, 33-36regional opportunities and, 199-200, 204-209, 211-214tax incentives, 36-37 See a/so Dispersed generation

sources; Nonutility power generationNew York State Electric & Gas, 171Nondispatchable applications, 19, 68, 75Nonutility power production

accelerated development, 3, 4cross-technology profitability comparison, 234-241,

248-250

investment decisionmaking, 32, 231-234history, 228market characteristics, 228-229policy options, 290-295producer characteristics, 229-230role of, 11utility interaction, 68-69See also Dispersed generation sources

North American Electric Reliability Council (NERC), 8,183, 185

Northea st Power Co ordinating Counc il (NPCC), 187,189, 190, 195, 200, 207-208

Northwest Power Pool Area (NWPP), 210NPCC. See Northeast Power Coordinating CouncilNSPS. See New Source Performance StandardsNucla facility, 140Nuclear power, 49, 52-53, 62, 64, 204-209, 211NWPP. See Northwest Power Pool Area

Oak Creek Station, 140Obsolescence, 257Occupational Safety and Health Administration (OSHA),

167Operations management, 174, 176-179Operations planning, 176OSHA. See Occupational Safety and Health

Admin i s t r a t ionOverseas markets, 4, 258, 263, 266, 288-289Ownership structure, 230-232

Pacific Gas & Electric (PG&E), 57, 63

Parabolic dishes, 24, 84-85, 90-91, 260-262Parabolic troughs, 24, 85, 89-90, 259-262PCS. See Power-conditioning subsystemsPeak load reduction, 149-151Pennsylvania Power & Light Co. (PP&L), 140PEPCO. See Potomac Electric Power Co.



Index . 327

Performance test and analysis, 136, 137Permits, 192, 265, 269, 272, 276, 280, 282, 294, 297PFBC. See Pressurized fluidized-bed combustorPG&E. See Pacific Gas & ElectricPhosphoric Acid Fuel Cell Program, 270Photovoltaics (PVS)

commercial prospect, 23-24, 78-80, 255-258cost and performance projections, 80-81, 83-84, 304

environmental issues, 80-81, 245industry development, 253-255interconnection factors, 178-179nonutility profitability analysis, 235, 238-41overview, 77-80regional opportunities, 211technology, 20, 77-80utility cost analysis, 224

PIFUA. See Powerplant and industrial Fuel Use ActPlanning, 174-176, 220-221, 299Plant betterment

business strategies, 64-65cost and performance, 137, 139current activities, 140insurance coverage, 140objectives of, 135-137overview, 133, 135prospects for, 25regional opportunities, 30, 195, 215regulation of, 139, 226, 227utility cost analysis, 224, 226

Policy optionscost and performance related, 286-289dispersed generation related, 295, 299nonutility related, 290-295overview, 285utility related, 295-298

Port Washington Station, 140Potomac Electric Power Co, (PEPCO), 140, 274Potomac River Station, 140Power-conditioning subsystems (PCS), 80, 81, 83, 167-

168, 170Power Cost Equalization Program, 211-212Power factor, 164Powerplant and IndustrialFuel Use Act of 1978, 35,

122, 211, 261, 277, 280, 297Power quality, 163-164, 167-168Power sales contracts, 232-233Power transfers, 30, 65-66, 203-208, 210-213, 215PP&L. See Pennsylvania Power & Light Co.Predispatch problem, 176Pressurized fluidized-bed combustor (PFBC), 112Prevention of Significant Deterioration (PSD), 139Production Tax Credit (PTC), 36, 291Productivity improvements, 136Profitability, 60-61

Profitability analysis, 234-241, 248-250Project financing, 231-233Protection and control subsystems, 162-163, 165-166PSD. See Prevention of Significant Deterioration permitsPTC. See Production Tax CreditPublicly owned power systems, 58, 147

Public utility commissions, 11, 34-35Public Utility Regulatory Policies Act of 1978 (PURPA),

3, 4, 22, 35, 42, 228, 230, 294-295, 297-298Pumped hydro plants, 118PURPA. See Public Utility Regulatory Policies Act of

1978PVS. See Photovoltaics

R&D. See Resea rch a nd de velopm entReactive power, 163, 164Rate of return, 234, 238-240Rates

battery storage and, 282determination of, 223innovative, 147-148, 150load management and, 147-148, 150minimizing, 55nonutility generation and, 69regulation, 190-191research and development cost factors, 69shock effects, 67

Real-time operations, 176Regional differences

avoided cost, 190-191definition of regions, 183demand growth { 183, 185, 187, 214generation mix, 29-30fuel reliance, 194-195, 214load management, 30, 188-190, 213-214, 226-227nonutility generation, 198-200plant betterment opportunities, 195, 215, 226-227power transfers, 30, 197-198, 203region profiles, 203-214reliability criteria, 30-31renewable resources, 31small-scale system regulation, 192utility choice variables, 183, 214-215

Regional distributionload control activities, 148-149, 151

Rehabilitation. See Plant bettermentReliability, 30-31, 54-55, 67-68, 137-138, 197Remote-engine parabolic dish, 90Renewable Energy Tax Credit (RTC), 3, 24, 36, 241,

255-257, 260, 262, 264, 267, 268, 290-294Research and development (R&D)

acce le ra t ed deve lopmen t and , 3a tmosphe r i c f l u id i zed -bed combus t ion , 117battery storage, 281fuel cells, 108, 270-272geothermal power, 267, 268integrated gasification/corn bined-cycle plants, 274-275opportunities for, 25policy options, 33-35, 287-288, 295-296, 299

power transmission system, 213rate setting and, 69role of, 12solar thermal-electric powerplants, 87, 90utility activities, 70wind turbines, 95-96




Reserve margins, 30-31, 185-187, 203, 204, 206, 208,209, 214, 220

Residential sector, 143, 145, 147-151Resource assessment, 257, 261, 264-265, 268, 289Resource availability, 199-200, 215Risk, 57Risk reduction, 232RMPA. See Rocky Mountain Power Area

Rock caverns, 119, 122Rocky Mountain Power Area (RMPA), 210Rotating generators, 163, 164RTC. See Renewable Energy Tax CreditRural electric cooperatives, 58, 148

Salt reservoirs, 119, 121, 122Sandia Laboratory, 167, 168, 170SEGS. See Solar Electric Generating SystemSensitivity analyses, 224-225, 238, 240-241SERC. See Southeastern Electric Realibility CouncilShawnee Steam Plant, 115, 277, 278Shell, 273, 275Short-period analysis, 57Silicon, 83

Single phase electromechanical watt-hour meters, 151,152Single-phase power, 164Single watt-hour meters, 168Siting policies, 192, 194, 297Small Power Producer (SPP), 233Sodium-sulfur batteries, 123SOHIO, 273Solar Electric Generating System (SEGS), 89, 90, 260,

261Solar Energy Research Institute, 259Solar One pilot facility, 259Solar ponds, 85-87, 89, 259Solar technologies, 76-77, 175, 200, 212-214

commercial prospects 24, 86-87, 89-91, 260-262cost and performance projections, 91, 306-307environmental issues, 91, 245industry developments, 259-260nonutility profitability analysis, 235, 238, 241overview, 86-91regional opportunities, 31technology, 20, 84-86See also Photovoltaics; Solar thermal-electric

powerplantsSolar thermal-electric utility cost analysis, 224Solar troughs, 24, 85, 89-90, 259-262Sole ownership, 231-232SOLMET data, 257Southeastern Electric Reliability Council (SERC), 187-

190, 195, 208-209Southern California Edison, 63, 260, 273, 275

Southwest Power Pool (SPP), 187, 189, 195, 200,209-210

Soyland Electric Cooperative, 121, 122, 279Special rates, 147-148, 150Spinning reserve, 117

SPP. See Small Power Producer; Southwest Power PoolStandards

interconnection, 170-174, 295photovoltaic equipment, 258wind turbines, 265

Storage, 117-118.See a/so Battery storage; Compressed-air energy

storage

Superconducting magnetic energy storage, 118Susitna Project, 211Sustainability, 61Synchronous generators, 163, 164, 169Synthetic Fuels Corp. 273, 274System 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., 273Tennessee Valley Authority (TVA), 115, 140, 273, 277,

278Texaco, Inc., 273THD. See Total harmonic distortionThe Geysers, California, 266Thermal storage, 157Three-phase power, 164Toshiba, 270Total flow systems, 96Total harmonic distortion (THD), 163Transient stability, 179Transmission facilities, 265-266, 269, 294Transmission planning, 175, 220-221Treasury Department, 240TVA. See Tennessee Valley Authority

UCGA. See Utility Coal Gasification AssociationUncertainty sensitivity, 224-225, 240United Stirling, 260United Technologies, 270Utility Coal Gasification Association (UCGA), 275Utility-grade relays, 164, 171-172Utility grid, 162-163. See a/so InterconnectionUtility industry structure, 58Utility investment

business strategies, 63-70commercial deployment role, 34comparative cost analysis, 222-225, 246-248constraints, 219-220current activities, 70demand growth and, 46, 48-49, 52-53extent, 42financial criteria, 61-62new technology prospects, 31-32, 53-54, 59-60,

227-228objectives, 54-56operations factors, 176-179overview, 41planning factors, 174-176, 220-222