Industrial and Commercial Cogeneration - OTA Archive

Industrial and Commercial Cogeneration

February 1983

NTIS order #PB83-180547


- -' . _ ..... -

— —

Library of Congress Catalog Card Number 83-600702

For sale by the Superintendent of Documents,U.S. Government Printing Office, Washington, D.C. 20402

Foreword

This assessment responds to requests by the House Committees on Banking,Finance, and Urban Affairs; Energy and Commerce; and Science and Technology foran evaluation of the economic, regulatory, and institutional barriers to the develop-ment of cogeneration systems by utilities, industries, and businesses. This report com-plements a forthcoming OTA analysis of Industrial Energy Use in evaluating the poten-tial for onsite energy production in industry. The findings also will serve as part of thematerial to be used in future OTA assessments of other electricity-generating technol-ogies.

The report describes the available and promising future cogeneration technologies,including their likely costs and operating characteristics, and reviews the potential ap-plications for these technologies in industry, commercial buildings, and rural/agriculturalareas. It also describes the technical requirements for interconnecting cogenerationsystems with the utility grid, and discusses advanced combustion and conversion tech-nologies (fluidized bed and gasification systems) that will enable cogenerators to usefuels other than oil and natural gas. The analysis of cogeneration’s market potentialfocuses on the competitiveness of cogeneration when compared to investments in con-servation or in conventional separate thermal and electric energy systems (e.g., an in-dustrial boiler and a central station utility powerplant). In addition, the report examinesthe possible effects of the widespread use of cogeneration systems on utilities and theirratepayers, and on air quality. Several options for changes in Federal policy in orderto enhance cogeneration’s market potential, to optimize its ability to displace oil andnatural gas, and to mitigate its possible adverse economic and environmental impactsare discussed.

We are grateful for the assistance of the project advisory panel and the advice ofnumerous individuals in utilities, industry, State governments, trade associations, anduniversities. Also the contributions of several contractors, who performed backgroundanalyses, are gratefully acknowledged.

. Ill


James J. Stukel, ChairmanUniversity of Illinois

Roger BlobaumRoger Blobaum & Associates

William H. CorkranAmerican Public Power Association

Claire T. Dedrick*California Land Commission

Steven FerreyNational Consumer Law Center

Todd La PorteUniversity of California at Berkeley

Evelyn MurphyThe Evelyn Murphy Committee

Advisory PaneI

Theodore J. NagelAmerican Electric Power Service Corp.

Thomas W. ReddochUniversity of Tennessee

Bertram SchwartzConsolidated Edison Co. of New York

Harry M. TrebingMichigan State University

Thomas F. WidmerThermo Electron Corp.

Robert H. WilliamsPrinceton University

* Ex officio. Dr. Dedrick is a member of the OTA Technology Assessment Advisory Council.

iv

OTA Industrial and Commercial Cogeneration Project Staff

Lionel S. Johns, Assistant Director, OTAEnergy, Materials, and International Security Division

Clark

Richard E. Rowberg, Energy Program Manager

Jenifer Robison, Project Director

Eric Bazques Steven Plotkin David Strom

Bullard Charles Holland J. Bradford Hollomon*

Research Assistants

Lois Gottlieb George Hoberg Martin Hsia

Administrative Staff

Virginia Chick Marian Grochowski Lillian Quigg Edna Saunders

Contractors and Consultants

Thomas CastenDecision Focus, Inc.Energy and Resource Consultants, Inc.ICF, inc.Edward KahnL. W. Bergman & Co.William Snyder

OTA Publishing Staff

John C. Holmes, Publishing Officer

John Bergling Kathie S. Boss Debra M. Datcher Joe Henson

Doreen Cullen Donna Young

● Project Director through July 1980.

Acknowledgments

OTA thanks the following people who took time to provide information or to review part—or all of the study:

Dwight AbbottAerospace Corp.Weible AlleyArkansas Power & Light Co.Douglas BellU.S. Environmental Protection AgencyBen BlaneyU.S. Environmental Protection AgencyMerrilee BonneyU.S. Environmental Protection AgencyJosh BowenU.S. Environmental Protection AgencyJoel P. BrainerdNew York Public Service CommissionJohn DadianiTRW Corp.Douglas C. DawsonSouthern California Edison Co.Fred 1. DennyEdison Electric InstituteRichard DonovanNational Aeronautics and Space AdministrationFred DryerPrinceton UniversityLowell J. EndahlNational Rural Electric Cooperative AssociationPeter FreudenthalConsolidated Edison Co. of New YorkHoward GellerAmerican Council for an Energy Efficient EconomyMarty GordonEdison Electric InstituteTom GrahameU.S. Department of EnergyJ. Steven HerodU.S. Department of EnergyRonald JohnsonAerospace Corp.R. Eric LeberAmerican Public Power AssociationTom LepleyArizona Public Service Co.

Elliot LevineArgonne National LaboratoryGlenn LovinInternational Cogeneration SocietyFrederic MarchConsultantTom MarciniakArgonne National LaboratoryAlan S. MillerNatural Resources Defense CouncilRalph C. Mitchell, IllArkansas Power & Light Co.David MorrisInstitute for Local Self-RelianceDale PahlU.S. Environmental Protection AgencyRobert PodlasekIllinois Commerce CommissionWilson PritchettNational Rural Electric Cooperative AssociationArnold RosenthalConsolidated Edison Co. of New YorkBlair A. RossAmerican Electric Power Service Corp.Barry SaitmanCalifornia Energy CommissionFred SissineCongressional Research ServiceElinor SchwartzState of California, Washington OfficeWalt StephensonU.S. Environmental Protection AgencyJohn WilliamsU.S. Department of EnergyL. J. WilliamsElectric Power Research InstituteR. L. WilliamsEBASCO Services Inc.Mike ZimmerCogeneration Coalition, Inc.

vi

Contents

Chapter Page

I. Overview . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . $ . . . . . . . . . . . . . . . . . . . . . 3

2. issues and Findings. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25

3. Context for Cogeneration . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 49

4. Characteristics of the Technologies for Cogeneration . . . . . . . . . . . . . . . . . . . 117

5. lndustrial, Commercial, and Rural Cogeneration Opportunities . . . . . . . . . . . 171

6. impacts of Cogeneration . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 221

7. Policy Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 267

AppendixesA. Dispersed Electricity Technology Assessment Model . . . . . . . . . . . . . . . . . . . 283

B. Emissions Balances for Cogeneration Systems . . . . . . . . . . . . . . . . . . . . . . . . . 286

C. Acronyms, Abbreviations, and Glossary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 288

index . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 295

vii

Chapter 1

Overview

Contents

PageIntroduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3

Cogeneration Technologies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6

The Potential for Cogeneration . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10

Cogeneration Opportunities .. .. ... ... . . . . . . . . . . . . . . . . . . . . . . . . . . 11industrial Cogeneration . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . 11Commercial Building Cogeneration . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12Rural Cogeneration Opportunities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13

Interconnection Requirements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13

impacts of Cogeneration . . . . . . . . . . . . . . . . . . . . . . . .. .. .. .. .. ... ... ..... . . . . . 15Effects on Fuel Use..... . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15impacts on Utility Planning and Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15Environmental Impacts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16Socioeconomic Impacts. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17

Policy Considerations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18Oil Savings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18Economic incentives for Cogeneration . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19Utility Ownership . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20Interconnection Requirements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20Air Quality Considerations. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21Research and Development. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21

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

Tables

Table No. Pagel. Summary of Cogeneration Technologies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 82. lnstalled lndustriaI Cogeneration Capacity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11

Figures

Figure No. PageI. Historical Overview of Electricity-Generating Capacity, Consumption, and

Price, 1902-80 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 42. Conventional Electrica! and Process Steam Systems Compared With a

Cogeneration System . . . . . . .. .. .. .. .. .. ... ... ......O . . . . . . . . . . . . . . . . . . . . . 7

Chapter 1

Overview

INTRODUCTIONA major focus of the current energy debate is

how to meet the future demand for electricitywhile reducing the Nation’s dependence on im-ported oil. Conservation in buildings and in-dustry, and conversion of utility central stationcapacity to alternate fuels will play a major rolein reducing oil use in these sectors. But cost-effective conservation measures can only go sofar, and the industrial and commercial sectorsultimately will have to seek alternative sourcesof energy. Moreover, electric utilities may facefinancial, environmental, or other constraints onthe conversion of their existing capacity to fuelsother than oil, or on the construction of new alter-nate-fueled capacity.

A wide range of alternate fuels and conversiontechnologies have been proposed for the indus-trial, commercial, and electric utility sectors. Oneof the most promising commercially availabletechnologies is cogeneration. Cogeneration sys-tems produce both electrical (or mechanical)energy and thermal energy from the same pri-mary energy source. Cogeneration systemsrecapture otherwise wasted thermal energy, usu-ally from a heat engine producing electric power(i.e., a steam or combustion turbine or diesel en-gine), and use it for applications such as spaceconditioning, industrial process needs, or waterheating, or use it as an energy source for anothersystem component. This “cascading” of energyuse is what distinguishes cogeneration systemsfrom conventional separate electric and thermalenergy systems (e.g., a powerplant and a low-pressure boiler), and from simple heat recoverystrategies. Thus, conventional energy systemssupply either electricity or thermal energy whilea cogeneration system produces both. The auto-mobile engine is a familiar cogeneration systemas it provides mechanical shaft power to movethe car, produces electric power with the alter-nator to run the electrical system, and uses theengine’s otherwise wasted heat to provide com-fort conditioning in the winter.

Cogeneration is an old and proven practice.Between the late 1880’s and early 1900’s, oil- andgas-fired cogeneration technologies were increas-ingly used throughout Europe and the UnitedStates. In 1900, over 59 percent of total U.S. elec-tric generating capacity was located at industrialsites (not necessarily cogenerators) (see fig. 1).Because electric utility service during this periodwas limited in availability, unreliable, unregu-lated, and usually expensive, this onsite genera-tion provided a cheaper and more reliable sourceof power. However, as the demand for electric-ity increased rapidly and reliable electric servicewas extended to more and more areas in the early1900’s, as the price of utility-generated electric-ity declined, and as electric generation becamea regulated activity, industry gradually began toshift away from generating electric energy onsite.By 1950, onsite industrial generating capacity ac-counted for only about 17 percent of total U.S.capacity, and by 1980 this figure had declinedto about 3 percent. At the same time, cogenera-tion’s technical potential (the number of sites witha thermal load suitable for cogeneration) hasbeen increasing steadily.

There has been a resurgence of interest in re-cent years in cogeneration for industrial sites,commercial buildings, and rural applications. Acogenerator could provide enough thermal ener-gy to meet many types of industrial processneeds, or to supply space heating and coolingand water heating for a variety of different com-mercial applications, while supplying significantamounts of electricity to the utility grid. Becausecogenerators produce two forms of energy in oneprocess, they will provide substantial energy sav-ings relative to conventional separate electric andthermal energy technologies. Because cogener-ators can be built in small unit size (less than 1megawatt (MW)) and at relatively low capital cost,they could alleviate many of the current prob-lems faced by electric utilities, including the dif-ficulty of siting new generating capacity and the

3

4 ● Industrial and Commercial (generation

1

Figure l.— Historical Overview of Electricity.Generating Capacity,Consumption, and Price, 190240 - - -

107

1902 1912 1920 1930 1940.— ..-

1950 1980 1970 1980

Electricity generationbecomes a regulatedindustry

106

105

104

103

SOURCE: Office of Technology Assessment from Edison Electric Institute, Statistical Yearbook of the Electric UtilityIndustry: 1980(Washington, D.C.: Edison Electric Institute, 1961); Historical Statistics of the United States, Co.-Ionial Times to 1970: Part 2 (Washington, D.C.: U.S. Government Printing Off Ice, 1976).

high interest costs currently associated withfinancing large powerplants. The small size ofcogeneration systems also may be attractive asa form of insurance against short-term fluctuationsin electricity demand growth (in lieu of the cost-ly overbuilding of central station powerplants).However, if cogenerators are not designed andsited carefully, and if their operation is not coor-dinated with that of the electric utilities, they alsohave the potential to increase oil consumption,contribute to air quality problems in urban areas,and increase the cost of electric power.

Congress has expressed considerable interestin decentralized energy systems and in cogenera-tion. Cogeneration is a major issue in the NationalEnergy Act of 1978, parts of which were designedto remove existing regulatory and institutional obstacles to cogeneration and to provide economicincentives for its implementation. In addition, theHouse Energy and Commerce Committee, theHouse Science and Technology Committee, andthe Senate Energy and Natural Resources Com-mittee have held hearings on cogeneration, andseveral committees in both Houses of Congresshave held hearings on the general concept ofdecentralized energy systems.

The House Committee on Banking, Finance,and Urban Affairs requested that OTA undertakea study of small electricity-generating equipment.The request expressed concern that “considera-tions of energy policy have not taken adequatelyinto account the possibilities for decentralizingpart of America’s electrical generating capabilitiesby distributing them within urban and other com-munities.” Citing the financial problems currentlyfaced by electric utilities and the availability ofa wide range of new generating technologies, thecommittee requested “a careful examination ofthe role that small generating equipment couldplay and the economic, environmental, social,political, and institutional prerequisites and im-plications of greater utilization of such equip-merit. ” In 1981, the House Energy and Com-merce, and Science and Technology Committeeswrote letters to OTA reaffirming congressional in-terest in a study that would provide a betterunderstanding of the economic, regulatory, andinstitutional barriers to the development of cogen-

eration and small power production by utilities,industries, and businesses.

In response to these requests, OTA undertookthis assessment of cogeneration technologies. Theassessment was designed to answer four generalquestions:

1.

2.

3.

4.

In

Under what circumstances are cogenerationtechnologies likely to be economically at-tractive and on what scale, and what is thepotential for new technologies in the future?How much electric power is economicallyor technically feasible for cogeneration tocontribute to the Nation’s energy supply?What are the economic, environmental, so-cial, and institutional impacts of cogenera-tion?What policy measures would accelerate orretard the use of cogeneration systems?

order to answer these questions, this reportreviews the features of the Nation’s energy pic-ture (e.g., supply of and demand for fuels andelectricity) and of the electric power industry thatmay affect decisions to invest in cogenerationsystems; describes the major technologies suit-able for cogeneration applications; analyzes theimpacts of industrial and commercial cogenera-tion on utility planning and operations, on fueluse, and on environmental quality; and discussesthe policy issues arising from existing legislationor regulations related to cogeneration. Becauseelectric utilities are most likely to be affectedstrongly by onsite generation, the technical, in-stitutional, and policy analyses focus on the roleof utilities in such generation, and its effects ontheir future planning and operations.

The main focus of the report is the use of co-generation equipment in the industrial and com-mercial sectors; promising rural applications arediscussed briefly. The cogeneration technologiesaddressed in detail include steam and combus-tion turbine topping cycle equipment as well ascombined-cycle systems, diesel topping cycles,Rankine bottoming cycles, Stirling engines, andfuel cells. Other small power production tech-nologies (wind, solar electric, small-scale hydro)originally were included in the scope of thisstudy. However, OTA found that reliable data on

6 ● Industrial and Commercial Cogeneration

these technologies’ potential to produce electric-ity are not yet available. Moreover, the inclusionof four separate types of technologies made thescope of the study too broad. Therefore, analy-sis of these small power production systems hasbeen reserved for a subsequent OTA assessmentof electricity supply and demand in general.

Volume I of this report is organized as follows:

●

●

●

chapter 2 highlights the central issues sur-rounding cogeneration and summarizesOTA’S findings on those issues;chapter 3 reviews the context in whichcogenerators will operate, including the na-tional energy situation, current electric utilityoperations, and the regulation and financ-ing of cogeneration systems;chapter 4 presents an overview of the cogen-eration technologies, including their oper-ating and fuel use characteristics, projectedcosts, and requirements for interconnectionwith the utility grid;

chapters analyzes the opportunities for co-generation in industry, commercial build-ings, and rural areas;chapter 6 assesses the impacts of cogenera-tion on electric utilities’ planning and opera-tions and on the environment, as well as ongeneral economic and institutional factorssuch as capital requirements, employment,and the decentralization of energy supply;andchapter 7 discusses policy considerations forthe use of cogeneration technologies.

The appendices to volume I include a descrip-tion of the model used to analyze commercialcogeneration (ch. 5) and of the methods used tocalculate emissions balances for the air qualityanalysis in chapter 6, as well as a glossary of termsand a list of abbreviations used in the report.Selected reports by contractors in support ofOTA’S assessment are presented in volume Il.

COGENERATION TECHNOLOGIESThe principal technical advantage of cogen-

eration systems is their ability to improve theefficiency of fuel use. A cogeneration facility, inproducing both electric and thermal energy, usu-ally consumes more fuel than is required to pro-duce either form of energy alone. However, thetotal fuel required to produce both electric andthermal energy in a cogeneration system is lessthan the total fuel required to produce the sameamount of power and heat in separate systems.Relative efficiencies are portrayed graphically infigure 2 for an oil-fired steam electric plant, anoil burning process steam system, and an oil-firedsteam turbine cogenerator with a high-pressureboiler. It should be noted, that despite its relativeefficiency in fuel use, the fuel saved in cogenera-tion will not always be oil. Only if a cogeneratorreplaces separate technologies that burn oil andwould continue to do so for most of the usefullife of the cogenerator, will the fuel saved withcogeneration be oil.

A wide range of technologies can be used tocogenerate electric and thermal energy. Com-

mercially available technologies are steam tur-bines, open-cycle combustion turbines, com-bined-cycle systems, diesels, and steam Rankinebottoming cycles. Advanced technologies thatmay become commercially available within thenexts to 1s years include closed-cycle combus-tion turbines, organic Rankine bottoming cycles,fuel cells, and Stirling engines. Solar cogenerators(e.g., the therm ionic topping system) also are un-der development, but are not discussed in thisreport.

Cogeneration technologies are classified eitheras “topping” or “bottoming” systems, dependingon whether electric or thermal energy is pro-duced first. in a topping system–the most com-mon cogeneration mode—electricity is producedfirst, and then the remaining thermal energy isused for such purposes as industrial processes,space heating and cooling, water heating, or eventhe production of more electricity. Topping sys-tems would form the basis for residential/com-mercial, rural/agricultural, and most industrialcogeneration applications. In a bottoming system,

Ch. 7—Overview ● 7

Figure 2.—Conventionai Eiectricai and Process Steam System Compared With a Cogeneratlon System

(A) Conventional electrical generating system requires the equivalent of 1 barrel of oil to Produce 800 kWh electricity

Exhaust

W a t e r ~ High-pressure boiler

Mechanical InefficiencyGenerator Inefficiency

Electricity

GeneratorTurbine

(B) Conventional process-steam system requires the equivalent of 2 1/4 % barrels of oil to produce 8,500 lb of prooess steam

Exhaust

Fuel

(C) Cogeneration system requires the equivalent of 2 3/4% barrels of oil to generate the same amount of energy as systems Aand B

Exhaust

Fuel

J

7 1

Resource Planning Associates, Cogerreration.’ Techn/ca/ Concepts, Trends, Prospects (Washington, D. C.: U.S. Department of Energy,DOE-FFU-1703, 1978).

8 . Industrial and Commercial Cogeneration

high-temperature thermal energy is produced first ●

for applications such as steel reheat furnaces,glass kilns, or aluminum remelt furnaces. Heatis extracted from the hot exhaust waste stream ●

and transferred to a fluid (generally through awaste heat recovery boiler), which is then vapor-ized by the waste heat to drive a turbine that pro- ●

duces electricity. The primary advantage of bot-toming cycles is that they produce electricity withwaste heat (i.e., no fuel is consumed beyond thatneeded in the industrial process), but their use ●

is limited to industries that need high-temperatureheat.

Cogeneration technologies vary widely in their●

cost, energy output, efficiency, and other char-acteristics (see table 1). The choice of cogenera-tion equipment for a particular application willdepend on a number of considerations, includ-

●

Electric energy needs: How much electrici-ty is needed onsite and how much is to bedistributed to the grid?Operating characteristics: Will the cogenera-tor be operating all the time or only at cer-tain times of the day or year?Physical site /imitations: How much spaceis available for the cogenerator and its aux-iliary equipment (e.g., fuel handling andstorage)?Air quality considerations: What are theemission limitations onsite and can they beaccommodated through pollution controlsand stack height?Fuel availabillty: Which fuels are readilyavailable, and will the cogenerator displaceoil or some other fuel?Energy costs: What are the relative prices offuels for cogeneration (primarily natural gasin the near term, but also coal, biomass, andsynthetic fuels) and of retail electricity?Thermal energy needs: How much heat/

steam is needed onsite and at what temper- ●

ature and pressure?Capital availability and costs: Will thecogenerator be able to find attractive financ-

Table I.—Summary of Cogeneration Technologies

Part-loadFull-load (at 50% load)

Average annual electric electric Total Net heat Electricity-to-Fuels used availability efficiency efficiency heat rate rate

Technology Unit sizesteam ratio

(present/possibie in future) (percent) (percent) (percent) (Btu/kWh) (Btu/kWh) (kWh/MMBtu)

A. Steam turbinetopping

500 kW-100 MW Natural gas, distillate,residual, coal, wood,solid waste/coal- or bio-mass-derived gases andliquids.

Naturai gas, distillate,treatad residual/coal- orbiomass-derived gasesand liquids.

Externally fired—can usemost fuels.

Naturai gas, distillate,residual/coal- or biomass-derived gases and liquids,

Natural gas, distillate,treated residual/coal- orbiomass-derived gasesand liquids, slurry orpowdered coals.

90-95 14-28 12-25 12,200-24,000 4,5006,000 30-75

140-225

150-230

175-320

350-700

NA

NA

240-300340-500

B. Open-cycle gasturbine topping

100 kW-100 MW 90-95 24-35 19-29 9,750-14,200 5,500-6,500

C. Ciosed-cycle gasturbine topping

D. Combined gasturbine/steemturbine topping

E. Diesel topping

500 kW-100 MW

4 MW-1OO MW

75 kW-30 MW

90-95 30-35

77-65 34-40

60-90 33-40

30-35

25-30

32-39

9,750-11,400 5,400-6,500

8,000-10,000 5,000-6,000

8,300-10,300 6,000-7,500

F. Rankine cyclebottoming:Steam 500 kW-10 MW Waste heat. 90 10-20 Comparable

to full loadComparableto full load

37-4534-40

1 7 , 0 0 0 - 3 4 , 1 0 0 N A

Organic 2 kW-2 MW Waste heat. 60-90 10-20 1 7 , 0 0 0 - 3 4 , 1 0 0 N A

G. Fuel cell toppingH, Stirling engine

topping

40 kW-25 MW3-100 kW

(expect1.5 MW by1990)

Hydrogen, distillate/coal.Externally fired—can use

most fuels.

90-92 37-45Not known— 35-41expected to besimilar to gas tur-bines and diesels.

7,500-9,300 4,300-5,5008,300-9,750 5,500-6,5C4J

Ch. l—0verview ● 9

Table 1 .—Summary of Cogeneration Technologies-continued

Operation and maintenance cost Construction

Total installed Annual fixed cost Variable cost Ieadtime Expected lifetimeTechnology cost ($/kW)a ($/kW) (millions/kWh) (Years)b (years) Commercial status Cogeneration applicabiiity

A. Steam turbine 550-1,600 1,6-11.5 3.0-8.8 1-3topping

25-35 Mature technology —com-mercially available in largequantities.

This is the most commonlyused cogeneratlon tech-nology. Generally used inindustry and utility appli-cations. Best suited forwhere electric/thermalratio is low.

Potential for use in residen-tial, commercial, andindustrial sectors if fuelis available and costeffective.

Best suited to larger scaleutility and Industrial ap-plications. Potential forcoal use is excellent.

Most attractive wherepower requirements arehigh and process heat re-quirements are lower,Used in large industrialapplications such assteel, chemical, andpetroleum refiningindustries.

Reliable and available, canbe used in hospitals,apartment complexes,shopping centers, hotels,industrial centers if fuel isavailable and cost effec-tive, and if can meet envi-ronmental requirements,

B. Open-cycle gas 320-700turbine topping

0.29-0.34 2.5-3.0 0.75-2 20 natural gas15 distillate

Mature technology —com-mercially available in largequantities.

C. Closed-cycle gas 450-900 5 percent of Included inturbine topping acquisition fixed cost

cost per year

2-5 20 Not commercial In theUnited States; is well de-veloped in several Euro-pean countries.

Commercially available;advanced systems by1985.

D. Combined gas 430-800 5.0-5.5 3.0-5.1turbine/steamturbine topping

2-3 15-25

E. Diesel topping 350-800 6.0-8.0 5.0-10.0 0.75-2.5 15-25 Mature technology —com-mercially available in largequantities.

F. Rankine cyclebottoming:

Steam 550-1,100 1,6 3.7-6.9 1-3 20 Commercially available. Industrial and utility usealmost exclusively. Al-though efficiency is low,since it runs on wasteheat no additional fuelis consumed. Can reduceoverall fuel use.

Same benefits/limitationsOrganic 800-1,500 2.8 4,9-7.5 1-2 20 Some units are commerciallyavailable but technologyis still in its infancy.

as steam Rankine bottom-ing except that it can uselower-grade waste heat.Organic Rankine bottom-ing is one of the fewengines that can usewaste heat in the 200°600oF range,

Modular nature, low emis-sions, excellent part-loadcharacteristics allow forutility load foliowing aswell as applications incommercial and industrialsectors.

High efficiency and fuelflexibility contribute to alarge range of applica-tions. Couid be used inresidential, commercial,and industrial applica-tions. Industrial usedepends on developmentof large Stirling engines,

G. Fuel cell topping 520-840C 0.26-3,3 1.0-3.0 1-2 10-15

20

Still in development andexperimental stage. phos-phoric acid expected by1985, moiten carbonate by1990.

Reasonably mature technol-ogy up to 100-kW capacitybut not readily available.Larger sizes beingdeveloped.

H. Stirling engine 420-960 C

topping5.0 8.0 2-5

“NA” means not applicable.a1980 dollars,bDepends on system size and heat source.CCost estimates assume successful development and Commercial scaie production, and are not guaranteed,

SOURCE: Office of Technology Assessment from material in ch. 4,

-

70 ● Industrial and Commercial Cogeneratlon

ing, or will investments in process improve-ments have priority for available capital?

At present, significant uncertainties about thetypes of cogeneration technologies that will beinstalled and their location, costs, and operatingcharacteristics, and about general financial andeconomic conditions make it difficult to analyze

the market potential for cogeneration or its im-pacts on electric utilities, fuel use, and the envi-ronment. However, general trends in the nationalenergy, electric utility, and policy context inwhich cogenerators would be deployed can bediscerned, and analyses of these trends can beused to evaluate existing policy incentives.

THE POTENTIAL FOR COGENERATION

Cogeneration could have a very large technicalpotential in the United States–perhaps as muchas 200 gigawatts (GW) of electrical capacity by2000 in the industrial sector alone, with a muchlower potential (3 to 5 GW) in the commercial,residential, and agricultural sectors. (Total U.S.installed generating capacity in 1980 was approxi-mately 619 GW.) However, cogeneration’s mar-ket potential (the amount of cogeneration capac-ity that might be considered sufficiently economicfor an investment to be made) will be much small-er than this for several reasons.

First, cogeneration investments will have tocompete with conservation in industries andbuildings. Conservation investments usually areless costly than cogeneration and have a shorterpayback period, and thus are likely to receive pri-ority over cogeneration in most cases. As a resultof conservation measures, thermal energy de-mand is likely to grow much more slowly thanit has in the past (some sources project a zeroor negative rate of growth in industrial thermaldemand through 2000), and could present a de-clining opportunity for cogeneration.

In addition, cogeneration will compete in thelong term (beyond 1990) with electricity sup-plied by coal, nuclear, hydroelectric, and othertypes of alternate-fueled electric utility generat-ing capacity. Some cogeneration applicationsmay not be economically competitive where util-ities have relatively low retail electricity rates orare planning to replace existing powerplants withones that will generate electricity more econom-ically (e.g., replacing intermediate-load oil-firedgenerators with baseload coal plants).

Cogeneration’s market potential also will belimited by the inability of most technologies—

especially smaller scale systems—to use fuelsother than oil or natural gas. At present, onlysteam turbine cogenerators can accommodatesolid fuels. Advanced technologies now underdevelopment will have greater fuel flexibility, aswell as better fuel efficiency and lower emissions.In addition, advanced fuel combustion or conver-sion systems such as fluidized beds and gasifierscan be used to improve the fuel flexibility of ex-isting cogeneration technologies. More develop-ment is needed, however, to make these technol-ogies commercially attractive, and they are notlikely to contribute significantly for 5 to 10 years.

Cogeneration’s ability to supply electricity tothe utility grid also will affect its market poten-tial. Under the Public Utility Regulatory PoliciesAct of 1978 (PURPA), economic and regulatoryincentives are offered to cogenerated power thatreduces utility costs for capacity, energy, or trans-mission and distribution, or that contributes topower supply or load reduction during daily orseasonal peak demands. These incentives are re-flected in the price that utilities must pay for pow-er purchased from a cogenerator, which is deter-mined by a utility’s incremental costs, or the costsavoided in not generating and distributing thepower itself or purchasing bulk power from thegrid. In many parts of the country, shortrunavoided energy costs will be based on the pricethe utility pays for oil or natural gas, and capac-ity costs on the operating cost of a peakload pow-erplant (e.g., a combustion turbine). In thesecases, the greater efficiency of cogeneration sys-tems—even those burning distillate oil or naturalgas–often can make cogeneration the economi-cally preferable means of generating electricity.However, if the utility relies primarily on coal ornuclear fuel and has excess capacity, then the

Ch. l—Overview ● 17

shortrun avoided energy cost (determined by off-setting coal or nuclear fuel) would be much lowerand there may be no shortrun avoided capacitycost. In these cases, shortrun avoided cost pay-ments may not be sufficient to make cogenera-tion an attractive investment. Longrun avoidedcosts would be based on a utility’s resource plan,and would raise the issue noted above of com-petition with coal and other non premium fuels.

Furthermore, the choice of technology will af-fect a cogenerator’s ability to supply power to thegrid. In general, technologies with a high ratioof electricity-to-steam production (E/S ratio) willbe favored when onsite electric power needs arelarge or when power is to be exported offsite;these include diesels, combustion turbines, and

combined-cycle systems. At present, however,the high E/S ratio systems can only burn oil ornatural gas. Steam turbines, the only commercial-ly available technology that can burn solid fuelsdirectly, have a relatively low E/S ratio. For ex-ample, a large industrial installation that uses500,000 lb/hr of steam would cogenerate 30 to40 MW of electricity with steam turbines, and 120to 150 MW with combustion turbines. Therefore,where onsite electricity needs are high, or theproject’s economic feasibility depends on sup-plying electricity to the grid, a technology witha higher E/S ratio (e.g combustion turbines,diesels, combined cycles) would be favored, butcould not use fuels other than oil/gas in the shortterm.

COGENERATION OPPORTUNITIESAlthough the factors discussed above make

cogeneration’s overall market potential highly un-certain, it is possible to identify promising cogen-eration opportunities in the industrial and com-mercial sectors and in rural areas.

Industrial Cogeneration

Today, industrial cogeneration has an estimatedinstalled capacity of 14,858 MW (see table 2). *An additional 3,300 MW is reported to be in theplanning stages or under construction. The largestnumber of industrial cogenerators are in the pulpand paper industry, which has large amounts ofburnable wastes (process wastes, bark, scraps,and forestry residues unsuitable for pulp) that canbe used to fuel cogenerators. For at least two dec-

*A more recent estimate arrives at a total of about 9,100 M W(5). No breakdown by SIC code is given, however, but we assumethe distribution would be similar to that given in table 2.

ades this industry has considered electricity gen-eration to be an integral part of its productionprocess and new pulp and paper plants are like-ly candidates for cogeneration.

The chemical industry uses about as muchsteam annually as the pulp and paper industryand historically has ranked third in industrialcogeneration capacity. Chemical plants also willrepresent a promising source of new cogenera-tors. Conservation opportunities, however, willstrongly dampen growth in steam demand if notcause it to decline.

Another major cogenerator is the steel indus-try, because the off-gases from the open-hearthsteelmaking process provide a ready source offuel to produce steam for driving blast furnaceair compressors and other uses. But new cogener-

Table 2.–installed Industrial Cogeneration Capacity

Capacity Capacity Number of PlantsSector (SIC code) (MW) (percent) plants (percent)Food (20) . . . . . . . . . . . . . . . . . . . . . . . . 398 3 42 11Pulp and paper (26) . . . . . . . . . . . . . . . 4,246 29 136 37Chemicals (28) . . . . . . . . . . . . . . . . . . . 3,438 23 62 17Petroleum refining (29) . . . . . . . . . . . . 1,244 8 24 6Primary metals (33) . . . . . . . . . . . . . . . 3,589 24 39 11Other . . . . . . . .’. .’. . . . . . . . . . . . . . . . 1,943 13 68 18

Total . . . . . . . . . . . . . . . . . . . . . . . . . 14,858 371SOURCE: General Energy Associates, Industrial Cogeneration Potential: Targeting of Opportunities at the Plant Site(Waahington,

D. C.: U.S. Department of Energy, 1982).


ation capacity is not likely to be installed in thisindustry because new steel mills probably will beminimills that use electric arcs and have little orno thermal demand. However, if a market for thethermal output could be found, an electric arcminim ill could use the cogenerated electricityand sell the heat/steam.

petroleum refining also is well suited tocogeneration, but significant new refinery capac-ity is not expected to be built in the near future,except in connection with heavy oil recovery inCalifornia. However, some cogeneration capacitycould be installed when existing refineries areupgraded.

Finally, the food processing industry current-ly has a small amount of cogeneration capacitywhich could more than double by 1990. Herethe primary limit on the cogeneration potentialis the low thermal load factor that results fromthe seasonal nature of the steam demand.

Commercial Building Cogeneration

Cogeneration in commercial buildings has amuch smaller potential for growth than indus-trial cogeneration, primarily due to the low ther-mal load factors in those buildings. Additionalconstraints on commercial building cogenera-tion opportunities include the difficulty ofhandling and storing solid fuels (coal, biomass)in and around buildings; competition with con-servation for energy investment funds, and withcoal or other baseload capacity additions foreconomic electricity generation; and the specialair quality considerations in urban areas.

The disadvantages presented by the low ther-mal load factors in commercial buildings can beovercome to some extent by undersizing the co-generator and operating it at a high capacity fac-tor to meet the baseload thermal needs, and usingconventional thermal conversion systems to sup-plement the cogenerator’s output. Alternatively,several buildings could share a cogenerator anduse the diversity in their energy demand to im-prove the thermal load factor.

Moreover, commercial building cogenera-tion fueled with natural gas may have a promis-ing market in the near term (up to 1990), especial-

ly where rates for utility purchases of cogeneratedpower are based on the price of oil-fired elec-tricity generation and utilities have substantialamounts of oil burning capacity. In these cases,cogeneration can allow rapid development of ca-pacity to meet new electricity demand and/or re-duce utility oil use. However, as noted previous-ly, in the long term, cogeneration will have tocompete economically with coal and other alter-nate-fueled utility capacity.

The probable low market penetration of com-mercial sector cogeneration means that it usual-ly will have a low potential for displacing thefuel used by utility generating capacity. How-ever, where electricity prices are high or utilitycapacity additions are limited, cogeneration mayhave a greater market potential and could dis-place utility intermediate oil or gas capacity. Ifboth the cogenerator and the capacity it displacesuse oil, the result usually would be a decreasein utility use of residual fuel oil and a correspond-ing increase in distillate use by commercial co-generators, but an overall reduction in total oiluse. Relatively small systems with good part-loadcharacteristics (e.g., diesels and spark-ignitionengines) are likely to be favored in urban residen-tial/commercial applications where there arephysical site limitations and low capacity factors,and these systems are limited to the use of oil ornatural gas in the near term.

In summary, OTA found that commercialbuilding cogeneration would be economicallyattractive where there is a moderate rate ofgrowth in electricity demand (2 percent or moreannually), where electric utilities are caught ina capacity shortfall, or where the utility has ahigh percentage of oil-fired capacity; wherethere is a high heating demand (about 6,000heating degree days per year); and where cogen-erators can use a fuel that is significantly lesscostly than oil. However, even if these advan-tages are available, cogeneration’s competitive-ness in the commercial sector will be subject tothe same limiting factors as in the industrial sec-tor—competition with conservation measures thathave a lower capital cost and shorter paybackperiod, the ability to supply significant amountsof power to the grid, and economic and regula-tory uncertainties.

C.+. I—Overview ● 13

Rural Cogeneration Opportunities

Rural cogeneration opportunities arise wherethere are existing small community powerplantsthat could recover and market their waste heat,and/or where alternate fuels (such as biomass)are readily available. Promising rural cogenera-tion applications include producing ethanol, dry-ing crops or wood, and heating greenhouses, ani-mal shelters, or homes.

A large number of small rural powerplants arestanding idle due to the high cost of premiumfuels. Generally these are dual-fuel engines burn-ing natural gas plus small amounts of fuel oil tofacilitate combustion; diesel engines and natural-gas-fueled spark-ignition engines are also com-mon. The waste heat from these engines couldbe recovered and use directly (in the case ofnatural-gas-fired systems) or used in heat ex-changers to provide hot water or steam. If onlyhalf of the waste heat were used, a powerplant’senergy output would double, providing a newrevenue stream for the community and enablingthe engines to be operated economically. Thesepotential benefits would be weighed against thecost of installing and operating the heat recoverysystem.

However, cogeneration at an existing ruralpowerplant could increase oil use if it is substi-tuted for grid-supplied electricity generated withalternate fuels. Therefore, rural communitiesshould focus on technologies that can use locallyavailable biomass fuels such as crop residues,wood, and animal wastes. Gasifiers that convert

crop residues or wood to low- or medium-Btugas can be connected with internal combustionengines, although the engines will need somemodification for trouble-free operation over longperiods of time. Such gasifiers are commerciallyavailable in Europe and are being demonstratedin the United States. Anaerobic digestion of ani-mal wastes from confined livestock operationsalso could be used to produce biogas (a mixtureof 40 percent carbon dioxide and 60 percentmethane) to fuel an internal combustion engine.Anaerobic digestion has the advantages of solv-ing a waste disposal problem, while producingnot only biogas but also an effluent that can beused directly as a soil conditioner, dried and usedas animal bedding, or possibly treated and usedas livestock feed. Digesters for use in cattle, hog,dairy, and poultry operations are commerciallyavailable in the United States and are being dem-onstrated at several rural sites. Wastes from rural-based industries, such as whey from cheeseplants, also are being used as a feedstock for farm-based digesters.

Cogeneration can have significant economicand fuel savings advantages in rural communitiesand on farms. The rural cogeneration potentialis not so large as that in industrial and urban ap-plications, but the advantages can be very impor-tant in allowing significant local economic expan-sion—from new jobs and from increased reve-nues due to steam/heat sales—by using local re-sources without increasing the base demand forenergy.

INTERCONNECTION REQUIREMENTSThe economic and other incentives offered to

cogeneration under PURPA assume that cogen-erators will be interconnected with the electricutility grid. Such interconnections may requirespecial measures to maintain power quality, tocontrol utility system operations, to protect thesafety of lineworkers, and to meter cogenerators’power production and consumption properly.OTA found that most of the technical aspectsof interconnection are well understood, and theprimary issues related to interconnection are the

lack of uniform guidelines and the cost of theequipment.

The characteristics of cogenerated electricitythat is distributed to the grid must be within cer-tain tolerances so that utilities’ and customers’equipment will function properly and not bedamaged. Thus, grid-connected cogeneratorsmay need capacitors to keep voltage and currentin phase; over/under relays to disconnect the gen-erator automatically if its voltage goes outside a


certain range; and a dedicated distribution trans-former to isolate voltage flicker problems. Be-cause the power quality impacts of cogeneratorsare technology- and/or site-specific, not all sys-tems will need all of this equipment. In particu-lar, very small cogenerators (under 20 kW) mayhave few or no adverse effects on grid powerquality and may not require any extra intercon-nection equipment. Moreover, larger systemsprobably will already have dedicated transform-ers, and may only need power factor correctingcapacitors if they use induction (as opposed tosynchronous) generators.

Proper interconnection is necessary to ensurethe safety of utility workers during repairs totransmission and distribution lines. First, cogen-erators should locate their disconnect switchesin specified areas in order to simplify lineworkers’disconnect procedures. In addition, inductiongenerators (and, very occasionally, synchronousgenerators) must use voltage and frequency relaysand automatic disconnect circuit breakers to pro-tect against self-excitation of the generator. Alter-natively, the power factor correcting capacitorscan be located where they will be disconnectedalong with the cogenerator (and thus prevent self-excitation) or where they can be isolated easilyby lineworkers.

Large numbers of grid-connected cogeneratorsthat are dispatched by the electric utility may re-quire expensive telemetry equipment and couldoverload utility system dispatch capabilities.However, these problems can be avoided if util-ities treat cogenerators as “negative loads” bysubtracting the power produced by the gener-ators from total system demand and then dis-patching the central generating capacity to meetthe reduced load. Most utilities currently usenegative load scheduling with cogenerators (andsmall power producers), and some studies in-dicate that it may work well even with largenumbers of cogenerators. However, some utilitiesquestion whether the system would continue tofunction properly if a significant percentage oftotal system capacity were undispatched cogen-erators being treated as negative loads. Addi-tional research is needed to determine whetherundispatched cogenerators will cause problemsfor a utility system and, if so, at what degree

of system penetration such problems wouldarise.

Finally, cogenerators’ power production andconsumption must be metered accurately in or-der to provide better data on their output char-acteristics (and thus facilitate utility system plan-ning), and to ensure proper pricing for buybackand backup power. Cogenerators can be me-tered inexpensively with two standard watt-hourmeters—one operating normally to measure con-sumption and the other running backwards to in-dicate production. Alternatively, advanced me-ters can be installed that indicate not only kilo-watthours used/produced but also power factorcorrection and time-of-use. These advanced me-ters provide better data about cogeneration’scontribution to utility system loads, and they facil-itate accurate accounting (and thus pricing) ofpower purchased and sold. However, advancedmeters also cost about five times more than twostandard watt-hour meters.

Estimates of the cost for interconnection varywidely—from $12/kW for a large cogeneratorto $1 ,300/kw for a small system—depending onthe generator type, the system size, the amountof equipment already in place, and a particularutility’s or State public service commission’s re-quirements for equipment type and quality. Ingeneral, interconnection costs will be higher ifa dedicated transformer is needed. Economies ofscale also are apparent for circuit breakers, trans-formers, and installation costs. Moreover, someutilities or commissions may require more equip-ment than described above in order to provideextra protection for their system and the othercustomers. The quality of the interconnectionequipment required also may affect costs substan-tially. Some utilities allow smaller cogeneratorsto use lower quality and less expensive industrial-grade equipment, but the size cutoff varies widelyamong utilities—from 200 to 1,000 kW. In otherareas, all cogenerators are required to use thehigher quality utility-grade equipment, but withsuch equipment the cost of interconnection maybe prohibitive for small cogenerators. Few guide-lines exist for the type and quality of intercon-nection equipment necessary for cogenerators,but several are under preparation. Once standardguidelines are available, interconnection costsshould become more certain.

IMPACTS OF COGENERATION

Cogeneration has the potential for bothbeneficial and adverse effects on fuel use, utilityplanning and operations, and the environment.In each case, OTA found that the potential neg-ative impacts could be mitigated substantiallyif the cogeneration technology is carefully se-lected and sited, if the cogenerator works closelywith the utility throughout the project’s plan-ning and implementation, and if the cogenera-tion system is carefully integrated with existingand planned future energy supplies.

Effects on Fuel Use

All cogenerators will save fuel because theyproduce electric and thermal energy more effi-ciently than the separate conversion technologiesthey will displace (e.g., an electric utilitypowerplant and an industrial boiler). Whethercogeneration will save oil depends on the fuelused by a cogenerator and the fuels used in theseparate systems that are displaced. If both ofthe separate technologies burn oil and wouldcontinue to do so for most of the useful life ofthe cogenerator that supplants them, then evenan oil burning cogenerator will reduce total oilconsumption. However, if either or both of theseparate conventional technologies use an alter-nate fuel (e.g., coal, nuclear, hydroelectric, bio-mass, solar), or would be converted to an alter-nate fuel during the useful life of a cogenerator,then oil-fired cogeneration would increase totalsystem oil use.

Where oil savings are available throughcogeneration, their magnitude will depend onthe type of cogenerator and the types of sep-arate conversion technologies that are dis-placed, as well as on the rates for purchases ofcogenerated power under PURPA. For example,an oil-fired steam turbine cogenerator could re-duce oil use by 15 percent if it is substituted foran oil-fueled steam electric powerplant and sepa-rate low-pressure steam boiler, while a diesel co-generator that recovers three-quarters of the po-tentially usable heat could represent a 25 percentsavings if it replaces a diesel electric generatorand separate oil burning furnace. (Much greater

savings are available if an alternate-fueled cogen-erator replaces separate oil-fired systems.)

Higher rates for utility purchases of cogener-ated power will favor technologies with high E/Sratios, thus increasing the potential to displaceutility generating capacity, much of which willbe intermediate and peakload plants that burnoil. However, because currently available highE/S cogenerators also are limited to the use of oil(or natural gas), care must be exercised in deploy-ing these technologies if it is important to ensurethat oil savings are achieved over the useful lifeof the cogenerator. In many cases, the market(high prices and uncertain availability), regulatoryprovisions, tax measures, and the utility’s avoidedcosts will provide such insurance.

Impacts on Utility Planningand Operations

Cogeneration can offer significant economicsavings for utilities that need to add new capaci-ty. Where utilities need to displace oil-firedcapacity or accommodate demand growth, co-generation can bean attractive alternative to con-ventional powerplants. Cogenerators’ relative-ly small unit size and short construction lead-time can provide more flexibility than largebaseload plants for utilities in adjusting to unex-pected changes in demand, and cogenerationis a more cost-effective form of insurance againstsuch changes than the overbuilding of centralstation capacity. Cogeneration also has the po-tential to significantly reduce interest costs dur-ing construction (and thus the overall cost ofproviding electricity).

Relying on cogeneration capacity instead ofconventional powerplants should not pose signifi-cant operating problems for utilities if the cogen-erators are properly connected to the grid. Asdiscussed previously, large numbers of small grid-connected cogenerators should not overburdenutility system dispatch capabilities if they aretreated as negative loads, but the effects of asubstantial penetration of a system are uncertain.


However, expansion of cogeneration couldhave a substantial adverse economic impact onutilities that have excess capacity and/or a lowrate of growth in demand. If large industrial andcommercial sites drop out of a utility’s load, thenthe utility’s fixed costs must be shared amongfewer customers, who would then have higherelectric rates. This competition has been ob-served in other regulated industries (e.g.,telecommunications, railroads). The effects ofsuch competition are essentially the same asthose of the competition from conservation meas-ures or of the excess capacity that can result fromoil displacement.

Where utilities already have excess capacity orare committed to major construction programsthat cannot be deferred, the risk of reduced fixedcost coverage can be acute. In the long run, suchcompetition could represent a benefit for mostutilities by reducing the need for new capacityand thus relieving financial pressures on utilitiesand lowering rate levels. But until the construc-tion budget is adjusted, the short-term effects ofrevenue losses could be severe for some utilitiesand their remaining customers.

Furthermore, if utilities purchase power fromcogenerators based on the utility’s full avoidedcost, the utility’s non-cogenerating customers maynot receive any economic benefit from cogenera-tion. Cogenerators usually will be installed onlywhere their operating costs would be less thanthe avoided cost rate paid by the utility for theirpower. If the cogenerator receives the full differ-ence, the ratepayer will receive no direct benefit.This situation is exacerbated if the avoided costpayments are higher than the utility’s actual short-run marginal cost (e.g., if the State regulatorycommission bases avoided costs on the price ofoil and the utility operates with a mix of fuels,or if the commission establishes a high avoidedcost as an explicit subsidy to encourage cogener-ation). A payment to cogenerators of less thanthe utility’s full avoided cost, with the differencegoing toward rate reduction, would share anycost benefits of cogeneration with the utility’sother ratepayers.

One solution to both the competition posedby cogeneration and the rate reduction issue is

for utilities to own cogenerators. ownershipcould be advantageous to a utility because thecogenerator would be included in the utility’s ratebase and thus the utility would earn a percent-age return on the equipment. Where cogenera-tion is economically competitive with other typesof capacity additions, utilities should be investingin it. However, cogeneration systems that aremore than 50 percent utility-owned are not eligi-ble for the economic and regulatory incentivesestablished under PURPA, which often determineeconomic competitiveness. If full utility owner-ship were allowed incentives under PURPA, co-generation’s market potential probably would in-crease, as would the amount of electricity itwould supply to the grid (because utilities wouldbe more likely to install high E/S ratio technolo-gies). In addition, utility investment in cogenera-tion would have the economic advantages relatedto the small unit size and shorter constructionIeadtimes discussed previously, and could resultin lower electricity rates compared to conven-tional capacity additions. However, full utilityownership under PURPA raises a number of con-cerns about possible anti-competitive effects andabout the resulting profits to utilities; these arediscussed in more detail under “Policy Consider-ations,” below.

Environmental Impacts

The primary environmental concern about co-generation is the public health effects of changesin air quality. Cogeneration will not automatical-ly offer air quality improvement or degradationcompared to the separate conversion technol-ogies it will replace. Cogeneration’s greater fuelefficiency may lead to either a decrease or an in-crease in the total emissions associated with elec-tric and thermal energy production, dependingon the types of combustion equipment, theirscale, and fuel used. Similarly, cogeneration mayimprove or degrade air quality by shifting emis-sions away from a few central powerplants withtall stacks to many dispersed facilities with shorterstacks, depending on the variables listed aboveas well as on the location of the cogenerators andthe separate systems they replace.

Of the available cogeneration technologies,diesel and gas-fired spark-ignition engines have

Ch. l—Overview ● 17

the greatest potential for adverse air quality im-pacts due to their high–but usually controlla-ble–nitrogen oxide emissions. Diesels also emitpotentially toxic particulate, but clear medicalevidence of a human health hazard is lacking atthis time. Steam and gas turbines should not resultin an increase in total emissions unless they usea “dirtier” fuel than the separate conversion tech-nologies they replace (e.g., a shift from distillateoil to high sulfur coal), or where a new turbinecogenerator that primarily produces electricity isinstalled instead of a new boiler or furnace.

Adverse local air quality impacts are most like-ly to occur with cogeneration in urban areas,because urban cogenerators usually will bediesels or spark-ignition engines, because urbanareas would have a higher total population ex-posure, and because tall buildings can interferewith pollutant dispersion. Moreover, the smallsystems that would be used in these applicationstend to have high nitrogen oxide and particulateemissions. As a result of these considerations,urban cogenerators must be designed and sitedcarefully, including choosing an engine modelwith low emissions, applying technologicalemission controls, and ensuring that the exhauststacks are taller than surrounding buildings.

Cogenerators’ greater fuel efficiency also canlead to an important environmental benefit inother aspects of a fuel cycle (e.g., exploration,extraction, refining/processing) if a cogeneratoruses the same fuel as the conventional energy sys-tems it displaces. However, if a fuel that is dif-ficult to extract, process, and transport (e.g., coal)is substituted for a “cleaner” fuel (such as naturalgas), the overall impact may be adverse ratherthan beneficial.

Finally, cogeneration might affect water qual-ity (from blowdown from boilers and wet cool-ing systems, and from runoff from coal piles andscrubber sludge and ash disposal), waste disposal(sludge and ash), noise, and materials (from cool-ing tower drift). All of these will be more likelyto pose a problem in urban areas, and all areeither controllable and/or are more likely to bea nuisance than a health hazard.

Socioeconomic Impacts

General trends for impacts on economic andsocial parameters such as capital investment,operating and maintenance (O&M) costs (ex-cluding fuel costs), and labor requirements can-not be identified at this time due to the largeuncertainties in future deployment patterns.These impacts will depend heavily on the sizeand type of cogenerators used, the size and typeof separate conversion technologies that wouldbe displaced, the regions in which cogenerationwould be installed (construction costs and laborrequirements generally are lower in the South),and cogenerators’ operating characteristics. Forexample, in comparing cogeneration capital costswith those for conventional baseload and peak-Ioad capacity, OTA found that the cost of install-ing 100,000 MW of electric generating capacityunder cogeneration scenarios varied from about25 percent more to approximately 95 percent lessthan the cost of installing an equivalent amountof capacity under conventional central stationscenarios, depending on the capacity mix andlocation for each scenario.

For purposes of comparison, OTA analyzed themean values for capital and O&M costs, and forconstruction and O&M labor requirements, for50,000, 100,000, and 150,000 MW of electricity-generating capacity with and without cogenera-tion. In this comparison, OTA found that meancapital costs for cogeneration tended to bearound 20 to 40 percent lower than the meancosts for an equivalent amount of conventionalutility capacity. Because cogenerators have ashorter construction Ieadtime than conventionalpowerplants, savings on interest charges duringconstruction would increase this capital cost dif-ference. The O&M cost differences were calcu-lated for two different cogeneration capacityfactors–45 and 90 percent. With a capacity fac-tor of 90 percent, mean cogeneration O&M costswere higher (25 to 70 percent) than mean utilityO&M costs, while cogenerators operating at a 45percent capacity factor had mean O&M costsranging from approximately 20 percent higher toroughly 35 percent lower than mean utility costs.


Construction and O&M labor requirements both In general, these results confirm reports in thetended to be higher for the cogeneration sce- Iiterature that cogeneration could save invest-narios than for the central station capacity ment capital while increasing direct employmentscenarios. Up to 50 percent more construction in electricity supply. However, the actual eco-Iabor might be required for cogeneration than for nomic and employment effects might be muchutility capacity. The O&M labor requirements different if the mix of technologies installed werevaried much more widely due to the lack of data different from those examined by OTA.and the pronounced economies of scale for co-generation O&M labor.

POLICY CONSIDERATIONSThe primary Federal policy initiatives that af-

fect the deployment of cogeneration capacity in-clude provisions of title II of PURPA, the Power-plant and Industrial Fuel Use Act of 1978 (FUA),the Clean Air Act, and the tax laws, as well asGovernment support for research and develop-ment. In general, the combined focus of theseinitiatives is to encourage grid-connected cogen-eration that will use energy economically andutility resources efficiently. Although the long-term effects of these policies on cogeneration im-plementation are still uncertain (due to delays inState implementation and to ongoing changes inFederal priorities), a number of unresolved issueshave been identified for possible further congres-sional action. These include the use of oil in co-generation, the economic incentives for cogener-ation, utility ownership of cogeneration capacity,requirements for interconnection with the grid,and the effects of cogenerators on local airquality.

Oil Savings

Despite their inherent energy efficiency, not allcogenerators will save oil. The purchase powerrate provisions of PURPA, FUA prohibitions onoil use in powerplants and industrial boilers, andthe energy tax credits discourage cogenerationapplications that would increase oil use, but theymay not be effective in all cases. For example,cogenerators with less than about 10-MW gener-ating capacity or that sell less than half their an-nual electric output, are automatically exemptfrom FUA prohibitions. Similarly, an oil-fired co-generator may not be entitled to rates for utility

purchases of cogenerated power under PURPAthat are as high as those paid to systems burningalternate fuels, but the installation could be eco-nomic without those payments (e.g., if retail elec-tricity rates are very high). Moreover, an existingindustrial or commercial oil burning energy sys-tem could be retrofitted for cogeneration and stillqualify for the energy tax credit as long as onsiteenergy use is reduced.

In many cases, the uncertain price and long-term availability of oil, coupled with regulatoryand economic disincentives to its use, will be suf-ficient to discourage oil-fired cogeneration. How-ever, where oil-fired cogenerators still would beeconomic but would not provide lifetime oil sav-ings, additional policy initiatives might be con-sidered if net oil savings is the primary goal.These include amending FUA to prohibit the useof oil in all cogenerators regardless of size or elec-tricity sales unless a net lifetime oil savings canbe demonstrated; amending PURPA to denyqualifying facility status (and thus economic andregulatory incentives) to oil burning cogeneratorsunless net oil savings are shown; and amendingthe investment and energy tax credits and othertax code provisions to deny tax deductions,credits, or other measures for cogeneration proj-ects unless net oil savings are demonstrated.However, these measures may only provide oilsavings of less than 100,000 barrels per day in1990. Moreover, net oil savings are difficult toprove, and these regulations could be expensiveand time-consuming for both potential cogener-ators and implementing agencies, and could dis-courage even those cogeneration systems thatwould save oil.

Ch. 1—Ovefview ● 19

If net oil savings is the primary goal, there areseveral policy alternatives to additional layersof fuel use regulations. First, oil consumptioncould be taxed (e.g., with an oil import fee). Sucha tax would encourage conservation in all oil mar-kets and provide additional Federal revenues.Alternatively, restrictions in FUA and the tax lawson the use of natural gas in cogenerators mightbe eliminated. Natural gas for cogeneration islikely to be competitive with oil, and gas-firedcogenerators usually will be technically and eco-nomically attractive in the same situations as oilburning systems. Moreover, gas-fired cogener-ation could provide a bridge to the developmentof gasification systems using alternative fuels.Thus, removing regulatory and tax restrictions onthe use of natural gas in cogenerators would com-plement market disincentives to oil use, by pre-senting an economically attractive alternative inthose situations where oil might otherwise befavored.

On the other hand, if gasification systems donot become commercial as soon as their devel-opers project, or if the cost of producing low- ormedium-Btu gas remains significantly higher thanthe cost of natural gas, then this strategy couldlock cogenerators into natural gas use for 10 to20 years. Moreover, if natural gas-fired cogenera-tion were given incorrect incentives, and mademore attractive than market conditions would jus-tify, this could discourage the use of non-premiumfuels (e.g., coal, biomass, wastes) and add to thedemand for natural gas. If supplies are limited,the cogenerators’ demand could increase sup-ply pressures for established gas users.

Economic Incentives for Cogeneration

Cogeneration’s market potential (the amountof cogeneration capacity that may be installedand the amount of electricity that it will pro-duce) is extremely sensitive to economic consid-erations. These include the rates for utility pur-chases of cogenerated power, tax credits andleasing provisions, and other policy measuresthat either reduce the capital cost or offset theoperating cost of cogeneration systems. At pres-ent, however, the continued availability of exist-ing policy initiatives is in doubt.

A recent court decision vacated the Federal En-ergy Regulatory Commission (FERC) regulationsimplementing PURPA that called for utility pur-chases of cogenerated power at rates equal to 100percent of the incremental cost saved by the util-ity by not generating the power itself or purchas-ing it from the grid (termed the utility’s “avoidedcost”). The court heId that FERC had not ade-quately justified rates based on the full avoidedcost when a lower rate would still compensatemost cogenerators adequately while sharing theeconomic benefits of cogeneration with the util-ity’s ratepayers. In order for the ratepayers toshare in any cost benefits of cogeneration, lessthan full avoided costs would have to be paid tothe cogenerator, with the difference going to ratereductions, or the utility would have to own thecogenerator. The full avoided cost rates remainin effect pending final resolution in the case (in-cluding appeals and revision of the regulations,if necessary), but uncertainty about the long-termpurchase rates is substantially discouraging co-generation except in those cases where State leg-islatures or regulatory commissions have insti-tuted full avoided cost rates on their own initia-tive.

A second source of uncertainty is the 1982 ex-piration date for the special energy tax credit. Theavailability of this credit often can make or breakthe economic feasibility of cogeneration projects(and other alternate energy systems). Due to thecurrently high interest rates and the promise ofimproved technologies now under developmentor demonstration, many potential cogeneratorswould prefer to wait several years before mak-ing their investment. The continued availabilityof the energy tax credit (perhaps through 1990)could help to ensure that those investmentswould be made, while an earlier expiration datemight encourage the installation of less efficientexisting technologies.

Finally, if the Government wanted to maximizecogeneration’s market potential, then policiesthat substantially reduce capital costs might beimplemented. With the current high interestrates, debt financing—the primary mode of fi-nancing for potential cogenerators—is unattrac-tive or unavailable. Therefore, subsidies that low-er interest rates and extend loan terms may bemore attractive than tax credits.

Utility Ownership

Electric utility ownership could substantiallyincrease cogeneration’s market potential. Powerproduction is electric utilities’ primary businessand they would thus not be subject to many ofthe qualms of industrial or commercial concernsthat are unaccustomed to producing electricpower or that place higher priorities on invest-ments in process equipment. Some utilities mayrequire a lower return on their investment thanother types of investors, and a cogeneration proj-ect that may only be marginally economic for anindustrial or commercial firm could be attractiveto a utility. Moreover, utility ownership couldallay concerns about competition from cogener-ators.

Although there are no legal restrictions on utili-ty ownership of cogenerating capacity, such own-ership is at a competitive disadvantage becausecogenerators in which electric utilities or utilityholding companies own more than a 50-percentequity interest do not qualify for the economicand regulatory incentives under PURPA, and be-cause public utility property is not eligible for theenergy tax credit. Removing these disincentiveswould place utilities in an equal (at least) posi-tion with other investors with regard to cogenera-tion, and could substantially increase the produc-tion of cogenerated electricity.

However, full utility ownership under PURPAraises concerns about the possible effects of suchownership on competition and on utility obliga-tions to minimize electricity generation costs. Util-ities could favor their own (or their subsidiaries’)projects in contracting for cogeneration capaci-ty. They also might favor a few major establishedsuppliers of cogeneration equipment, leading tothe possibility of adverse effects on small businessand the development of innovative technologies.Moreover, if a utility is paying its subsidiary forcogenerated electricity based on the utility’savoided cost of generation or purchases from thegrid, then the utility has few incentives to reduceits marginal costs, because to do so would be toreduce the subsidiaries’ rate of return and profit-ability. while these concerns about utility

ownership under PURPA are real, they can beallayed through carefully drafted legislation orregulations, or through careful State review ofutility ownership schemes. If these cautionarymeasures are taken, the benefits of utility own-ership probably would outweigh the potentialfor anti-competitive and economic costs.

interconnection Requirements

The requirements for interconnecting and inte-grating cogenerators with utility transmission anddistribution systems have become both technicaland institutional issues. There are technical issuesbecause of the wide variability among States andutilities on the type and quality of equipment thatis necessary to regulate system power quality,protect the safety of utility employees, maintaincontrol over system operations, meter cogenera-tors’ electricity production and consumptionproperly, and prevent damage to utilities’ andother customers’ equipment. Few guidelines existfor interconnection needs, but the equipment re-quired can add enough to a project’s costs tomake cogeneration economically infeasible. Asa result, a high priority should be placed on thepreparation of guidelines for utilities and Statecommissions to follow in setting interconnectionrequirements.

Second, utilities’ legal obligation to intercon-nect is unclear. FERC regulations implementingPURPA established a general obligation to inter-connect in order to carry out the statutory man-date that utilities must purchase power from andsell it to cogenerators. However, PURPA alsoamended the Federal Power Act to provide forfull evidentiary hearings on interconnectionsupon the request of a utility or a qualifying co-generator. The U.S. Court of Appeals recentlyruled that the Federal Power Act procedure wasthe valid one. Therefore, if a utility is not willingto interconnect, the cogenerator must go throughthe costly and time-consuming process of sucha hearing. Furthermore, most of the showings re-quired of the petitioner in such a hearing wouldbe extremely difficult and expensive for a poten-

tial cogenerator to make. This issue probably canonly be resolved through a congressional amend-ment to PURPA that specifies utilities’ obligationto interconnect with cogenerators (and smallpower producers) and leaves resolution of techni-cal and cost issues to State utility commissions.

Air Quality Considerations

Proponents of cogeneration have argued thatair pollution control regulations unnecessarilyrestrict the deployment of cogenerators. Theysuggest that cogenerators be given special treat-ment that accounts for their increased fuel effi-ciency and their displacement of emissions fromcentrally generated electricity. Proposed changesinclude emission standards that are tied to theamount of energy output rather than the fuel in-put, or separate and more lenient emissions lim-itations for cogenerators; and less strict newsource review procedures for cogenerators underprevention of significant deterioration and non-attainment area provisions of the Clean Air Act(e.g., by allowing an automatic offset for reduc-tions in powerplant and boiler emissions).

Although these changes would remove somedisincentives to cogeneration, OTA found thatin many situations there is no public health orenvironmental justification for automaticallygranting cogenerators relief from air quality re-quirements. A potentially more productive alter-native would be to favor situations where cogen-erators can demonstrate that they will have a pos-itive net impact on air quality. In those cases,relief from regulatory requirements could begranted on a case-by-case basis. Review of indi-vidual cases will be especially important in ur-

CHAPTER 11.

2.

3.

Edison Electric Institute, Statistic/ Yearkok of theE/ectric Uti/ity /ncfustry: 1980 (Washington, D. C.:Edison Electric Institute, 1981).General Energy Associates, /ndustria/ CogenerationPotential: Targeting of Opportunities at the PlantSite (Washington, D. C.: U.S. Department of Energy,1982).Historica/ Statistics of the United States, Co/onia/Times to 1970: Part2 (Washington, D. C.: U.S. Gov-ernment Printing Office, 1976).

ban areas where small internal combustion en-gine cogenerators that are not regulated underthe Clean Air Act could have significant adverseimpacts on air quality.

Research and Development

The most promising cogeneration applicationsare those that can use fuels other than oil andthat can produce significant amounts of electrici-ty. Of the currently available technologies (thatare widely applicable), only steam turbines canaccommodate solid fuels. But steam turbineshave a low E/S ratio. Higher E/S ratio technologiesare available, but can only use oil or gas. There-fore, research and development efforts shouldconcentrate on demonstrating high E/S cogener-ators that can burn solid fuels cleanly, and onadvanced combustion systems such as fluidizedbeds that can be used in conjunction with a co-generator. Because many potential cogeneratorswill not be able to burn solid fuels directly (dueto site, environmental, or resource availabilitylimitations), special attention also should be paidto the development and demonstration of gasi-fiers that would convert solid fuels to syntheticgas onsite, or for transport to the cogenerationsite. Gasifiers would allow available cogenera-tion technologies to be installed now and usenatural gas (currently relatively abundant) untilsynthetic gas becomes available.

Research also should be directed at removingthe remaining technical uncertainties in intercon-nection, developing lower cost pollution controltechnologies for small generators, and improv-ing coal transportation and handling in urbanareas.

4. Resource Planning Associates, Cogeneration: Tech-nical Concepts, Trends, Prospects (Washington,D. C.: U.S. Department of Energy, DOE-FFU-1 703,1978).

5. TRW Energy and Environmental Division, Ana/ysisof Existing lnclustrial Cogeneration Capacity (~ash-ington, D. C.: U.S. Department of Energy, 1982).

Chapter 2

Issues and Findings

Contents

PageWhat ls Cogeneration? . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25

Will Cogeneration Save Oil? . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25

Under What Circumstances Are Available Cogeneration Technologies Attractive?.. . . . 28

What Are Some Promising Future Cogeneration Technologies? . . . . . . . . . . . . . . . . . . . . 29

Will Cogeneration Be Competitive With Conventional Thermal andElectric Energy Systems?. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31

What Are the lndustrial Cogeneration Opportunities?. . . . . . . . . . . . . . . . . . . . . . . . . . . . 32

What Are the Opportunities for Cogeneration uncommercial Buildings? . . . . . . . . . . . . 34

What Are the interconnection Requirements for Cogeneration? . . . . . . . . . . . . . . . . . . . 35

Who Will Own Cogenerators? . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38

What Are the Potential Effects of the PURPA lncentives?. . . . . . . . . . . . . . . . . . . . . . . . . 39

What Are the Potential Economic impacts of Cogeneration on Electric Utilities?. . . . . . 40

What Are the Environmental impacts of Cogeneration? . . . . . . . . . . . . . . . . . . . . . . . . . . 43

Chapter p references. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 45

Tables

Table No. Page3. interconnection Costs for Three Typical Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 374. Considerations in Determining Avoided Costs Under PURPA . . . . . . . . . . . . . . . . . . . 415. Effect of Cogeneration Characteristics on Air Quality . . . . . . . . . . . . . . . . . . . . . . . . . . 43

Figures

Figure No. Page3. illustrations of Topping Cycle Cogeneration Systems . . . . . . . . . . . . . . . . . . . . . . . . . . 264. Schematic of a Bottoming Cycle Cogenerator . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 275. Schematic of a Combined-Cycle Cogenerator . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 296. Fuel Cell Operation. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 307. Schematic of a Stirling Engine . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31

Chapter 2

Issues and Findings

WHAT IS COGENERATION?Cogeneration is the combined production of

two forms of energy—electric or mechanicalpower plus useful thermal energy–in one tech-nological process. The electric power producedby a cogenerator can be used onsite or dis-tributed through the utility grid, or both. The ther-mal energy usually is used onsite for industrialprocess heat or steam, space conditioning, and/orhot water. But, if the cogeneration system pro-duces more useful thermal energy than is neededonsite, distribution of the excess to nearby facil-ities can substantially improve the cogenerator’seconomics and energy efficiency.

The total amount of fuel needed to produceboth electricity and thermal energy in a cogener-ator is less than the total fuel needed to producethe same amount of electric and thermal energyin separate technologies (e.g., an electric utilitygenerating plant and an industrial boiler). It isprimarily this greater fuel use efficiency that has

created a resurgence of interest in cogenerationsystems. However, cogeneration also can be at-tractive as a means of adding electric generatingcapacity rapidly at sites where thermal energyalready is produced.

Cogeneration technologies are termed “top-ping cycles” if the electric or mechanical poweris produced first, and the thermal energy ex-hausted from power production is then capturedand used (see fig. 3). “Bottoming cycle” cogener-ation systems produce high-temperature thermalenergy first (e.g., for steel reheating or aluminumremelting), and then recover the waste heat foruse in generating electric or mechanical powerplus additional, lower temperature thermal ener-gy (see fig. 4). Topping cycle cogenerators wouldbe used in residential, commercial, and most in-dustrial applications, while bottoming cycle appli-cations would most likely arise from high-temper-ature industrial processes.

WILL COGENERATION SAVE OIL?Cogeneration is widely acclaimed as a conser-

vation technology because it uses less fuel (meas-ured in Btu equivalents) to generate a givenamount of electricity and useful thermal energythan separate conventional energy systems (e.g.,a powerplant and an industrial boiler; see fig. 2).However, just because cogeneration is more fuelefficient does not mean that it will automaticallyreduce oil consumption.

Whether cogeneration will save oil (or naturalgas, or any other particular fuel) depends on thefuel burned by a cogenerator and the fuel usedin the separate electric and thermal energy pro-ducing systems the cogenerator displaces. ifboth of these separate systems would burn oil,and continue to burn oil for most of the op-erating life of an oil-fired cogenerator that re-placed them, then an oil burning cogeneratorwould reduce total oil consumption. This sav-

ings can range from a 15-percent reduction in oiluse when a steam turbine cogenerator is substi-tuted for a steam electric powerplant and aseparate low-pressure steam boiler, to a 34 per-cent savings if a diesel cogenerator that converts38 percent of the fuel energy to electricity (30 per-cent to useful thermal energy) replaces separateoil-fired powerplants and furnaces.

However, if a cogenerator that will burn oilduring most of its useful life replaces either apowerplant or a conventional furnace or boilerthat uses a different fuel (e.g., coal, wood), orthat plans to convert to a different fuel duringthe useful life of the cogenerator, then oil burn-ing cogeneration will actually increase total sys-tem oil use. Therefore, cogeneration will onlysave oil if it uses an alternate fuel itself (e.g., coal),or if it replaces separate electric and thermal ener-gy systems that use (and will continue to use) oil.

25


Figure 3.—illustrations of Topping Cycle Cogeneration Systems

Combustion turbine

Air and

ir

High-t

Diesel engine

Air and

Steam turbine

Diesel engine

f u e l - - - > ity

Jacket cooling

steam

Heat-recovery boiier

m

Steam generator (boiler)

SOURCE: Resource Plannlng Associates, Cogeneration: Technical Concepts, Trends, Prospects (Washlngton, D. C.: U.S. Department of Energy, DOE-FFU-1703,1978).

Ch. 2—issues and Findings . 27

(w

Figure 4.—Schematic of a Bottoming Cycle Cogenerator

Exhaust

r

t out

Regenerator

SOURCE: Resource Planning Associates, Cogeneration: Technical Concepts, Trends, Prospects (Washington, D. C.: U.S. Department of Energy, DOE-FFU-1703, 1978).

This finding is especially important for threereasons. First, most commercially available co-generation technologies require clean premiumfuels such as oil or natural gas (see ch. 4). Steamturbine cogenerators can burn coal or other alter-nate fuels such as biomass or solid waste, but maybe prevented from doing so due to site or envi-ronmental considerations. Advanced cogenera-tors that can use alternate fuels may not be avail-able for several years. Second, although industrialprocesses and, to a lesser extent, electric utilities,are heavily dependent on oil and natural gas,both groups already plan to reduce their use ofthese fuels either through conservation or con-version to alternate fuels or both. Third, althoughthe Powerplant and Industrial Fuel Use Act of1978 (FUA) prohibits the use of oil and naturalgas in new powerplants and boilers, cogeneratorsare exempt from these prohibitions if less thanhalf of their annual electric output is sold or ex-changed for resale, or if they are relatively small(less than about 10 megawatts per unit (MW/unit)

or 25 MW/site, assuming a 10,000 Btu per kilo-watthour (Btu/kWh) heat rate), or if they candemonstrate a net savings of oil or gas.

When these three considerations are combinedwith economic conditions that favor cogenera-tion (e.g., high retail electricity rates), the com-bination could outweigh market considerationsand result in oil-fired cogeneration that wouldlock industrial or commercial cogenerators intopremium fuel use for 10 to 20 years or more. Onthe other hand, if oil cogeneration is used onlywhere premium fuel savings are sure to result(i.e., where both the electric and thermal systemsthe cogenerator replaces would continue to burnoil for most of the operating life of the cogener-ator), or where conversion to alternate fuels willbe possible in the near term (e.g., a dual-fuel sys-tem that can convert from oil to synthetic gaswhen gasification technology is improved), theneven oil-fired cogeneration can pose significantoil savings.


UNDER WHAT CIRCUMSTANCES ARE AVAILABLE COGENERATIONTECHNOLOGIES ATTRACTIVE?

The commercially available cogeneration tech-nologies described in this report include steamturbines, open-cycle combustion turbines, com-bined-cycle systems, diesels, and steam Rankinebottoming cycles. All of these technologies willprovide energy savings because their fuel efficien-cy is greater than that of the separate electric andthermal energy systems they will replace, buttheir comparative technical, economic, and fueluse advantages vary (see table 1 and ch. 4; fora review of their relative environmental advan-tages, see, “What Are the Environmental Impactsof Cogeneration?”).

A steam turbine topping cycle cogenerator (seefig. 3) produces thermal energy at moderate tem-peratures and pressures that are suitable for manyindustrial applications that do not need high-tem-perature heat. Available steam turbines have arelatively high overall efficiency, but their ratioof electricity generated to thermal energy pro-duced (electricity-to-steam (E/S) ratio) is relativelylow. Therefore, steam turbine cogenerators are usu-ally not appropriate where large electricity require-ments are paramount, such as the need to pro-vide power to the grid to improve economic feasi-bility. In addition, steam turbines can have rel-atively high unit costs, longer startup times andinstallation Ieadtimes than other available cogen-erators, and more stringent personnel require-ments specified by boiler codes. On the otherhand, steam turbines are extremely reliable, andcan use a wider range of fuels more easily thanother cogeneration technologies, including coal,biomass, and solid wastes, as well as coal-derivedliquids and gases when they become available.

Open-cycle combustion turbine topping cycles(see fig. 3) have a higher E/S ratio and producehigher temperature steam than steam turbines.Therefore, combustion turbines can meet theelectric and thermal needs of more types of in-dustries and are more likely to produce excesselectricity that may be exported to the grid. Com-bustion turbines’ unit cost and construction timeare relatively low while their reliability is compar-able to that of steam turbines. Combustion tur-

bines are available in a wider range of unit sizesthan steam turbines, and the lower capacity units(i.e., below 7 MW) may be attractive for commer-cial facilities (such as shopping centers, apart-ments, hotels) because they are small in size andcan be operated remotely. Combustion turbinesalso are well suited to arid climates because theyrequire no cooling water. Finally, although open-cycle combustion turbines cannot now use solidfuels such as coal or wood directly, they will beable to use synthetic gas or liquid fuels derivedfrom coal or biomass, and units using pulverizedwood directly are under development.

Combined-cycle cogenerators (combinedsteam turbine and combustion turbine systems;see fig. 5) increase electric power output at theexpense of recoverable heat. They have a higherE/S ratio than either a steam or combustion tur-bine alone, and thus will be most attractive insituations where electricity requirements are rel-atively high, or where electric power can be dis-tributed to the grid economically. Their unit ca-pacity also tends to be greater than either of theseparate turbine systems. Currently availablecombined-cycle systems require too much spacefor most commercial applications, but they shouldbe well suited to larger industrial facilities. Theirunit cost and installation Ieadtime are higher thancombustion turbines’, but comparable to medi-um- or large-size steam turbines. Furthermore,while combined cycles’ availability is lower thaneither system alone, their overall fuel efficiencyis higher. Finally, combined cycles can use thefull range of fuels and will be readily adaptableto fluidized bed combustion systems.

Diesel cogenerators (see fig. 3) have a higherE/S ratio than the technologies described above,and thus will be very attractive for facilities withhigh electricity demand but low thermal energyneeds (i.e., most commercial building applica-tions and many smaller industries), or where elec-tricity can be distributed to the grid economically.Diesels’ relatively high efficiency, low cost, shortinstallation Ieadtime, long service lifetime, andestablished service infrastructure all contributeto their attractiveness. However, diesels also can

Ch. Z—Issues and Findings ● 29

Figure 5.—Schematic of a Combined-Cycle Cogenerator

Mechanic~inefficiencyGenerator inefficiency

SOURCE: Resource Planning Associates, Cogeneration: Technical Concepts, Trends, prospects (Washington, D. C.: U.S. Department of Energy, DOE-FFU-1703, 1978).

have high maintenance costs and may be lessacceptable environmentally due to their poten-tially high nitrogen oxide and particulate emis-sions. In addition, currently available diesel tech-nologies must burn oil or gas (some are dual-fueled), although they will be able to use synthet-ic fuels. Diesels capable of burning powderedcoal or coal slurries are under development, butit is unclear whether they will be economicallycompetitive with other types of cogenerators.

Rankine steam bottoming cycles (see fig. 4) areconceptually different from the technologies sum-marized above in that high-temperature processheat is produced first, then waste heat from the

thermal process is used to produce electric ormechanical power plus additional lower tempera-ture thermal energy. Because waste heat is usedto generate electricity, Rankine bottoming cyclescan present even greater fuel savings than top-ping cycle cogenerators. The cost, average an-nual availability, and construction Ieadtime ofRankine steam bottoming cycles are comparableto steam turbines, while their expected servicelife is approximately equal to combustion tur-bines, combined cycles, and diesels. Unit capac-ity, however, often is smaller than other cogener-ation systems. Rankine steam bottoming cyclestypically are considered for industrial applicationswith very high-temperature heat needs.

WHAT ARE SOME PROMISING FUTURECOGENERATION TECHNOLOGIES?

Current research and development efforts on cumstances Are Available Cogeneration Technol-cogeneration are directed toward both improve- ogies Attractive?”) and the development of newments in existing systems (see, “Under W/hat Cir- technologies. The primary concerns in these ef-

30 ● INdustrial and Commercial Cogeneration

forts include the ability to burn fuels other thanoil and gas (e.g., coal, biomass, solid waste), im-proved fuel efficiency, increased electrical out-put, and lower capital and operating costs (seech. 4).

Advanced steam turbine cogenerators withhigher steam pressures and temperatures, andthus greater electric generating efficiency, shouldbe available between 1985 and 1990. Much ofthe research on steam turbines is aimed at im-proving the efficiency of smaller systems (less than7 MW), while reducing their cost. Similarly, re-search on open-cycle combustion turbines is di-rected toward increasing efficiency throughhigher inlet temperatures by improving turbineblade cooling or making materials changes inblade composition. Materials changes also wouldimprove the anticorrosive properties of turbineblades and thus would allow combustion turbinesto use solid fuels (municipal solid waste, pulver-ized coal, etc.). However, as with steam turbines,capital and operating costs for advanced com-bustion turbines are likely to be slightly higherthan present costs. Improvements in combined-cycle systems include the advances in combus-tion turbines, as well as the development ofsmaller combined cycles with a wider range ofpotential applications. Finally, advanced dieselcogenerators are being developed that use coal-derived fuels, and have a much greater poweroutput, as well as those for which all the recov-ered thermal energy could be high-quality steam.Each of these improvements in the diesel cogen-erator should be commercially available by 1990,but not all in the same system.

Advanced cogeneration technologies that arenot now available commercially include closed-cycle combustion turbines, organic Rankine bot-toming cycles, fuel cells, and Stirling engines (seetable 1 and ch. 4). (Solar cogenerators, such asthe therm ionic topping system, are not discussedin this report.)

Closed-cycle, externally fired combustion tur-bines are not available commercially in theUnited States but are well developed in Europeand Japan. These systems are potentially very at-tractive because they can use a wide variety offuels (including coal), have a relatively high effi-

ciency and E/S ratio, and should be priced com-petitively with other topping cycle cogenerators.They will be attractive primarily in larger industrialand utility applications.

Organic Rankine bottoming cycles evaporateorganic working fluids (e.g., toluene) to produceshaft power, and can operate efficiently at lowertemperatures and in smaller sizes (i.e., 2 kW to2 MW) than steam bottoming cycles. Becausethey use lower temperature heat, they can beadapted to a wide variety of heat sources, includ-ing solar, geothermal, and industrial waste heat,or engine exhausts. However, they currently re-quire more maintenance than most topping cy-cles, and further development and demonstra-tion are necessary before the organic Rankinebottoming cycle can be considered a “mature”technology.

Fuel cells (electrochemical devices that con-vert the chemical energy of a fuel directly intoelectricity with no intermediate combustion cycle—see fig. 6) are potentially attractive cogeneratorsdue to their modular construction, good electri-cal-load-following capabilities, automatic opera-tion, ability to use coal-derived fuels, and lowpollutant emissions. In addition, fuel cells couldbe adapted to a wide range of sizes and applica-tions, from small (40 to 500 kW) residential andcommercial systems to larger industrial and utilityplants (5 to 25 MW). Although fuel cell demon-

Figure 6.—Fuei Cell

Hydrogen-rich gas and C02

from shift converter

1Porousanode

( - )

Electrolyte(phosphoric

acid)

Porouscathode

(+)

Operation

C02 and unreactedhydrogen

Ch. 2—Issues and Findings ● 31

stration plants are under construction, commer-cial readiness is still at least 5 years away. Theprimary development concerns include some-what high capital costs and short service life.

Finally, Stirling engines (see fig. 7) could offeran attractive alternative to available topping cy-cles because of their ability to use coal and othersolid fuels, their high thermal and part-load effi-ciency, and their low emissions, noise, and vibra-tions. Stirling engines also could be used as com-ponents of solar energy systems or as adjunctsto fluidized bed combustors, nuclear reactors, orother conversion technologies. Current researchefforts are directed toward improved efficiencyand solid fuel combustion characteristics, as wellas lower capital costs, before Stirling engines canbe considered commercial. Because they pro-duce relatively low-temperature recoverableheat, Stirling engines will be most attractive forwater heating or in facilities with relatively smallprocess heat requirements.

In addition to the cogeneration technologiesreviewed above, two types of advanced combus-tion systems may be attractive for increasing co-generators’ fuel flexibility: gasifiers and fluidizedbed combustors. Gasifiers would convert coal,pet coke, or other solid fuels to medium-Btu gas(about 300 Btu/standard cubic foot) for distribu-tion to cogenerators (or other facilities) withinabout a 100-mile radius. Gasification could cen-tralize the use of solid fuels, and thus eliminatecogenerators’ need for coal storage and handlingfacilities. However, gasification is not yet a prov-en technology, although both small- and large-scale systems are being demonstrated. Whethersuch a scheme will be successful is heavily de-

Figure 7.—Schematic of a Stirling Engine

duct

SOURCE: Application of Solar Technology to Today’s Energy Needs (Waehlngton,D. C.: U.S. Congress, Office of Technology Assessment, OTA-E86, June1978).

pendent on the capital costs, which are still highlyuncertain. Fluidized bed combustors can accom-modate a wide range of solid fuels, and operateat a lower temperature and pose fewer environ-mental and operating problems than convention-al boilers. Fluidized beds can be adapted to fireseveral different types of cogeneration technol-ogies. Atmospheric fluidized bed systems couldbe used with steam or combustion turbines orcombined cycles, while pressurized systems coulddrive combustion turbines or combined cycles.Fluidized bed combustors are now being demon-strated and could become commercial within afew years.

WILL COGENERATION BE COMPETITIVE WITH CONVENTIONALTHERMAL AND ELECTRIC ENERGY SYSTEMS?

Cogeneration is most likely to be competitive oil-fired cogeneration will only save oil in a

with conventional separate electric and thermal few circumstances (see, “Will Cogeneration Saveenergy technologies when it can use relatively oil?”). Moreover, the price gap between oil/gasinexpensive, plentiful fuels, and where there are and other fuels is likely to become wider overlarge thermal energy needs or it can meet on- time. Therefore, cogenerators will have to usesite energy needs while supplying significant relatively inexpensive and plentiful fuels (suchamounts of electricity to the utility grid. as coal, biomass, or solid wastes) in order to be


economically competitive with utility generatingcapacity over the long run (10 to 20 years andbeyond). Alternatively, if the utility’s avoided costis determined by the price of oil, or if the utilityis primarily dependent on oil-fired capacity, thennatural gas may remain economically attractiveas a cogeneration fuel for several years. In theshort term, it is possible that cogenerators maybe able to rely on natural gas as a transition meas-ure until synthetic gas from coal or biomass be-comes widely available at a competitive price.However, if gasifier technology or planned ad-vances in the fuel flexibility of cogeneration tech-nologies are not available as soon as expected,or synthetic gas is not competitive in price withnatural gas, this strategy could lock cogeneratorsinto premium fuel use for many years.

For cogeneration to be economically attrac-tive, there usually must also be substantial ther-mal loads. Sites with low loads (e.g., less than50,000 lb/hr of steam) due to conservation meas-ures or limited process needs, or with fluctuatingloads, generally would not be economically com-petitive with conventional steam boilers and util-ity-supplied electricity. Thus, commercial build-ings are likely to have a low potential forcogeneration because of their very low thermalload factors. In some cases, however, cogenera-tors can be “undersized” and operated at a highcapacity factor to meet the base thermal load,with conventional boilers or furnaces used whennecessary to meet the remaining thermal demand(see, “What Are the Opportunities for Cogenera-tion in Commercial Buildings?”).

Finally, cogeneration’s ability to meet onsitethermal and electrical needs, or to meet the

thermal needs and supply significant amountsof power to the utility grid, will be a major deter-minant of its economic competitiveness. In theregions where electric utilities have substantialamounts of generating capacity fueled by oil ornatural gas, or where demand growth is signifi-cant (primarily the Northeastern States and Cali-fornia, and to a lesser extent the South Atlanticand West South-Central States), cogeneration willbe more attractive when it can supply significantamounts of electricity to the grid (see, “What Arethe Potential Effects of the PURPA Incentives?”).Alternatively, if the utility has substantial excesscapacity or primarily uses coal or other non-premium fuels, and avoided costs are low or retailelectricity rates are high, a cogenerator’s eco-nomic competitiveness will depend primarily onits ability to reduce onsite energy costs.

These determinants of cogeneration’s econom-ic competitiveness will affect the choice of cogen-eration technologies. Of the technologies thatare commercially available, only the steam tur-bine topping and Rankine cycle bottoming sys-tems can use fuels other than oil/gas. However,bottoming cycles usually are limited to special-ized applications that require high-temperatureheat, while steam turbines have low E/S ratios(see, “Under What Circumstances Are AvailableCogeneration Technologies Attractive?”). Systemswith higher E/S ratios that will be able to use alter-nate fuels are under development or demonstra-tion, as are advanced combustion technologiessuch as fluidized beds and gasifiers, and shouldbe available commercially by the mid to late1980’s (see, “What Are Some Promising FutureCogeneration Technologies?”).

WHAT ARE THE INDUSTRIAL COGENERATION OPPORTUNITIES?Cogeneration of electricity and thermal energy at which the thermal load is sufficient to justify

for industrial processes is a proven concept, an investment in a cogeneration system) is high—with approximately 9,000 to 15,000 MW of co- perhaps as much as 200 gigawatts (GW), or aboutgeneration capacity in operation at industrial 32 percent of current U.S. generating capacity.sites throughout the United States (see table However, the market potential (the amount for2), and at least 3,300 MW in the planning stage which an investment is likely to be made) is muchor under construction. The technical potential lower due to economic and institutional consid-for industrial cogeneration (the number of sites erations.

●

●

●

●

versions of existing process technologiesnow under development will have greaterfuel flexibility, higher fuel efficiency, andhigher electricity output.Whether cogeneration retrofits are feasibleor new plants will be built: For instance,petroleum refineries are well suited to cogen-eration, and some existing refineries couldbe upgraded, resulting in the production oflow-Btu gas suitable for onsite cogeneration.But, few new refineries are likely to be builtexcept in areas such as California, which hasspecial requirements related to enhanced oilrecovery.Whether a plant’s operating pattern makescogeneration economic: Many food process-ing plants operate only during harvest sea-son, and the resulting low capacity factormay make cogeneration economically infea-sible. However, the food processing seasonoften overlaps the hottest months when irri-gation and air-conditioning loads contributeto peak demands on electric systems in ruralareas, the seasonal price for utility generatedpower is often very high and/or its reliabilityis low. As a result, this industry’s seasonaloperating pattern can be outweighed by itspotential for lower energy costs.The availability of capital for investmentsin cogeneration: Industrial firms typically re-quire shorter payback periods for their in-vestments than cogeneration may be able toprovide, although current accelerated depre-ciation measures and investment and energytax credits can improve the payback signifi-cantly. Cogeneration also must compete foravailable capital with process equipment orother investments that improve an industry’scompetitive position (as well as with conser-vation measures, as mentioned above).Third-party or utility ownership can improvecapital availability (see, “Who Will Own Co-generators?”), as can low interest loans andother financing measures that alleviate theeffects of high interest rates and capitalshortages.Whether there is a match between a plant’sneeds and the cogenerator’s output: An in-dustry may need more or less thermal or


●

electric energy than a cogenerator provides.usually the technology will be chosen to op-timize the match between load and output,but this will not always be possible. The PubIic Utility Regulatory Policies Act (PURPA) re-quirements that electric utilities offer to buypower from and sell power to cogeneratorscan mitigate an electricity supply and de-mand mismatch, but the economics may notalways be favorable to the cogenerator (see,“What Are the Potential Effects of the PURPAIncentives?”). In some cases, industrial parkswith central cogenerators and shared energyproducts through dedicated distribution sys-tems may be an attractive solution to ther-mal and electric supply/demand mis-matches.Regulatory uncertainty and perceived risks:Doubt about the continued availability of theeconomic and regulatory incentives offeredby PURPA, the fuel use and pricing provi-sions of FUA and the Natural Gas Policy Act,and the various tax incentives for investmentin cogeneration (e.g., investment and energytax credits, accelerated cost recovery, safe

harbor leasing) can be a significant deterrentto investment in cogenerators. Similarly, un-certainty about interest costs and capitalavailability, fuel costs, investment paybackperiods, the use of solid fuels, and environ-mental regulation can be disincentives to theimplementation of cogeneration projects.

All of the above factors could lead industrialmanagers to adopt a “wait-and-see” attitude to-ward cogeneration. As a result, widespread de-ployment of industrial cogeneration capacitycould be delayed a decade or more. But the res-olution of legal and regulatory uncertainties, therapid development and demonstration of ad-vanced technologies that can burn solid fuelscleanly, and lower interest rates or innovativefinancing and ownership arrangements couldsubstantially improve industrial cogeneration’smarket potential. In addition, if natural gas pricesare seen to be lower than distillate for an ex-tended period—lo to 20 years—an industry mightdecide it is worth the investment risk if their pur-chase power rates are based on oil.

WHAT ARE THE OPPORTUNITIES FOR COGENERATIONIN COMMERCIAL BUILDINGS?

Although the opportunities for cogeneration incommercial buildings depend on the same gen-eral factors as industrial cogeneration—thermalenergy demand, availability of capital, competi-tion with conservation, capability of using non-premium fuels, etc. —there are characteristicsabout buildings that constrain cogeneration morethan in industry.

In the near term–the next 10 to 15 years–com-mercial cogeneration will be fueled predom-inantly by natural gas. Coal-fired units can beused but these will be limited because of the dif-ficulties of handling and storing coal in andaround commercial buildings. Therefore, theprincipal determinants for commercial cogener-ation for the near term will be the price andavailability of natural gas, and either the priceof electricity from central station units or theprice that utilities will pay for electricity from

cogenerators as set by their public utility commis-sions. For those regions where the latter is set ator near the price of oil-fired electricity and theutilities have oil or natural gas fueled capacity,commercial cogeneration fueled by natural gashas a promising market even if natural gas pricesshould approach those of distillate fuel oil. Theprimary advantage of commercial cogenerationin these cases is that it allows rapid developmentof new capacity to meet new demand and/or toreplace the utility’s oil-fired capacity.

Under least cost conditions, cogenerated elec-tricity will be produced and sold when it is lessexpensive than central station electricity (see,“Will Cogeneration Be Competitive With Con-ventional Thermal and Electric Energy Systems?”).Net fuel savings by cogeneration compared toseparate production of electricity and heat, how-ever, may be less than that indicated by the

Ch. 2—Issues and Findings ● 35

amount of electricity sold because of the very lowthermal load factors of commercial buildings. Themost promising arrangement for commercialbuildings probably would be to undersize thecogenerator and operate it at a high capacityfactor to meet the base thermal load, and useconventional thermal energy systems when nec-essary to meet the remaining load. This allowsa high degree of heat recovery and efficient cap-ital utilization. Alternatively, the diversity addedby using several buildings for heating loads couldgreatly increase net fuel savings. This also meansthat buildings located in regions with high ther-mal loads (about 6,000 degree days or higher peryear) will be the most attractive candidates forcogeneration.

However, in both the near and long term,commercial cogeneration will compete withconservation-especially in new buildings. Con-servation will very likely be more economic thancogeneration for most of the Nation’s buildings.Further, the more efficient a building is, the lowerits thermal demands and the less attractive cogen-eration becomes. This is particularly significantwhen capital is scarce. Utility ownership may beone way of reducing the severity of the latter con-cern (see, “Who Will Own Cogenerators?”).

For the longer term, beyond 10 years, com-mercial cogeneration ultimately must competewith new coal-fired or, possibly, nuclear capac-ity. It is unlikely that natural gas-fired cogenera-tion will be able to compete economically withnew coal-fired central station capacity—even withbyproduct credit for displacing natural gas forspace heating—unless natural gas prices stay wellbelow distillate oil. This is not likely to be the case

toward the end of the century as supplies of con-ventional natural gas diminish. Where electricitygrowth rates are high (greater than 2 percent peryear) and thermal demands are high (6,000 de-gree days or higher per year), however, naturalgas-fired commercial cogeneration, even at highgas prices, could be competitive for new interme-diate and peaking electric loads or for cases inwhich coal use is limited.

Cogeneration directly fired by coal with newtechnologies, such as fluidized bed combustion,or indirectly through low-Btu gasification andcombined-cycle systems, could compete withnew central station coal capacity (see, “What AreSome Promising Future Cogeneration Technol-ogies?”). Some current analyses indicate that thiswill be so, but the OTA analysis of synthetic fuelsfor transportation shows that there is considerableuncertainty with respect to cost of synfuels pro-duction (6). Other promising possibilities arecombined-cycle systems fired by biomass or solidwaste gasifiers. These new technologies do noteliminate the coal or biomass handling problem,however, which will still act to inhibit cogener-ation.

Finally, environmental considerations are like-ly to be more important for commercial build-ings than for other cogeneration applications.This is due in part to the potential for increasedemissions with the technologies that are mostsuited to commercial building applications, andin part to the inherent characteristics of the urbanenvironment (e.g., proximity of buildings to eachother, urban meteorology; see, “What Are theEnvironmental Impacts of Cogeneration?”).

WHAT ARE THE INTERCONNECTION REQUIREMENTSFOR COGENERATION?

In the past, electric utilities and the agencies into the grid. These “two-way” power flows havethat regulate them have only been concerned raised concerns about the technical and safetywith power flows from the central grid to cus- aspects of interconnection and integration withtomers, or from one utility to another. However, the grid, about liability for any damage that maythe economic and other incentives offered to co- result from improper interconnection, and aboutgeneration under Federal (and some States’) law the costs of the equipment needed for proper in-assume that cogenerators may feed power back terconnection and integration. OTA found that


most of the technical aspects of interconnectionand integration with the grid are relatively wellunderstood, although some electric utilities stillhave reservations. Rather, the primary issues reIated to interconnection are the costs of theequipment and the utilities’ legal obligation tointerconnect.

The technical aspects of interconnection aboutwhich utilities are concerned include maintain-ing power quality, metering cogenerators’ powerproduction and consumption, and controllingutility system operations. Power supplied by co-generators to the grid must be within certain tol-erances so that the overall utility system powerquality remains satisfactory and utilities’ and cus-tomers’ equipment will function properly and notbe damaged. In order to maintain power quality,grid-connected cogenerators may need capaci-tors to keep voltage and current in phase, over/under relays to disconnect the generator if itsvoltage goes outside a certain range, and a dedi-cated distribution transformer to isolate voltageflicker problems. However, the power quality ef-fects of interconnected cogenerators often aretechnology- and site-specific, and not all systemswill need all of this equipment. in particular,smaller systems (under 20 kW) may have few orno adverse effects on power quality and may re-quire only limited interconnection equipment.Larger systems probably will already have dedi-cated transformers, and would only need capaci-tors to correct power factor if they use induction(as opposed to synchronous) generators.

Cogenerators’ power production and con-sumption must be metered accurately in orderto collect data for better understanding their con-tribution to electric system loads, and thus for de-termining how to price buyback and backuppower. Two standard watthour meters can beused, with one operating normally to measureelectricity consumption and the other runningbackwards to indicate production. Alternatively,more advanced meters are available that indicatenot only kilowatthours used/produced, but alsopower factor correction and time-of-use. Al-though an advanced meter provides more usefuldata, it also costs about five times more than twostandard watthour meters. Whether cogener-ators are given a choice between standard and

advanced meters and, if not, whether the utilityor the cogenerator pays for the advanced meter,varies among utilities.

Utilities also are concerned about cogenerators’effects on their ability to control utility systemsoperations, including the possibility that largenumbers of cogenerators (or small power produc-ers) would overload system dispatch capabilities,and would contribute to unstable power systems.Although very large cogenerators might be dis-patched by a central utility control center (andthus require connection via expensive telemetryequipment), most utilities will treat cogeneratorsas “negative loads” by subtracting the power pro-duced by the dispersed generators from total sys-tem demand, and then dispatching the utility’scapacity to meet the reduced demand. Studiesof such negative load treatment indicate that itshould work well where the total capacity of thecogenerators is limited compared to the overallsystem capacity. However, additional researchis needed on the effects of large numbers ofcogenerators on system stability. The primaryconcern with a significant system penetration ofcogenerators is their ability to remain synchro-nized with the system following a disturbance.

Without proper interconnection measures,large numbers of cogenerators also might posehazards to worker safety during repairs to trans-mission and distribution lines. First, dispersedgenerators will need to locate their disconnectswitches in specified areas in order to simplify lineworkers’ disconnect procedures. Second, induc-tion (and, very occasionally, synchronous) gen-erators must guard against self-excitation eitherby using voltage and frequency relays and auto-matic disconnect circuit breakers, or by locatingtheir power-factor correcting capacitors wherethey will be disconnected with the cogeneratoror where they can be isolated easily by lineworkers. Therefore, while proper interconnec-tion must be ensured in order to protect utilityworkers’ safety, none of the necessary precau-tions is difficult to implement.

The cogenerator usually is liable for accidentsor damage to equipment resulting from improperinterconnection or operation. The utility may in-clude the cost of insurance against such mishaps

Ch. 2—Issues and Findings . 37

in the cogenerator’s regular billing, or liability(and adequate insurance to cover it) may be acondition of the contract between the utility andcogenerator. However, in some cases, require-ments for both insurance and protective equip-ment may be redundant and place an excessivecost burden on the cogenerator.

The cost of interconnection varies widely de-pending on the size and type of cogenerator,the equipment already in place, and the utility’sor State regulatory commission’s requirements.Few guidelines have been published (althoughseveral are being prepared) and some utilities orcommissions may require more equipment thandescribed above in order to provide extra pro-tection for their system and their other customers.In addition, the quality of equipment required (in-dustrial or utility grade) can affect the cost sub-stantially. Most utility engineers agree that the lessexpensive industrial grade should be adequatefor smaller cogenerators, but specifications of thecutoff range from 200 to 1,000 kW. Finally, costswill depend on the amount of equipment that isalready in place (e.g., dedicated transformers)and on the adequacy of existing distribution lines.

Based on published studies, OTA estimated twosets of interconnection costs for three sizes ofcogeneration systems: a “base case” that assumes

that much of the equipment is already in placeor not required (e.g., capacitors, dedicated trans-formers, protective relays), and a “worst case”that assumes this equipment must be purchased(see table 3). Most of the cost difference betweenthe two cases results from the addition of a dedi-cated transformer, and from the use of more ex-pensive relays and other protective devices.Moreover, these estimates indicate that there aresignificant economies of scale in interconnectioncosts.

The Federal Energy Regulatory Commission’s(FERC) rules implementing section 210 of PURPAoriginally specified that “any electric utility shallmake such interconnections as may be necessaryto accomplish purchases or sales” of cogeneratedpower. However, this rule recently was over-turned by the U.S. Court of Appeals on thegrounds that it is inconsistent with other parts ofPURPA that provide for individual FERC ordersrequiring interconnection after the opportunityfor a full evidentiary hearing in accordance withthe Federal Power Act. Thus, if cogenerators can-not get a utility to agree to interconnect withthem, they will have to meet the multiple strin-gent legislative tests of the Federal Power Act,which will be very difficult, expensive, and time-consuming for the cogenerator.

Table 3.—interconnection Costs for Three Typical Systems

50 kW 500 kW 5MWEquipment Best Worst Best Worst AveraaeCapacitors for power factor . . . . . . . . . . . .Voltage/frequency relays . . . . . . . . . . . . . . .Dedicated transformer. . . . . . . . . . . . . . . . .Meter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Ground fault overvoltage relay . . . . . . . . . .Manual disconnect switch . . . . . . . . . . . . .Circuit breakers . . . . . . . . . . . . . . . . . . . . . .Automatic synchronizers. . . . . . . . . . . . . . .Equipment transformers . . . . . . . . . . . . . . .Other protective relays . . . . . . . . . . . . . . . .

Total costs ($) . . . . . . . . . . . . . . . . . . . . . .Total costs ($/kW). . . . . . . . . . . . . . . . . . .

$1,000 ------- $5,000$1,000 1,000 , 1,000

— 3,900 12,50080 1,000 80 1,000

600 600 600 600300 300 1,400 1,400620 620 4,200 4,200— — 2,600 2,600600 1,100 600 1,100— 3,500 – 3,500

$2,600 $13,020 $11,080 $32,90052 260 22 66

$1,:0040,000

1,000600

3,0005,0002,6001,1003,500

$57,80012

NOTE: “-” means an optional piece of interconnection equipment that was not included in the requirements and costcalculations.

SOURCE: Office of Technology Assessment calculations based on data derived from Howard S. Geller, The /interconnectionof Cogenerators and Small Power Producers to a Utility System (Washington, D. C.: Office of the People’s Counsel,February 1982).


WHO WILL OWN COGENERATORS?Cogenerators might be owned by industrial,

commercial, or other users, by utilities, by thirdparties, or by some combination of these (jointventures). Each of these forms of ownership hasrelative advantages and disadvantages for financ-ing, taxation, operating characteristics, and regu-latory considerations.

The energy and investment tax credits, coupledwith the economic and regulatory incentives insti-tuted by PURPA, encourage private firms (e.g.,industrial facility and commercial building own-ers) to cogenerate. The PURPA requirement thatutilities purchase electricity from, and sell it to,cogenerators, and the provision that exempts co-generators from regulation as electric utilities, re-moved the primary institutional and economicobstacles to private ownership of cogenerationcapacity. PURPA also encourages the develop-ment of contractual relationships between privateowners and electric utilities—often a prerequisitefor obtaining attractive financing. Long-term con-tracts can establish a purchase rate based on theutility’s avoided costs either at the time of thecontract or at the time power is delivered to theutility, or the cogenerator and utility can negotiatea price independent of avoided cost considera-tions. PURPA incentives are augmented by pri-vate owners’ ability to earn up to 20 percent taxcredits for investment in cogenerators throughthe end of 1982, and 10 percent thereafter, whichoffers a boost to cash flow early in a project’s life.Finally, user ownership generally would providethe greatest control over the cogenerator’s energyoutput. However, industrial and commercialfirms’ willingness to invest in cogeneration willbe influenced heavily by the cost of capital (oftenhigher than the cost to utilities or many third-partyinvestors), the need to invest in process equip-ment or other items that will contribute to a firm’scompetitive position, and the availability of lesscostly conservation measures.

Investor-owned electric utilities and their sub-sidiaries are logical potential owners of cogenera-tion capacity because electricity generation istheir primary business. Ownership of cogenera-tors would enable the electric utility industry toprovide a wide range of energy supply options

and not just to facilitate their development byother parties. Moreover, utility ownership wouldreduce the potential for revenue losses from thedevelopment of generating capacity by nonutil-ities, while providing an additional revenuestream from thermal energy sales. Direct utilityownership (i.e., not utility subsidiaries) also couldresult in lower generation costs to be passed onto consumers because the avoided cost wouldbecome the lower of the cost of cogenerating orof providing electricity from alternate sources(see, “What Are the Potential Effects of thePURPA Incentives?”). In addition, utilities aremore likely to choose technologies that have highE/S ratios and that can accommodate coal orother alternate fuels (e.g., with gasifies). As aresult of all these considerations, cogeneration’smarket potential in general, and its ability tosupply large amounts of electricity to the gridin particular, are likely to be enhanced substan-tially under utility ownership.

However, current Federal policy toward cogen-eration discourages full utility ownership. First,PURPA incentives are not available to cogenera-tors in which utilities own more than a 50-percentinterest. Allowing 100-percent ownership wouldmean that utilities could earn a higher rate ofreturn on unregulated cogeneration capacity thanon their regulated central station capacity, andwould compensate utilities more fully for accept-ing the business risks of investment in generatingequipment over which they have little control(e.g., strikes, plant closings, or fuel interruptionsat the cogeneration facility). Second, utility prop-erty is not eligible for the energy tax credit, andthus utilities would not gain the same cash flowadvantages as private investors. Removing thesedisincentives would allow electric utilities to com-pete on at least an equal basis with other poten-tial owners, and may give utilities a competitiveadvantage, and thus could substantially increasecogeneration’s market potential.

However, full utility ownership raises concernsabout competition and potential economic distor-tions. Utilities could favor their own (or their sub-sidiaries’) projects through the duration or otherterms of the purchase power contract, the inter-

Ch. 2—issues and Findings . 39

connection requirements, or the priority for con-tracting. There is also a potential for utilities tocross-subsidize cogenerators through their otheroperations, making it difficult for private ownersto compete, or for utilities to favor particular mod-els and thus stifle competition among vendors.Each of these concerns can be dealt with eitherthrough carefully drafted legislation and regula-tions, or through careful review of utility owner-ship schemes by State regulatory commissions.

Publicly owned utilities also are logical candi-dates for investment in cogeneration capacity.Most publicly owned electric utilities purchaseall or some of their power from the grid. invest-ment in cogeneration capacity would enablethem to add a new source of municipal revenuewhile increasing the reliability of their power sup-ply. Moreover, many existing small municipalpowerplants are sitting idle due to their high oper-

ating costs relative to the cost of grid-suppliedpower. These small plants could be retrofitted forcogeneration and the thermal energy used tomeet local needs for such processes as grain dry-ing or ethanol production. Municipal utilities alsohave advantages in financing because they aretax-exempt and so is the interest paid on theirobligations.

Finally, joint ventures among any of the typesof owners listed above or with third-party inves-tors will be attractive, primarily due to the tax ad-vantages. If the primary investor cannot take ad-vantage of tax benefits such as credits or acceler-ated depreciation (e.g., because the investor istax-exempt or has a low tax liability), the cogen-eration equipment can be sold to another partyfor tax purposes only and leased back to the co-generator or other owner.

WHAT ARE THE POTENTIAL EFFECTS OFTHE PURPA INCENTIVES?

PURPA extends several important incentives toqualifying cogenerators (and small power produc-ers). These include exemptions from electric util-ity or utility holding company regulation underFederal and State law and from some Federal fueluse and pricing regulations; incentive rates forsales of cogenerated electricity to the grid, andnondiscriminatory rates for purchases of backupor supplementary power from the grid; and spe-cial provisions on interconnection, and on wheel-ing of cogenerated power. All of these incentivesare important because they could remove long-standing regulatory and economic barriers to on-site electricity generation. However, the rate pro-visions of PURPA are likely to have the most im-portant impacts.

PURPA requires electric utilities to purchasepower from cogenerators at a rate that does notexceed “the incremental cost to the electric utilityof alternative electric energy.” This is termed theutility’s avoided cost, and is measured by the sav-ings to the utility in not generating the power itselfor purchasing it from the grid. Avoided cost ratesare based on a cogenerators’ contribution to

power supply or peak load during daily or season-al peak demands (including the reliability of thatcontribution from the utility’s perspective); acredit for capacity and/or energy if the cogenera-tor enables the utility to defer new constructionand decrease oil/gas use; and any costs or sav-ings to the utility in transmission and distribution.

The level at which avoided cost rates will beset is uncertain at this time. The original FERCrules implementing PURPA provided for pur-chases of cogenerated power at 100 percent ofthe utility’s avoided cost. This provision was chal-lenged successfully on the grounds that PURPAestablished the full incremental cost as a rate ceil-ing, and that FERC had not adequately justifiedtheir choice of the highest permissible rate whena lower rate would share the economic benefitsof cogeneration with the utility’s ratepayers. FERCis appealing this ruling, but it may be monthsbefore a final decision is available and the regula-tions are rewritten, if necessary.

Regardless of whether the rates for purchasesof cogenerated power are set at 100 percent of


avoided costs or less than 100 percent, theserates will vary widely regionally. In most cases,only those utilities that are heavily dependent onoil or gas, have a declining reserve margin, or areanticipating relatively high peak demand growth(e.g., 3 percent per year or greater) will have suf-ficiently high avoided costs to make grid-con-nected cogeneration an attractive investment (seetable 4). Therefore, PURPA rate provisions aremost likely to be an incentive to cogeneration inthe New England States (especially Massachu-setts, Rhode Island, New Hampshire, and Con-necticut); the Mid-Atlantic States (particularlyNew York, New Jersey, and Delaware); theSouthern and South-Central States of Florida,Mississippi, Arkansas, Louisiana, and Texas; andthe State of California and the Pacific Northwest.

However, in each area, PURPA avoided costincentives may be reduced by such factors asutility plans to convert to less costly generatingcapacity, or by conservation measures that re-duce the rate of peak demand growth. Thus, ifpeak demand growth rates are not so high asthose presented in table 4, then reserve marginswould be higher than shown and avoided costswould be lower. Where avoided costs are low,a cogenerator may deliver its electricity to a moredistant utility that would have higher avoidedcosts, if the local utility agrees to transmit thepower.

PURPA economic incentives also can have im-portant impacts on electric utilities and their cus-tomers—especially if cogenerated power is pricedat 100 percent of the utility’s avoided cost. Be-

cause the avoided cost rate is based on the costto the utility of alternative electric power, theprice of electricity for non-cogenerating custom-ers should not be any higher than it would beif the utility did not make avoided cost paymentsto cogenerators (unless the State has establishedrates higher than the full avoided cost). However,neither will the price to those customers be anylower under 100-percent” avoided cost rates (ex-cept in those cases where utilities negotiate a con-tract price for cogenerated power that is less thanthe full avoided cost).

Moreover, even though utilities should treat co-generated power as part of their overall capacity,they will not earn a rate of return on cogenera-tion equipment unless they own it. Under PURPA,cogenerators that are more than 50 percent util-ity-owned are not eligible for PURPA economicand regulatory incentives. If utilities could owncogeneration capacity outright and still benefitfrom those incentives, the avoided cost couldbecome equivalent to the cost of cogeneratedelectricity or the cost of alternative power—whichever is lower. If the cost of cogeneratedpower were lower, utilities could pass this sav-ings on to their non-cogenerating customers,while still earning a higher rate of return on un-regulated cogenerators than the regulated returnon their conventional capacity. Therefore, remov-ing the ownership limits in PURPA could act asan incentive to utility investment in cogeneration,and thus increase the technology’s market poten-tial. However, utility ownership also raises con-cerns about possible anti-competitive effects (see,“Who Will Own Cogenerators?”).

WHAT ARE THE POTENTIAL ECONOMIC IMPACTSOF COGENERATION ON ELECTRIC UTILITIES?

Cogeneration could have either beneficial oradverse economic impacts on electric utilitiesand their customers, depending on the choiceof cogeneration technologies, their fuel use, andthe type of utility capacity they might displace;on who owns the cogenerators; on the systems’operating characteristics; and on the price paidby utilities for cogenerated power. These poten-tial impacts include decreased (or increased) costs

of constructing and operating electric generatingcapacity, increased (or decreased) employmentassociated with electricity supply, and a de-creased (or unchanged) rate of growth in electric-ity rates.

In order to gauge the potential magnitude ofthese economic impacts if cogeneration achieveda very large market penetration, OTA developed

Ch. 2—issues and Findings ● 41

Table 4.–Considerations in Determining Avoided Costs Under PURPA

Fuel used (percent)b Reserve margin (percent) Peak demand growth (percent)Regiona Oil Gas 1981 1990 2000 1981-1990 1991-2000Northeast . . . . . . . . . . . . . . . . .

Maine . . . . . . . . . . . . . . . . . . .New Hampshire . . . . . . . . . .Vermont. . . . . . . . . . . . . . . . .Massachusetts . . . . . . . . . . .Rhode Island . . . . . . . . . . . .Connecticut . . . . . . . . . . . . .New York. . . . . . . . . . . . . . . .

Mid-Atlantic . . . . . . . . . . . . . . .Pennsylvania. . . . . . . . . . . . .New Jersey . . . . . . . . . . . . . .Delaware . . . . . . . . . . . . . . . .

Southeast . . . . . . . . . . . . . . . . .Virginia . . . . . . . . . . . . . . . . .North Carolina . . . . . . . . . . .South Carolina. . . . . . . . . . .Georgia . . . . . . . . . . . . . . . . .Florida . . . . . . . . . . . . . . . . . .Tennessee. . . . . . . . . . . . . . .Alabama . . . . . . . . . . . . . . . .Mississippi . . . . . . . . . . . . . .

East-Central . . . . . . . . . . . . . . .Maryland . . . . . . . . . . . . . . . .District of Columbia . . . . . .West Virginia . . . . . . . . . . . .Ohio . . . . . . . . . . . . . . . . . . . .Kentucky . . . . . . . . . . . . . . . .Indiana . . . . . . . . . . . . . . . . . .Michigan . . . . . . . . . . . . . . . .

Midwest . . . . . . . . . . . . . . . . . . .Wisconsin . . . . . . . . . . . . . . .Illinois . . . . . . . . . . . . . . . . . .Missouri . . . . . . . . . . . . . . . .

North-Central . . . . . . . . . . . . . .Minnesota . . . . . . . . . . . . . . .North Dakota . . . . . . . . . . . .South Dakota . . . . . . . . . . . .Nebraska . . . . . . . . . . . . . . . .Iowa . . . . . . . . . . . . . . . . . . . .

South-Central . . . . . . . . . . . . . .Kansas .,...... . . . . . . . . . .Oklahoma . . . . . . . . . . . . . . .Arkansas . . . . . . . . . . . . . . . .Louisiana . . . . . . . . . . . . . . . .Texas . . . . . . . . . . . . . . . . . . .

Western . . . . . . . . . . . . . . . . . . .Montana . . . . . . . . . . . . . . . .Colorado . . . . . . . . . . . . . . . .Wyoming . . . . . . . . . . . . . . . .New Mexico . . . . . . . . . . . . .Arizona . . . . . . . . . . . . . . . . .Utah . . . . . . . . . . . . . . . . . . . .Idaho . . . . . . . . . . . . . . . . . . .Oregon . . . . . . . . . . . . . . . . . .Washington . . . . . . . . . . . . . .California . . . . . . . . . . . . . . . .Nevada . . . . . . . . . . . . . . . . . .

45.416.038,3—

80.075.444.838.017.4—

44.559.415.539.5———

47.9

—37.7

4.923.8

100.0———

10.74.8———1.6—————5.3—

27.017.7

15.7——

————

—40.6—

52.9————

24.1——2.1—

10.5—4.9————

16.0——

30.6————————2.9———2.4—————

70.441.182.915.582.373.214.4—

12.5—

26.3}13.5}————

28.8}26.0}

43.8

31.6

33.5

38.8

19.4

41.4

25.4

30.1

32.8

21.2

43.7

29.1

28.5

33.5

18.4

20.4

19.7

34.3

40.2

18.0

24.2 1.9 2.1

25.6

18.6

29.0

2,4

3.7

3.5

2.9

3.8

4.0

3.5

4.7

1.9

3.0

2.9

14.7

14.8

17.6

25.6

16.5

11.4 2.6 2.2

3.2

3.3

3.6

2.8

3.6

aRegions correspond roughly to North American Electric Reliability Council regions.bElectric utility fuel use of less than about IO percent is not included for individual States.

SOURCE: Office of Technology Assessment, from Edison Electric institute, Statlsflcal Yearbook off the Electric Utility Industry: 1980(Washington, D.C; Edison Electriclnstltute,1981~ and North Amerlcan Electrlc Rellabillty council, Electrlc Power Supply and Demand, 1981-1990 (Princeton, N.J; North American ElectricReliablllty Council, July 198l)


six scenarios of cogeneration use that postulatepenetrations of 50,000, 100,000, and 150,000MW of cogeneration capacity by 2000 with twodifferent technology mixes. We then comparedthe capital requirements, operation and mainte-nance (O&M) costs, and construction and O&Mlabor needs for these scenarios to those for install-ing an equivalent amount of central station base-Ioad and peaking capacity (using two mixes forbaseload capacity–loo percent coal and SO/SO

coal and nuclear). In this comparison, OTA foundthat:

●

●

●

●

capital requirements for cogeneration variedfrom around 95 percent less to about 25 per-cent more than the capital requirements foran equivalent amount of central station ca-pacity;O&M costs for cogeneration ranged from ap-proximately 75 percent less to about 95 per-cent more than the O&M costs for centralstation generation;construction labor requirements for cogen-eration varied from around 45 percent lessto approximately 70 percent more than thosefor constructing an equivalent amount of util-ity capacity; andO&M labor requirements, measured inwork-hours per megawatthour, varied muchmore widely (e.g., 10 to several hundredtimes greater labor needs for cogenerationthan for central station capacity).

In generaI, the wide variations in these resultscan be attributed to the economies of scale inthe costs and labor needs for constructing andoperating cogeneration capacity. Thus, total esti-mated cogeneration capital requirements are, onthe average, lower than those for central stationcapacity, but may be slightly higher if all the co-generators were very small systems with a highinitial cost per kilowatt (e.g., 500-kW steam tur-bines, 75-kW diesels, 100-kW combustion tur-bines). Similarly, average estimated constructionlabor requirements for cogeneration range from

about the same as those for installing convention-al utility capacity to around so percent higher,and could be even greater when the smallest co-generators (that require more work-hours perkilowatt of capacity) are installed. On the otherhand, construction labor requirements for cogen-eration may be lower than those for central sta-tion utility capacity if the largest cogenerators areused (e.g., 100-MW steam or combustion tur-bines, 30-MW diesels). For O&M costs, cogenera-tion tends to be more expensive for small systemsand those with a higher capacity factor, and lessexpensive for large systems or those with a lowercapacity factor. Finally, the O&M labor require-ments for cogeneration are the most uncertain,primarily due to the lack of data in this area andbecause the economies of scale are even morepronounced.

Because the mean cost of cogenerated electric-ity tends to be lower than the marginal cost ofelectricity from new central station capacity, co-generation may have the potential to reduce therate of growth in retail electricity rates. That is,if utilities installed cogeneration capacity, lowercosts would be passed on to their customers thanif they installed conventional capacity. However,if utilities purchase cogenerated power at a ratebased on their marginal, or full avoided costs,then the cost passed onto other customers wouldbe equivalent to the cost of alternative electricity(i.e., either central station capacity or power sup-plied by the grid), and cogeneration would notreduce retail electricity rates, (see, “What Are thePotential Effects of the PURPA Incentives?”). Fur-thermore, where State regulatory actions providefor purchases of cogenerated power at rates thatare even higher than full avoided costs (e.g.,either because the State commission sets pur-chase power rates equivalent to the cost of oiland the utility uses a mix of fuels, or when thecommission establishes an explicit subsidy rate),non-cogenerating ratepayers will be subsidizingcogeneration.

Ch. 2—Issues and Findings . 43

WHAT ARE THE ENVIRONMENTAL IMPACTS OF COGENERATION?The primary environmental concern about co-

generation is the air quality impacts. In general,cogeneration does not appear to offer automaticair quality improvement or degradation com-pared to the separate production of electricityand thermal energy (see table s). Rather, eachcogeneration application must be evaluated sep-arately. Thus, cogeneration’s greater fuel efficien-cy—when considered by itself—appears to offera decrease in the total emissions associated withelectric and thermal energy production, but,when evaluated in combination with the otherchanges associated with substituting cogenera-tion for conventional energy systems (includingchanges in the type of combustion equipment,its scale, and the type of fuel), may actually leadto an increase in total emissions.

Similarly, the location and technological char-acteristics of a cogenerator will affect ambientpollution concentrations and pollution disper-sion. Cogeneration usually involves shifting emis-sions away from a few central powerplants withtall stacks to many dispersed facilities with lowerstacks. In many situations, this shift will lead tolocal increases in annual average pollutant con-centrations near the cogenerators. For urban co-generators, total population exposure may in-

.crease because the emissions sources have beenmoved closer to densely populated areas. Also,air quality under certain meteorological condi-tions (such as low-level inversions) may be worsewith cogeneration than with conventional sepa-rate electricity and thermal energy production.On the other hand, in some situations the “worstcase” short-term pollutant concentrations causedby cogenerators will not be so high as the worstcase concentrations associated with the facilitiesthey displace. Moreover, if a cogenerator replacesseveral small furnaces or boilers then its air qualityimpacts can be positive.

Industrial and large-scale commercial cogen-eration systems using steam or combustion tur-bines do not appear to present significant airquality problems in most situations. However,if the substitution of these cogeneration technol-ogies for separate electric and thermal energyproduction also involves a switch from “clean”to “dirty” fuels (e.g., from distillate oil to highsulfur coal) then emissions could increase. Simi-larly, where a new steam or gas turbine cogener-ator that primarily produces electricity is substi-tuted for a new boiler or furnace, then the cogen-erator could add significantly to local emissions.

Table 5.—Effect of Cogeneration Characteristics on Air Quaiity

Effect on air qualityTechnological characteristic Direct physical effect (positive or negative)Increased efficiency Reduction in fuel burned PositiveChange in scale (usually smaller for Change in pollution control Negative for electrica

electric generation, at times requirements (stringency Positive for heatlarger for heat/steam production) increases with scale)

Change in stack height and plume Negative for electricrise (increases with scale) Positive for heat

Changes in design, combustion Mixedcontrol

Changes in fuel combustion Changes in emissions production, Mixedtechnology required controls, types of

pollutants, physical exhaustparameters

Change of fuels Change in emissions production, Mixedtype of pollutants

Change of location (most often for Change in emissions density and Mixedelectric generation) distribution—electric power more

distributed, heat/steam maybecome more centralized

~he air quallty effect of replacing the electric power component of the conventional system with the electrlc component of the cogeneration system is negative.

SOURCE: Office of Technology Assessment from material in ch. 6.


The use of diesel cogenerators (and gas-firedspark-ignition engines), however, generally willlead to increased levels of nitrogen oxide (NOX)emissions at the cogenerator site, even after ac-counting for the displaced emissions from theseparate electric and thermal energy sources.Available controls can reduce diesel NOX emis-sions by nearly one-half, which mitigates but doesnot eliminate this problem. Diesels also emit po-tentially toxic particulate, but conclusive medi-cal evidence of harm is lacking at this time, andthe evidence that is available suggests that thishazard may not be critical.

Cogenerators’ greater fuel efficiency can leadto an important environmental benefit throughreduced exploration, extraction, refining/process-ing, and transportation of the fuel saved. How-ever, this benefit is difficult to quantify and com-pare to the various air quality effects noted above.Furthermore, this benefit usually will occur onlywhen the cogenerator uses the same fuel as theconventional energy systems it displaces. That is,if a fuel that is difficult to extract, process, andtransport (e.g., coal) is substituted for a “cleaner”fuel (such as natural gas) the overall impacts maybe adverse rather than beneficial.

The air quality concerns reviewed above meanthat cogenerators— especially those in urbanareas—must be designed and sited carefully.Most urban cogenerators are likely to be dieselsor gas-fired spark-ignition engines, both of whichhave higher NOX emissions than the systems theywould replace. In urban areas with high NOX

concentrations, deployment of large numbersof cogenerators without pollution controls andcareful siting could lead to violations of ambientair quality standards and increased risks of ad-verse health effects. There is considerable poten-tial to mitigate these problems through propersite selection and engine design, and the use ofavailable NOX controls. For example, uncon-

trolled diesel NOX emissions may vary by asmuch as a factor of 8 depending on the enginemodel and manufacturer, so appropriate enginechoice alone might improve environmental ac-ceptability significantly. However, there are noFederal emission standards for stationary dieselengines and the degree of risk from their deploy-ment will depend on the effectiveness of Stateand local air quality permitting and management.

Proper siting and design also are importantin avoiding the problems of “urban meteorol-ogy, ” or the effect of tall buildings on air cur-rents and, thus, on pollutant dispersion. Urbanmeteorology can cause plumes to downwash orto be trapped and recirculated in the artificial can-yons created by urban buildings, and can there-fore result in very high local pollution levels dur-ing certain wind conditions. Proper design andsiting—especially ensuring that exhaust stacksare taller than surrounding buildings—can avoidair quality problems caused by urban meteorol-ogy. But the solutions may be costly in certaincircumstances (e.g., when adjacent structures aremuch taller than the cogenerator’s building), andmay be ignored by developers unless there is astrong State or local permit review process.

Although potential air quality impacts are theprimary environmental concern for cogeneration,water quality, solid waste, noise, and cooling tow-er drift also may be important. Water pollutioncan result from blowdown from boilers and wetcooling systems, and runoff from coal piles andfrom scrubber sludge and ash disposal. In urbanareas, these effluents may have to be pretreatedbefore discharge into the municipal treatmentsystem. in addition, sludge and ash disposal maybe a problem in urban areas due to the lack ofsecure disposal sites. Noise is also primarily anurban problem, but control measures are read-ily available. Finally, cooling tower drift can bea nuisance for those in the immediate area.

Ch. 2—issues and Findings ● 45

1.

2.

3.

4.

CHAPTER 2Khalsa, P. S., and Stamets, L., Cornrnercial Status:Electrical Generation and Non-generation Technol-ogies (Sacramento, Calif.: California Energy Com-mission, April 1980).Edison Electric Institute, Statistical Y’earbook of theElectric Utility Industry: 1980 (Washington, D. C.:Edison Electric Institute, 1981).Geller, Howard S., The Interconnection of Cogen-erators and Small Power Producers to a Utility Sys-tem (Washington, D. C.: Office of the People’sCounsel, February 1982).North American Electric Reliability Council, Elec-tric Power Supply and Demand, 1981-1990 (Prince-ton, N.J.: North American Electric Reliability Coun-cil, July 1981).

5.

6.

7.

Office of Technology Assessment, U.S. Congress,Application of Solar Technology to Today’s EnergyNeeds (Washington D. C.: U.S. Government Print-ing Office, OTA-E-66, June 1978).Office of Technology Assessment, U.S. Congress,Synthetic Fuels for Transportation (Washington,D. C.: U.S. Government Printing Ofllce, OTA-E-185,September 1982).Resource Planning Associates, Cogeneration: Tech-nical Concepts, Trends, Prospects (Washington,D. C.: U.S. Department of Energy, DOE-FFU-1 703,1978).

Chapter 3

Context for Cogeneration

PageNational Energy Context . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 49

Current Picture and Trends . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 49Future Prospects . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 50implications for Cogeneration . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 51Conclusion .. .. .. .. .. .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 54

Electric Utilities Context . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 54The Electric Power Industry . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 55Current Status of Electric Utilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 72

Regulation and Financing of Cogeneration . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 76Federal and State Regulation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 76Financing and Ownership . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 104


Tables

Table No. Page6. 1980 U.S. Energy Demand . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 507. Ratio of Annual Energy Demand to GNP Growth Rates. . . . . . . . . . . . . . . . . . . . . . 508. Comparison of Energy Demand Projections . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 509. Thermal Energy Demand. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 53

10. U.S. Electric Power System Statistics, 1980 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5511. installed Generating Capacity, by Type of Prime Mover 1978 . . . . . . . . . . . . . . . . . 6112. Differences in Financing by Form of Ownership. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6413. New Capacity Additions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6514. Capital Structure for Private Utilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6515. Sources of Long-Term Financing to REA Electric Borrowers . . . . . . . . . . . . . . . . . . . . 6616. Taxes Paid by investor-Owned Electric Utilities-Electric Department Only, 1980.. 6717. Energy Property Eligible for ITC Under the Energy Tax Act of 1978.... . . . . . . . . . 6818. State Regulation of Utiiity Service and Operations.. . . . . . . . . . . . . . . . . . . . . . . . . . 6919. Rates for Power Purchased From Quality Facilities by State-Regulated Utilities . . . . 8620. Capital Recovery Factors for Cogeneration . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 106

Figures

Figure No. Page8. North American Electric Reliability Council Regions.. . . . . . . . . . . . . . . . . . . . . . . . . 589. The General Patterns of an Electric Power System . . . . . . . . . . . . . . . . . . . . . . . . . . . 59

IO. Daily Load Shapes for Five Representative Weekdays . . . . . . . . . . . . . . . . . . . . . . . . 6011. Typical Electric Distribution System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6212. Allocation of Electricity Costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6313. Statewide Utility Resource Plan Additions 1981-82: Renewable/Innovative

Technologies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9114. CWE Average Avoided Cost Paths: Baseline Construction . . . . . . . . . . . . . . . . . . . . . 9515. Generic Paths for Average Avoided Costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 98

Chapter 3

Context for Cogeneration

Cogeneration has attracted widespread atten-tion in recent years because of its potential forincreased energy efficiency, and therefore, lowerenergy costs. A decision by an industrial concern,a commercial building owner, or a utility to in-vest in a cogeneration system will be based onan evaluation of the supply and price of fuel,regulatory considerations, the cost and availabilityof capital, tax incentives, and the technical, cost,and output characteristics of cogeneration rel-ative to conventional separate electric and ther-mal energy systems. This chapter will review theinstitutional, regulatory, and financial contextwithin which cogeneration must compete against

conventional energy supplies, including the na-tional energy context (supply of and demand forelectricity and fuels), the structure and operationsof the electric power industry (as they may af-fect a utility’s choice of investing in a conven-tional baseload or peakload powerplant or incogeneration), and the regulation and financingof cogeneration technologies. Subsequent chap-ters will describe cogeneration technologies andtheir cost and output characteristics, promisingcogeneration applications in the industrial andcommercial sectors and in rural areas, and thepotential environmental and economic impactsof cogeneration.

NATIONAL ENERGY CONTEXTCogeneration systems could affect both the

supply of and demand for fuels and electricity.The greater operating efficiency that can resultfrom cogeneration’s dual energy output couldreduce the amount of fuel needed to supply elec-tric and thermal energy for the industrial andcommercial sectors. In many cases, dependingon the fuel used by the cogenerator and by theutility capacity it would displace, the fuel savedwith cogeneration could be oil or natural gas.Moreover, the widespread use of cogenerationcould reduce the demand for electricity from cen-tral generating plants. In order to analyze thesepotential effects, it is first necessary to understandthe current supply and demand picture for fuelsand electric power—the national energy contextin which cogenerators would operate.

This section discusses cogeneration with refer-ence to the current and projected energy picturein the United States. First, the present energysituation and recent trends are reviewed briefly.Then, some projections of energy demand–par-ticularly of electric and thermal demand in theindustrial and commercial sectors—are discussed.In doing so, this section also briefly outlines someof the factors that could alter the energy picturein these sectors which, in turn, would affect themarket penetration of cogeneration.

Current Picture and Trends

Table 6 presents 1980 U.S. energy demand byfuel and sector. Electricity is shown both as a de-mand and as a “fuel, ” with losses distributed toeach final demand sector.

Total energy demand in 1980 was 76.3 quad-rillion Btu (Quads), a decline of 3.4 percent fromthe 1979 total of 79.0 Quads. The size of this de-cline—the largest annual drop in energy demandever experienced by this country—was due inpart to the very large increase in oil prices in 1979and in part to investments in energy efficiencymade as a result of the 1973-74 price rise. Thiscan readily be seen by the 7.8-percent (2.9Quads) decline in petroleum consumption from1979 to 1980, and by the substantial decrease inthe rate of growth in energy demand since the1973 Arab oil embargo. Since 1973, overall U.S.energy demand has grown by approximately 0.8percent annually, as compared with an averageyearly growth of about 3.5 percent between 1950and 1972. The most telling change in the overallU.S. energy growth picture, however, is thatwhile energy growth has slowed dramatically,gross national product (GNP) has continued togrow at near historical rates. Table 7 shows thegrowth rates for both energy demand and GNP

49


Table 6.—1980 U.S. Energy Demand (Quads)

SectorElectric

Fuel Residential Commercial Industrial Transportation utilitiesPetroleum . . . . . . . . . . . . . . 2.05 2,34 8.88 17.99 3.00Natural gas . . . . . . . . . . . . . 5.91 1.92 8.41 0.60 3.79Coal . . . . . . . . . . . . . . . . . . . 0.10 0.10 3.35 — 12.12Nuclear ... , . . . . . . . . . . . . — — — 2.70Electricity . . . . . . . . . . . . . . 9.00 6,03 9.67 0.04Hydro . . . . . . . . . . . . . . . . . . —

—— — — 3.09

Total . . . . . . . . . . . . . . . . . 17.06 10.39 30.31 18.63 24.70SOURCE: U.S. Department of Energy.

Table 7.—Ratio of Annual Energy Demandto GNP Growth Rates

GNP rate Energy demand ratePeriod (percent) (percent) Ratio1950-60 . . . . . . . . 3.29 2.76 0.841960-70 . . . . . . . . 3.85 4.24 1.101970-80 . . . . . . . . 3.26 1.31 0.40SOURCE: Office of Technology Assessment.

over the last three decades, as well as the ratioof energy demand to GNP growth rates for eachof those decades. This latter measure indicatesthat a healthy economic growth rate can be sus-tained with a wide variety of energy growth rates,and demonstrates the conservation potential ofthe U.S. energy economy.

In addition to the cost effectiveness of conser-vation, other important national energy trendsthat have emerged during the past 8 years includethe steady decline of domestic oil and natural gasproduction, and the increasing financial problemsof electric utilities. The latter are, in large part,due to the large drop in electricity demandgrowth and the rapidly escalating costs of cen-tral station electricity generation. The unexpectedrapid decline in the growth of electric energy de-mand (from 7.9 percent per year for 1950-72 to3.5 percent annually for 1972-80) found mostutilities with far greater capacity under construc-tion than needed to meet the new growth. Whenit became evident that the lower growth rateswere here to stay—in fact they might even getsmaller—electric utilities deferred or canceled asmuch of their construction budget as they could.Many utilities were still left, however, withsubstantial excess capacity.

In addition, several factors combined to makenew capacity much more expensive. These in-cluded longer construction times, increased en-vironmental and regulatory review, higher in-terest rates, and high inflation. One major con-sequence of these considerations is that, in mostcases, the marginal cost of new central stationelectricity now exceeds the average cost. As aresult, electric utilities face severe financial prob-lems, and those utilities that are experiencing de-mand growth or that need to displace oil-firedcapacity may be unable to raise capital for anynew plant construction (see “Electric UtilitiesContext,” below).

Future Prospects

All energy demand projections show a con-tinuation of the trend toward increased energyefficiency, although there is still considerablevariation as to how much (see table 8). The rangeof the projections shown in table 8 is due prin-cipally to different assumptions about consumerresponses to changes in energy prices. In allcases, however, these projections recognize thatchanges in demand will be the dominant factorin the energy future of the United States for thenext few decades.

Table 8.—Comparison of Energy Demandprojections (Quads)

Forecaster 1980 1990 2000Energy Information Administration . . 76.3 87.0 102.5Exxon . . . . . . . . . . . . . . . . . . . . . . . . . . . 76.3 81.0 91.0Edison Electric Institute . . . . . . . . . . . 76.3 — 117.2National Energy Policy Plan. . . . . . . . 76.3 80-90 90-110SOURCE: Office of Technology Assessment

Another trend mentioned above–the declinein domestic petroleum and natural gas produc-tion—also is very likely to continue. In a technicalmemorandum, World Petroleum Availability:79802000, OTA estimated U.S. oil productionat 4 million to 7 million barrels per day (MMB/D)by 2000 compared to today’s 10.2 MMB/D (52).Exxon also has projected a drop to about 7.5MMB/D in 2000 (26). The Energy Information Ad-ministration (EIA), on the other hand, projects aslight increase above today’s level to about 10.9MMB/D (23). Despite the rapid increase in drill-ing activity since 1979, OTA has not yet seen anyevidence to contradict findings of a net declineof between 3 to 6 MMB/D by the end of thecentury.

Natural gas production is even more uncertaindue to the existence of large quantities of un-conventional gas (Devonian shale, tight sands,coal seam methane, and geopressurized brine).For most types of unconventional gas, the uncer-tainty is not so much the size of the resourcebase, but the production rates that can be ob-tained and the production cost. The availableestimates currently center on total natural gas pro-duction of 15 trillion to 17 trillion cubic feet (TCF)per year in 2000 compared to 19.5 TCF for 1980.If the price of natural gas rises to that of worldoil, however, these same estimates show produc-tion in 2000 to be approximately the same as itis today. In any case, there is little probability thatthe Nation will see a significant increase indomestic gas production, and such an increaseis even less likely for oil.

Implications for Cogeneration

The Nation is confronted with a combinationof circumstances that favor continued emphasison different, less costly ways to generate electrici-ty, and on increased efficiency in electricity use.These circumstances have led to a resurgence ininterest in the cogeneration of electricity and ther-mal energy. The relatively small size of cogenera-tion units compared to central power stationsmay offer significant short-term advantages forfinancing new capacity. Cogenerators will takemuch less time to build than central station plantsand they represent smaller capacity increments

that would allow rapid adjustment to changes indemand. Moreover, because cogeneration unitsare installed at or close to the point of demand,most or all of the energy requirements of manyindustrial plants and commercial buildings couldbe provided onsite with the added possibility ofgenerating electricity for distribution through theutility grid. Finally, cogenerators’ ability to usefuel for two purposes (electricity and thermalenergy) greatly increases the overall utilizationefficiency of that fuel. Thus, where electric utilitiesproject continued reliance on oil and gas due tothe unavailability or infeasibility of other fuels,or where cogeneration systems can use alternatefuels, substantial oil or gas savings may result.

The technical advantages of cogeneration havealways been available. It is the advent of theeconomic and energy supply and demand con-ditions described above that adds potential fueleconomy, financial, and planning advantages forcogeneration compared to central station elec-tricity generation and conventional thermalenergy combustion systems. Whether these ad-vantages will prove sufficient to accelerate thegrowth of cogeneration will be determined large-ly by the amount and character of demand forelectricity and thermal energy in the commercialand industrial sector, and by the future financialhealth of the electric utility sector.

Electricity Supply and Demand

Perhaps the most critical factor in cogenerationeconomics is the demand for electric power. ThePublic Utility Regulatory Policies Act of 1978 of-fers economic and regulatory incentives to co-generators that enable utilities to defer or cancelnew powerplants and decrease oil and gas use.A zero or low growth in electricity demand, how-ever, could undermine these incentives by reduc-ing the need for cogenerated electricity and,therefore, reducing the economic attractivenessof cogeneration. Moreover, where the utility isprimarily dependent on coal, nuclear, or hydro-electric plants, or where it plans to convert ex-isting oil-fired capacity to alternate fuels,cogeneration will only be attractive if it also canuse alternate fuels and can offer substantial finan-cial advantages.

Currently there is considerable uncertaintyabout future electric power demand growth; theSolar Energy Research Institute (SERI) projecteda 0.4 percent per year increase under their leastcost approach (61 ), while the North AmericanElectric Reliability Council (NERC) estimates a 2.9percent annual growth rate (48). In terms ofcapacity requirements, the SERI projection couldbe met by 620 gigawatts (GW) of capacity oper-ating at the current capacity factor of 45 percent.Further, SERI shows that 577 GW could be avail-able in 1985 assuming completion of all plantsscheduled to be on-line in 1985, and the retire-ment of all plants built before 1961 and of all oiland natural gas plants built between 1961-70 (61).Therefore, under the SERI least cost approach,very little new capacity would be needed past1985, and any cogeneration added after thatwould be likely to substitute for electricity fromexisting coal, nuclear, or hydroelectric plants.Under the NERC case, however, capacity is pro-jected to reach about 900 GW by 2000, an in-crease of 300 GW over present capacity. Eventhen, NERC estimates that the capacity factorwould have to increase to 50 percent to meettheir projected energy demand. Accounting forretirements and conversion of oil and natural gas,about 50 percent more new capacity would haveto be added under NERC projections than nowexists (49). In this case, cogeneration could havea very large market potential.

The future demand for electricity will be deter-mined by the relative prices of electricity andcompeting fuels (including conservation meas-ures), by the development of technologies thatuse electricity more efficiently (e.g., processequipment, appliances), and by consumers’ per-ceptions about the stability of oil and natural gasresources. Currently, average electricity prices inthe commercial sector are about 2.5 times dis-tillate fuel oil prices and five times natural gasprices on a delivered Btu basis. * For industry,both of these price ratios are about 2 to 1. Theratios have decreased by 20 to 60 percent fromthose in 1970, however.

*As will be discussed below, differences in end use efficiencybetween equipment using electricity and that using natural gas orfuel oil make price comparison on a delivered Btu basis alone,incomplete.

Continuation of the low rate of growth in elec-tricity demand, coupled with the current excessof generating capacity, may keep the rate ofgrowth in electricity prices rather low over thenext several years. If prices do remain somewhatstable, then the difference between electricityprices and oil and gas prices would be likely tobecome even smaller. However, the current de-cline in the real price of oil could alter this trend.Furthermore, if the oil price decline continues forthe next few years, natural gas price increasesfollowing decontrol also are not likely to be sodramatic as originally thought. Therefore, theratio of electricity prices to oil and natural gasprices would not decline for some time. At thispoint, it is most likely that the ratio will decline,although more slowly that previously antici-pated. The price trajectories used in the analysisof commercial cogeneration in chapter 5 also pro-ject that the ratio will become smaller.

Such growth rates would continue the trendtoward price closure between electricity andnatural gas or distillate fuel oil. If these trends arecombined with the development of technologiesfor buildings and industry that use electricity moreefficiently than equivalent oil or natural gas burn-ing technologies that provide the same services(e.g., space heating, reheating of finished metals),the costs of providing these services with elec-tricity could become lower than with oil ornatural gas. For example, in many areas, efficientelectric heat pumps can provide space heatingmore economically than oil furnaces. There areeven a few regions where space heating withelectric heat pumps is cheaper than with naturalgas furnaces.

Natural gas and oil are the primary energysources for industrial processes, supplying bothdirect heat (such as catalyzing chemical reactionsand heat treating) and process steam. The majoruse of electricity in industry is to run motors.Whether technologies that use electricity couldeconomically replace direct heat or processsteam in industry is much less certain than in thecommercial sector. Some possibilities includemicrowave, infrared, or dielectric heating, veryefficient electric motors for replacing steammechanical drives, and pulsed current devicesfor surface reheating of metals.

Ch. 3—Context for Cogeneration ● 53

It is possible, then, that the growth of electricitydemand could increase sharply toward the endof the decade. * However, the extent of any in-crease in industrial or commercial demand willdepend on the size of the dollar savings achievedby switching to electricity relative to the requiredcapital investment. Conversion is much morelikely for new buildings and plants than for ex-isting facilities. Therefore, unless there is signifi-cant new development in energy intensive indus-tries for which more economical electric tech-nologies are available and accepted, the growthrate of industrial use of electricity is not likely tochange substantially for the remainder of thecentury.

It is this uncertainty of future demand that pro-vides a potentially important role for cogenera-tion. If electricity use in buildings and industrydid increase substantially, electric utilities couldbe strained financially if they tried to meet theincreased demand with new central station ca-pacity. Further, attempts to accommodate de-mand growth with central station capacity couldlead to a rapid increase in electricity prices. Thisis because the marginal cost of electricity—thecost of a new plant—is often considerably higherthan the average cost. Therefore, as new capacitybecomes a larger fraction of the total electric utili-ty plant, the average cost will grow closer to themarginal cost. Cogeneration could help alleviatethese pressures, particularly in the first years ofan increase in demand. The small size of cogen-eration systems would allow rapid and fairlyprecise matching of supply and demand, andwith much smaller increments of capital. Thiswould greatly reduce the risk of building excesscapacity or having to defer or cancel capacityunder construction should demand growth sud-denly slow or stop. Moreover, because cogenera-tion supplies thermal energy, it could at least par-tially offset increases in electricity demand dueto a rapid rise in the use of electric heating.Cogeneration’s competitiveness would then turnon the difference between the cost of purchas-ing electricity plus supplying heat, and the fuel

*The extent to which electricity can be substituted economical-ly for other energy sources in buildings and industry will be ex-

amined in detail in forthcoming OTA studies on oil disruption andon electric utilities.

and operating and maintenance costs of a cogen-eration system. Finally, the avoidance of exten-sive new additions to transmission and distribu-tion systems also might alleviate some of the elec-tric utilities’ capital problems.

However, if utilities are able to raise capitaleasily, or if demand does not increase in the faceof stable prices, central station powerplants fueledwith coal, uranium, or hydropower may be pre-ferred to oil- or gas-fired cogeneration systems.These alternate energy sources probably wouldbe cheaper than the oil or natural gas likely tobe used in most cogeneration systems in the nearterm. Therefore central station electricity—evenwith a substantially larger capital cost per kilo-watt than cogeneration capacity—is likely to becheaper than cogenerated electricity despite co-generation’s higher overall fuel efficiency.

Thermal Energy Demand

The second major influence on the growth ofcogeneration is future thermal energy demandin buildings (space and water heat) and industry

(direct heat and process steam ). We have alreadydiscussed how some of this future load may bemet by electricity rather than by direct combus-tion of fossil fuels. In addition, available conser-vation opportunities will slow thermal demandgrowth and could even reduce thermal energy

use (by 2000) from the 1980 levels. Conservationwill affect electricity use as well, and even ifsignificant conversion from other fuels to elec-tricity (as discussed above) does occur, electricity

demand growth in these sectors still could be keptlow. Table 9 shows two estimates of direct com-bustion heat requirements for commercial build-ings and industry for 2000 compared to 1978. Ascan be seen, current thermal demand in industryis more than twice that of commercial buildings.Moreover, under either the EIA or the SERI pro-jection, the difference would become even morepronounced.

Table 9.—Thermal Energy Demand (Quads)

Buildings IndustryYear Space/water heat Direct heat Steam1978 ......., . . . . 4.5 3.8 6.82000 (EIA) . . . . . . . 3.8 5.0 9.32000 (SERII . . . . . . 1.6 3.7 6.6SOURCE: Office of Technology Assessment


The SERI estimates in table 9 are based on aleast cost approach using conservation technol-ogies that cost the equivalent of up to the 1980average cost of oil and electricity ($7.50/MMBtuand $.057/kWh respectively) (60). The EIA pro-jections are derived from economic and engi-neering models and reflect judgments about ac-tual consumer response to changing energyprices (22). In either case, cost-effective conser-vation opportunities for commercial buildingscould reduce fuel requirements for space andwater heating from 15 to 65 percent. For industry,EIA estimates a 37-percent increase in steamgrowth while SERI projects a 3-percent decrease(see the section on “Industrial Cogeneration Op-portunities” in chapter 5 for an analysis of steamgrowth projections).

These analyses indicate that cogeneration willhave greater potential in the industrial sector thanin commercial buildings as far as supplying ther-mal energy is concerned. Both EIA and SERI anal-yses imply that in the commercial buildings sec-tor, cogeneration will have to compete with cen-tral station electricity and with fuel freed by con-servation in meeting future space and water heat-ing demand. When the low load factor inherentin buildings’ heat load is added, the economicpotential of cogeneration is decreased further (seech. 5). In essence, conservation can considerablyreduce the opportunity to take advantage of co-generation’s high fuel utilization efficiency.

The air-conditioning demand of buildings alsooffers a potential market for thermal energy fromcogeneration. In 1980, over 98 percent of allcommercial air-conditioning was electric. Forthese buildings, the use of cogenerated steam forcooling would require conversion to either ab-sorption units or steam-driven compressors.

Where it is economic to do so, such conversionwould increase the baseload steam demand andtherefore the building’s thermal load factor. By2000, SERI and EIA project cooling demands of2 and 4 Quads of primary energy, respectively.

Conclusion

The attractiveness of cogeneration will depend,to a large extent, on energy demand in the com-mercial and industrial sectors, on the balance be-tween thermal and electric loads, and on theoverall demand for electricity. These, in turn, de-pend heavily on the price of energy–particularlythe relative prices of electricity, distillate fuel oil,and natural gas. It is fairly certain that energy de-mand will grow much more slowly than in thepast. The range of possible growth rates, how-ever, is large. Lower growth rates, while notnecessarily changing the economics of cogenera-tion, will clearly reduce the potential market aswell as the net fuel savings. Further, a very lowgrowth rate for electricity is likely to dampenprice increases and reduce the price paid byutilities for cogenerated power, both of whichwould reduce the economic attractiveness of co-generation. However, the uncertainty of futureelectricity demand and the economic problemscaused by a severe mismatch between loadgrowth and capacity growth make small capaci-ty additions potentially very desirable in the shortterm. Therefore, while conservation through in-creased efficiency is likely to be the most eco-nomic route to choose for at least the next severalyears, there appears to be a potential role forcogeneration, particularly in the industrial sec-tor where thermal and electrical demands arelikely to remain large.

ELECTRIC UTILITIES CONTEXTFuture supply of and demand for energy and owned and operated by electric utilities, or they

electricity, as discussed above, will be a major may be installed by former utility customers whofactor in determining the role cogeneration will now provide some or all of their own electricplay in the Nation’s energy future. Equally im- power needs and who may even supply powerportant in defining that role will be the electric to the utility. In this context, cogeneration mustpower industry. Cogeneration systems may be compete, both technologically and economically,

with well established electric and thermal energyconversion and distribution systems as well aswith alternate energy forms and conservation.The elements of this competition—both on a site-specific and a national energy policy basis—willbe wide ranging, encompassing the technologi-cal, fuel use, and institutional characteristics ofthe electric power industry, as well as the financ-ing, regulation, and operations of technologiesthat supply energy for commercial and industrialapplications.

This section will review the general electric utili-ty context within which cogeneration systems willcompete. The following section of this chapterwill analyze the present institutional and regu-latory context specific to cogeneration.

The Electric Power Industry

Current operations of electric utility systems arediverse, encompassing a wide range of technicaland institutional configurations. These include thenumber, size, and type of generating plants; theamount of electricity consumed by customerclasses and their regional load profiles; and thedifferent types of institutions that supply power,coordinate specific utility functions, and regulatethe power industry. Support activities include theproduction and acquisition of fuel supply and ofthe necessary equipment for fuel handling andstorage, and for electricity generation, transmis-sion, distribution, and consumption.

A wide array of institutions has evolved to per-form the functions listed above. The U.S. elec-tric power supply system is composed of over3,400 separate entities, including private, public,and cooperative utilities, joint action agencies,

Federal power agencies, power pools, and elec-tric reliability councils. In 1980, these systems had619,050 megawatts (MW) of installed generatingcapacity to supply close to 93 million customerswith about 2.3 trillion kilowatthours (kWh) ofelectricity (see table 10) (55). The utilities in theelectric power system obtain financing from avariety of sources including banks, insurancecompanies, traditional stock and bond markets,and Federal programs; their financial and tech-nical operations are regulated at the Federal,State, and local level. Finally, both the produc-tion and consumption of electricity are supportedby innumerable institutions that manufacture, dis-tribute, install, and service equipment, tools, andappliances. All of these factors together make theelectric utility industry the largest in the UnitedStates in terms of capital assets and issuance ofstocks and bonds.

Utility Organizations

The organizations that supply electricity in theUnited States include private or investor-ownedutility companies; publicly owned utilities suchas State, county, or municipal systems, and Fed-eral power agencies; rural electric cooperatives;joint ownership organizations; and groups of util-ities that coordinate their operations to improveefficiency and reliability.

Private utiiities are owned by their investorsand generally are granted territorial franchises byState or local governments. Most investor-ownedutilities (IOUS) generate their own electricity, andsome are part of vertically integrated corporationsthat own their fuel supply (e.g., “captive” coalmines) or other support activities.

Table 1O.–U.S. Electric Power System Statistics, 1980

Electric operating Net electricInstalled capacity kWh generation Customers revenues plant investment

Type of system Millions Millions Millions(and number) Megawatts Percent of kWh Percent Number Percent of dollars Percent of dollars Percent

Local public systems (2,248) . . . . 67,568 10.9 204,880 9.0 12,467,700 13.5 $12,224 10.8 $34,100 11.9Privately owned systems (217) . . . 476,979 77.1 1,782,545 78.0 70,620,300 76.2 87,062 76.9 207,555 72.4Rural electric cooperatives

(924) . . . . . . . . . . . . . . . . . . . . . . . 15,425 2.5 63,557 2.8 9,523,600 10.3 9,707 8.6 23,892 8.3Federal power agencies (8). . . . . . 59,078 9.5 235,051 10.3 13,300 0.01 4,238 3.7 21,100 7.3

Total . . . . . . . . . . . . . . . . . . . . . . . 619,050 100.0 2 , 2 6 6 , 0 3 3 1 0 0 . 0 9 2 , 6 2 4 , 9 0 0 1 0 0 . 0 $113,231 100.0 $ 2 8 6 , 6 4 7 1 0 0 . 0

aDoes not Include nuclear fuel.

SOURCE: Office of Technology Assessment from “Public Power Directory,” Publlc Power, January-February 1982.


IOU companies dominate power generation inthe United States today. The 217 IOUS representabout 6 percent of the total number of utilities,but those 217 own approximately 77 percent ofall installed generating capacity and generateabout 78 percent of the electricity produced (seetable 10). In 1977, approximately two-thirds ofthe IOUS had a peak demand in excess of 100MW, and about 12 percent had a peak demandgreater then 3,000 MW (21). Because of the cap-ital intensity of the electric utility industry, withtotal operating revenues of over $113 billion in1980 and net electric plant investment of over$286 billion, the domination of the industry bya relatively few IOUS means that they also deter-mine the role of utilities in financial and othermarkets.

publicly owned utilities include municipal,public utility districts, and State and county sys-tems. The authority to establish a public utilityderives from the State government, and a fewStates (e.g., New York, Nebraska) currently havetheir own systems. However, most States havedelegated this authority to county or municipalgovernments.

The relatively large number of publicly ownedutilities, in contrast to their small share of the elec-tricity market (see table 10), reflects their smallsize. Most of these systems only purchase whole-sale power and distribute it to their customers;those municipal that do generate have very smallloads (fewer than 100 publicly owned utilitieshave peak demands in excess of 100 MW) (21).Roughly 71 percent of the local public power sys-tems purchase all their electricity, while about6 percent own sufficient generating capacity tosupply all their needs. The remaining 23 percentof public utilities generate some portion of theirneeds and purchase the remainder (55).

Cooperative utilities represent a different typeof public ownership. The co-ops are nonprofiteconomic entities that are owned and managedby their customer members. Members’ shares inthe co-op may be plowed back into the opera-tion and/or expansion of the business as patron-age capital in order to keep the cost of co-op serv-ice as low as possible, or the patronage capitalmay be “rotated” —essentially paid out as divi-

dends–if the co-op’s equity ratio is 40 percentor higher.

Rural electric co-ops comprise a vast operatingnetwork of over 900 local and regional electricsystems in 46 States which own and maintainnearly 44 percent of the Nation’s electric distribu-tion lines, and whose service territories encom-pass 75 percent of the land area of the UnitedStates. The rural electric system is a two-tieredoperation, including 870 local distribution co-opsand 54 generation and transmission co-ops(G&Ts). The 870 local co-ops purchase electrici-ty and distribute it to their own rural customers,while G&Ts generate and/or transmit electricityprimarily for local distribution co-ops. Some G&Tsalso sell electricity wholesale to municipal andIOUS, while distribution co-ops may purchasepower from a combination of sources, includingG&Ts, Federal power agencies, and IOUS (16).

Still another form of public utility ownershipis represented by Federal power marketing agen-cies. The Federal role in electricity generationdates back to the Reclamation Act of 1906, whichempowered the Bureau of Reclamation to pro-duce electricity in conjunction with Federal ir-rigation projects, and to dispose of any surpluspower to municipal utilities (39). The secondFederal power marketing agency was the Ten-nessee Valley Authority (TVA), which was estab-lished in 1933 as a multipurpose river project withresponsibility for flood control, regional develop-ment, hydroelectric power generation, and otheractivities. Today, it is the single largest electricutility in the country, with a total system capaci-ty of over 31,000 MW. Approximately 65 percentof TVA’s sales are at wholesale to municipal utili-ties and rural electric co-ops. The remainder issold to private industries, other Federal agencies,and private power companies (55).

Other Federal power agencies include theBonneville Power Administration, which wasestablished in 1937 and which markets powerfrom hydroelectric projects constructed by theArmy Corps of Engineers and the Bureau of Recla-mation in the Columbia River Basin and operatesthe Nation’s largest network of long-distancehigh-voltage transmission lines; the SouthwesternPower Administration, which was set up in 1944


to market power from Corps of Engineers proj-ects in Arkansas, Missouri, Oklahoma, and Texas;the Southeastern Power Administration, createdin 1950 to market power from Corps projects in10 Southeastern States; the Alaska Power Ad-ministration, established in 1967 to operate andmarket power from Federal hydroelectric projectsin Alaska; and the Western Area Power Admin-istration, which was set up in 1977 and incor-porates Federal power marketing and transmis-sion functions formerly performed by the Bureauof Reclamation and markets power from a num-ber of Corps hydroelectric projects (55).

A hybrid form of public ownership is the jointaction agency, in which two or more publicpower systems pool their plans to purchasepower or to finance total or partial ownership ofgeneration and/or transmission systems. Wherethe local public utility system is no longer ade-quate or economical and low-cost Federal poweris not available, joint action agencies can placepublic power systems in a more advantageouscost and supply position, allowing even the small-est electric utilities to realize economies of scale(4). Joint action may also provide publicly ownedutilities with more flexibility in choosing fuels andtypes of generating capacity while avoiding therisks of a single-shot investment in one plant.IOUS may choose to participate in joint actionagencies to reduce plant construction costs or toobtain lower cost financing (32).

Joint action agencies are authorized by Statelegislation and membership arrangements vary.They may include statewide areas (e.g., Munici-pal Electric Authority of Georgia), correspond toIOU service areas (such as in North Carolina,which has three agencies, one for each of theState’s major IOUS), or be determined accordingto both geography and perceived mutual interests(e.g., the five Minnesota organizations). Somejoint action agencies, such as the Missouri BasinMunicipal Power Agency, have members fromseveral States. As such, they cannot finance proj-ects themselves but must rely on the members’funding abilities. In 1981, there were 49 public-ly owned joint action agencies in 31 States (55).

Since the 1920’s, all the types of utility systemsdescribed above have been interconnected and

their operations coordinated to some degree inorder to reduce costs by increasing the produc-tivity of the resources employed in the genera-tion and transmission of electricity, and to im-prove reliability by applying the combined re-sources of several systems to a contingency onany one. These intersystem agreements nowcomprise approximately 20 formal organizationsknown as power pools. The degree of coordina-tion among utilities in power pools can rangefrom very loose agreements for exchanges ofenergy; to some coordination of planning, con-struction, operation, and capacity reserves; tocomplete integration with joint planning on asingle system basis, centralized dispatch ofgenerating facilities, and strict contractual re-quirements for generating capacity and operatingreserves (29).

In general, the potential economic benefits ofpooling include reduced investment coststhrough economies of scale in building largergenerating units and through lower reserve mar-gins that result from reducing the ratio of gener-ating unit size to combined system peakload;greater operating economies through increasedload diversity, reduced operating costs per unitoutput for larger plants, and fuller use of thelowest cost capacity available on the system; andincreased savings through coordinated construc-tion programs that minimize the costs of tem-porary excess capacity that may result from theaddition of large generating plants. The poten-tial reliability benefits of power pools derive fromaccess to support from other systems, and maybe realized either through a reduction in reservesneeded to achieve a certain level of reliability orthrough an increase in the level of reliability ofthe coordinated systems (29).

Electric reliability councils represent a secondform of coordination among utilities. A FederalPower Commission (FPC) investigation of the1965 blackout in the Northeast stressed the needfor greater reliability and coordination amongelectric utility companies. In response to FPC find-ings, NERC and nine regional councils wereformed in the late 1960’s (see fig. 8), represent-ing about 95 percent of the Nation’s generatingcapacity. Each regional council consists of a rep-

98-946 (I - 83 - 5 : IQI, 3


Mid-AmericaInterpool Network

Mid-Continent AreaRellablllty CoordinationAgreement

Northeast PowerCoordlnatlng Council

Southeastern ElectricReliability Council

Southwest Power Pool

Western SystemsCoordinating Council

resentative from each of the major utilities in theregion and from groups of small utilities in someregions.

The regional councils develop voluntary stand-ards for those aspects of bulk power supply thataffect the regionwide reliability of service (e.g.,design criteria for transmission facilities). NERCaids in the coordination of policy issues amongthe regional councils, and provides industry in-formation, comment, and recommendationsabout the reliability and adequacy of bulk powersupply at the national level. In addition, NERCis responsible for the development and mainte-

Figure 9.—The Generai Patterns

Generating station

TransmittingGenerating station . . .

nance of nationwide standards for interconnectedoperation (18).

Technical Aspects of the Utility industry

A conventional power system can be describedas the coordinated operation of generating units,high-voltage transmission lines, and subtransmis-sion and distribution networks. Figure 9 showsa typical power system structure.

The primary consideration in an electric powersystem is to serve the electric loads, or power re-quirements, in a given area or region. The power

of an Eiectric Power System

a

Receiving substation’

Generating station

Distribution linesto electric users

Distribution linesto electric users

SOURCE: Economic Regulatory Administration, The National Power Gr/d Study, Volume //(Washington, D. C.: U.S. Departmentof Energy, DOE/ERA41056-2, September 1979).


requirements include all devices or equipmentthat convert electricity into light, heat, ormechanical energy, or otherwise consume elec-tricity (e.g., aluminum reduction), or the re-quirements of electronic and control devices. Thetotal load on any power system is seldom con-stant; rather it varies with hourly, daily, seasonal,and annual changes in the service area’s re-quirements (see fig. 10). The minimum systemload for a given period is termed the baseload,while maximum requirements (usually resultingfrom temporary conditions) are called peakloads.Because electric energy currently cannot be

stored in large quantities, generating plant opera-tions must be coordinated closely with fluctua-tions in the load, and large utility systems usual-ly have separate generating plants sized to meetbase, intermediate, and peakloads.

Table 11 shows the current U.S. generatingcapacity by type of prime mover. The choice ofcapacity type is a function of service needs, eco-nomic and financial considerations, resourceconstraints (e.g., fuel, land, water), potential en-vironmental impacts, future growth, politics, reg-ulatory requirements, and management prefer-

Figure 10.—Daily Load Shapes for Five Representative Weekdays(North Central Region, 1980)

1.0

0.9

0.8

0.6

0.5

0.4

0.3

SOURCE: Decision Focus, Inc., Evacuation of the Economic Benefits of Oecentra/lzed Electr(c Generathrg Equipment Con-nected to a Ut///ty Gr/d (contractor report to OTA, October 19S0).

Ch. 3—Context for Cogeneration . 61

Table 11.–lnstalled Generating Capacity, by Type of Prime Mover, 1978

Total Hydroelectric Conventional steam Nuclear steam Internal combustion

Thousandsof kilowatts

Investor-owned utilities . . . . . . . . . . . . . . . . 453,647Municipal utilities . . . . . . . . . . . . . . . . . . . . . 34,426State systems and publlc

utility dlstrlcts . . . . . . . . . . . . . . . . . . . . . . 25,322Rural electric cooperatives . . . . . . . . . . . . . 11,635Federal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 54,282

ThousandsP e r c e n t o f k W

76 23,8476 4,694

4 11,97529 30,431

ThousandsP e r c e n t o f k W

4 383,024< 1 25,511

2 9,245<1 11,073

5 20,376

Thousands ThousandsPercent of kW Percent of k i lowatts Percent

66 44,984 8 1,792 < 14 963 < 1 3,258 < 1

2 4,059 < 1 43 < 12 < 1 430 < 14 3,456 < 1 17 < 1

Total. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 579,312 100 71,014 12 449,231 78 53,527 9 5,540 1

SOURCE: Edison Electric Institute, Statistical Yearbook of the Electric Utility Industry, 1980 (Washington, D. C.: Edison Electric Institute, November 1981).

ences. In general, fossil and nuclear fueled steamplants and many hydroelectric facilities are usedfor baseload and intermediate-load generationwhile some hydro equipment (usually pumpedstorage) and combustion turbines are used tosupply peaking power.

The trend in recent years has been to constructlarge baseload plants in order to capture econo-mies of scale. Nuclear plants usually exceed1,000 MW in nameplate capacity and most of theexisting fossil steam plants are larger than 5ooMW. However, as capital costs and constructiontimes increase and it becomes more difficult tofinance large powerplants, some utilities are turn-ing to smaller equipment that may use uncon-ventional fuels. Where the service needs are notexpected to grow rapidly, small units such ascogenerators may improve load factors whilealleviating utility financial problems in the shortterm, although their longer term financial andsystem planning advantages are uncertain (seech. 6).

In order to serve the electric loads of an areaadequately, a utility must plan not only forbaseloads and peakloads, but also for systemreliability during scheduled and unscheduledoutages (e.g., equipment maintenance, stormdamage) and for demand growth. To some de-gree, system reliability can be achieved throughinterconnections with other utilities (i.e., powerpooling), but utilities also must incorporate re-serve margins into their planning. Reserve mar-gins are the installed available capacity in excessof that needed to meet the system’s peak demandwhen due consideration is given to maintenancerequirements, random equipment failure, orother contingencies. The amount of reservecapacity required in a given situation depends on

the reliability criterion, the behavior of individualgenerators, the unit size mix, and the intercon-nection support available. The usual planningprocedure is to specify a reliability level or lossof load probability, such as an expected deficien-cy of 1 day in 10 years, and optimize capacityexpansion so that this criterion is always met (3 S).The accepted industry minimum value is about20 percent. In 1979, the average reserve marginfor IOUS was around 36 percent of peakload (20).Some utilities have reserve margins above so per-cent, while others are below 10 percent.

Once electricity has been generated, its voltageis stepped up with power transformers and it istransmitted to the load center. High-voltage trans-mission lines (69 kilovolts (kV) and above) areused to transfer bulk power from the generatingplant to a substation or bulk purchaser, and tointerconnect utility systems for greater efficien-cy and reliability. Such lines are built to accom-modate power flows in either direction in orderto facilitate interconnection among systems.

After the bulk power has been transmitted tothe demand center, it goes into the distributionsystem, which supplies electric energy to the in-dividual user or consumer. The distribution sys-tem includes the primary circuits and the distribu-tion substations that supply them; the distribu-tion transformers; the secondary circuits, in-cluding the services to the consumer; and ap-propriate protective and control devices (see fig.11). A transmission substation transforms powerto subtransmission voltage (below 69 kV). It isthen distributed to various distribution substa-tions, load substations, and distribution transform-ers, where the voltage is stepped down furtherto match residential, commercial, and industrialneeds. Once the electricity enters a local distribu-

Figure 11.—Typicai Eiectric Distribution System (three.phase)

From transmission

volt

Industrial Commercial Residentialor large load or rural

commercial loadload

SOURCE: McGraw-Hill Encyclopedla of Energy (New York: McGraw-Hill Book Co., 1976).

tion system, the power usually only flows oneway in order to protect electrical workers andequipment. Special equipment is thus needed foronsite generators that feed power back to the grid(see discussion of interconnection in ch. 4).

Economic and Regulatory Aspectsof Utility Systems

Electric utilities are among the most capital-intensive and highly regulated industries in theUnited States, and the two aspects of the industryare integrally related. The rates charged forservice-as determined by State or Federal reg-ulation—are the primary factor in utility eco-nomics. But the economics of electric powersupply and demand also may be affected by fi-nancing and its regulation as well as by regula-tion of utility services and operations. Theseaspects of utility regulation and their effects onthe production and consumption of electricity—and thus on the potential role of cogeneration—are discussed below.

UTILITY RATES

In exchange for the privilege of operating asa natural monopoly, utility practices are regulatedin the public interest. The primary form of suchregulation is the determination of the rates utilitiescan charge for their services. State public servicecommissions (PSCS) traditionally have controlledrates for intrastate sales of electricity, while theFederal Government has had jurisdiction oversales for resale in interstate commerce since 1935.

State Regulation .–Each of the States (exceptNebraska, where all electricity is supplied througha State-owned and operated utility system) hasa PSC established by law to regulate utilities. Thedegree of State regulation varies. Ail PSCS regulatethe rates of IOUS, while 19 commissions havesome authority over publicly owned utility rates,and 29 regulate cooperatives (30). Where the PSCdoes not have such authority, public utilities areself-regulating through the municipal or countygovernment.


Determining the rates a utility charges for itsservices is a two-step process. The PSC mustdecide first, how much money the utility needs(the revenue requirement) and second, howthose funds will be collected (the rate structureor rate schedule). A utility’s revenue requirementis the total number of dollars required to coverits operating expenses and to provide a fair prof-it. The revenue requirement is usually expressedin formula form as follows:

E + d + T + (V – D) R

revenue requirementoperating expensesannual depreciation expensetaxes, including income taxesgross valuation of the property servingthe publicaccrued depreciationrate of return (a percentage)rate base (net valuation)profit, expressed as earnings on therate base, plus interest on debt (53).

The rate schedule allocates the revenue re-quirement among a utility’s customers. The prob-lem of cost allocation arises because most elec-tricity is produced in jointly utilized equipmentand its cost must be assigned to the customerclasses involved (36). First, costs directly at-tributable to a particular class or customer (e.g.,the distribution line from a substation to a fac-

Figure 12.–Allocation

Total utility Costs are$ costs attributed

for a given to majoryear functions

tory) are identified and segregated. Second, theremaining costs are arranged so that they can beapportioned among the various groups of cus-tomers jointly responsible. Third, those costs aredistributed in accordance with some physicallymeasurable attribute of the customer class.

in accomplishing the last two steps, costs arearranged according to function (such as produc-tion, transmission, and distribution), and theneither assigned to demand, energy, or customercost categories, or simply classified as fixed orvariable (see fig. 12). Demand costs (the fixed ratebase and expense items related to peak or aver-age demand) are generally the most difficult toallocate and have become controversial in thesetting of rates for backup service to cogenerators(see discussion of rates in next section). Energycosts can be directly allocated to customer classesbased on the number of kilowatt-hours con-sumed by the group, and thus do not pose aproblem (36).

Federal Regulation.–Federal regulation ofelectricity prices began in 1920 with the authorityto set rates for interstate sales of power fromfederally licensed hydroelectric projects. Thefinancial abuses of the 1920’s and early 1930’s,however, revealed a need for a more extensivenational role, and the Federal Power Act of 1935expanded Federal jurisdiction to include all salesof electric energy at wholesale in interstate com-

of Electricity Costs

Costs are Costs aredivided into allocated to

three principal three classes ofcategories customers

SOURCE: Office of Technology Assessment.

merce. The States retained exclusive jurisdictionover intrastate and retail electricity sales untilpassage of the Public Utility Regulatory PoliciesAct of 1978 (PURPA), which required the FederalEnergy Regulatory Commission (FERC) to estab-lish standards for PSCS to consider in setting retailand certain wholesale rates (56).

The Federal Power Act of 1935 requires thatall rates and charges of any electric utility for thetransmission or sale of power subject to FERC(formerly FPC) jurisdiction be just and reasonableas well as nondiscriminatory. Each utility mustregularly file with FERC schedules that show suchrates and charges, and the classifications, prac-tices, and regulations that may affect them. FERCrate proceedings are similar to those of State com-missions: FERC first determines the utility’s rev-enue requirement and then approves a rateschedule designed to meet that requirement. Insuch proceedings, FERC traditionally has em-ployed the same cost-based formulae used byPSCs (3).

Although only about 10 percent of the reve-nues realized by IOUS are from wholesale trans-actions subject to Federal jurisdiction, FERC stillhas a broad opportunity to influence State rate-making. For example, States may be reluctant tointroduce innovative rate structures for fear ofplacing utilities within their jurisdiction at a com-petitive disadvantage. Innovation at the Federallevel can provide the experience necessary for

State adoption of innovative rate designs. More-over, FERC’S ability to examine cost trends andpricing practices on a regional or nationwide (asopposed to local) scale may reveal to States op-portunities for ensuring greater economy in elec-tric power supply.

FINANCING

The second major factor in utility economicsis financing of new generating capacity. Utilityfinancing options vary widely depending on theform of ownership, current economic conditions,the type of project being financed, and similarconsiderations. A summary of differences infinancing by form of ownership is shown in table12. The general considerations related to utilityfinancing of capacity additions are reviewed here;financing considerations specific to cogenerationwill be discussed in the following section.

Investor-Owned Utilities.– IOUS spend thelargest proportion of funds in the electric powerindustry (see table 10) and, based on announcedplans for capacity additions (table 13), their shareof funds is likely to remain large. IOUS have fourbasic options for securing those funds: long-termdebt, preferred stock, common stock, and re-tained earnings (see table 14).

The primary form of long-term debt financingfor IOUS is the mortgage bond, which is securedby a conditional lien on part or all of the com-

Table 12.—Differences in Financing by Form of Ownershipa

Average return toOwnership Capitalization Percent financing sources Tax treatment Financiability

Federal DebtRetained earningsFederal

Municipal DebtRetained earningsMunicipality

Cooperative:Distribution Dept

EquityG & T sb Debt

EquityInvestor owned Debt

PreferredCommonRetained earnings

27.89.1

63.17325.5

1.5

66 (1977)34 (1977)96 (1977)

2 (1977)50.312.524.912.3

7.25% (1977)

4.9

7.4 (1977)10.7 (1977)7.4 (1977)

10.7 (1977)11.859.76

11.3

Tax exempt FederalTaxed revenues

Interest on debt Electricexempt from taxes revenues or

municipality

Taxed Federal loansor guarantees,or members’shares

Taxed investors

a1979 data unless Indicated otherwlse.bGeneration and transmission.

SOURCE: Economlc Regulatory Adminlstration, The National Power Grid Study, Volume Il(Washlngton, D.C.: U.S. Department of Energy, DOE/ERA-0056-2, September 1979.

Ch 3—Context for Cogeneration ● 65

Table 13.–New Capacity Additions (in megawatts, net operating capacity)

Added Planned After Total1979 1980 1981 1982 1983 planned

Private . . . . . . . . . . . . . . . . 9,167 22,373 13,139 17,582 137,832 190,930Public . . . . . . . . . . . . . . . . . 2,945 17,444 26,448 1,488 20,793 26,563Cooperative . . . . . . . . . . . . 1,640 2,675 1,543 2,577 11,376 18,171Federal . . . . . . . . . . . . . . . . 3,323 3,315 3,322 1,891 19,376 27,904

Total . . . . . . . . . . . . . . . . 17,075 30,107 20,652 23,522 187,377 263,658SOURCE: Office of Technology Assessment from U.S. Department of Energy data.

Table 14.—Capital Structure for Private Utiiities (average percent of capitalization)

1966 1970 1974 1977 1978 1979 1960Long-term debt . . . . . . . . . . . . . 52.3 54.8 53.0 51.0 50.5 50.4 50.4Preferred stock . . . . . . . . . . . . . 9.5 9.8 12.2 12.5 12.4 12.5 12.3Common stock. . . . . . . . . . . . . . 26.1 23.2 23.5 24.2 24,8 25.0 25.4Retained earnings . . . . . . . . . . . 12.1 12.2 11.3 12.3 12.3 12.1 11.9SOURCE: Edison Eiectric institute, Stat/st/ca/ Yearbook of the Electric Ut///tY hxfustrx W&l(Waahin@on, D. C.: Edieon Eiec-. .

tric Institute, November”1981).

pany’s property. In 1980, approximately 50 per-cent of total average IOU capitalization was longterm debt. In the same year, IOUS issued around$8.3 billion in long term debt (or 58 percent oftheir 1980 long term financing), $7.85 billion ofwhich was new capital and the remainder refund-ing. For the last quarter of 1980, the average yieldon all IOU bonds was 14.11 percent, with a rangeof 13.18 percent for Aaa bonds to 15.20 percentfor Baa bonds. For newly issued bonds, the aver-age yield in 1980 was 13.46 percent (20).

Common stock equity represented about 25percent of electric utilities’ total outstandingcapitalization in 1980. iOUs issued approximately$4.1 billion of common stock in 1980, or around28 percent of the long term financing obtainedby IOUS during that year. The average yield oncommon stocks during 1980 was 12.01 percent.The actual return on average common equity was11.4 percent, while the authorized rate of returnaveraged around 14.2 percent (20).

Preferred stock was about 12 percent of totaloutstanding electric utility capitalization in 1980.In the same year, approximately $2.0 billion ofpreferred stock was issued by IOUS (or about 14percent of total 1980 long-term financing), withan average yield of 12.28 percent (20).

Finally, IOUS may use internally generatedcapital or retained earnings to finance capacity

additions. The amount of retained earnings avail-able for financing usually is reflected by the ratioof dividends to net income, or the payout ratio.IOUS have had to pay a major portion of theirnet profits in dividends in recent years (75.8 per-cent in 1980), reducing their ability to financeprojects internally. In 1980, retained earningswere the smallest source of capital available toutilities (about 12 percent of total capitalization)(20).

Publicly Owned Utilities.–Publicly ownedutilities’ advantages over IOUS in financing newcapacity include their smaller size and thus lowercapital needs, their self-regulating (in most cases)and tax-exempt status, and their absence of con-cern about protecting shareholders’ equity. Yet this does not mean that they are totally withoutfinancing problems.

As with lOUs, the predominant form of munici-pal utility financing is long-term debt (73 percentof total 1979 capitalization) —mostly electric rev-enue bonds or general obligation bonds. Munici-pal bonds are attractive to investors because oftheir tax-free interest, but their average yield islower as a result (4.9 percent in 1979). Equityfinancing for municipal utilities is a combinationof direct investment by the municipal governmentand the retained surplus from operating revenues.The retained surplus is extremely important for


municipal’ ability to build a base for expansion;it averages about 10 times the amount of directinvestment by the municipal government (18). In1979, retained earnings represented an averageof 25.5 percent of municipal’ total capitalization(25).

The primary sources of long-term financing forcooperatives are insured loans and loanguarantees from the Rural Electrification Ad-ministration (REA). REA makes insured loans tothe local distribution co-ops at interest rates of2 to 5 percent, based on a revolving fund thathas a borrowing “floor” and “ceiling” specifiedannually by Congress. Loans from the revolvingfund are repaid from borrowers’ operating reve-nues and from collections on outstanding REAloans (16). Since 1973, REA also has been author-ized to make 100-percent loan guarantees topower supply borrowers–mostly G&Ts–for theconstruction and operation of powerplants andrelated transmission facilities. These guaranteesare made almost entirely by the Federal Financ-ing Bank, which borrows money from the U.S.Treasury. In fiscal year 1981, 34 REA loanguarantee commitments were made to powersupply borrowers; they accounted for about 85percent of REA’s total fiscal year 1981 electricfinancing programs. Interest rates on REA loanguarantees averaged about 15 percent (45).

REA insured loans are supplemented by moneyraised by the National Rural Utilities CooperativeFinance Corp. (CFC) in the public bond market.Co-ops that receive REA insured loans are re-quired to obtain from 10 to 30 percent sup-plemental financing from non-REA sources suchas CFC (which is a giant nonprofit co-op ownedby about 85 percent of the rural electric co-ops).CFC bonds accounted for approximately 4 per-cent of all rural electric co-op financing in fiscalyear 1981 (see table 15).

Regulatory Considerations.–Almost all aspectsof utility finance are regulated at either the Stateor Federal level or both. As in rate regulation, theStates have primary jurisdiction over intrastateutility financial transactions while the FederalGovernment regulates interstate financing ar-rangements as well as those with antitrust impli-cations.

In general, State regulation focuses on priorapproval of IOU’S issuance of mortgage and de-benture bonds and other long-term debts (e.g.,notes over 1 year), and of common and preferredstock. Some PSCS also regulate declarations ofdividends and budgets for capital expenditures.For public utilities, the authority to issue bondsderives from the State constitution or statutoryauthority. In many cases, a municipality must alsoobtain voter approval before issuing new bonds.

Table 15.—Sources of Long-Term Financing to REA Electric Borrowers (percent byfiscal year)

REAguarantee Other

Year REA 20/0 REA 5°A commitments CFC financing Total1969 . . . . . . . . 100.0% — — — — 100.0 ’%01970 . . . . . . . . 100.0 — — — 100.01971 . . . . . . . . 96.6 — — 3.4% — 100.01972 . . . . . . . . 72.2 — — 15.3 12.5% 100.01973 . . . . . . . . 32.4 52.80/o — 13.6 100.01974. . . . . . . . 3.1 26.0 45.80/o 4.9 20.2% 100.01975. . . . . . . . 5.1 28.7 58.2 7.7 0.3 100.01976 . . . . . . . . 10.3 24.5 57.6 5.1 2.5 100.0TQ . . . . . . . . . 7.6 22.5 64.8 3.3 1.8 100.01977. . . . . . . . 5.3 11.4 77.9 2.9 2.5 100,01978. . . . . . . . 5.1 20.8 66.2 6.0 100.01979. . . . . . . . 3.3 11.5 80.5 3.7 0.9 100.01980. . . . . . . . 2.0 11.3 81.4 4,3 0.9 100.01981 . . . . . . . . 2.8 10.6 78.7 4.0 3.9 100.0SOURCE: U.S. Congress, Senate hearfngs before the Commlttee on Appropiations, “Agriculture, Rural Development, and Related

Agencies Appropriations,” fiscal year IWO, 9t3th Cong., 1s1 aaas., part l—juntlflcations; National Rural ElectrlcComparative Association, peraonat communication to the OffIce of Technology Asaaaament.


Federal jurisdiction over electric utility owner-ship and financial operations includes regulationof debt and equity financing of holding com-panies and their acquisition of other entities, salesand purchases of utility property, and the is-suance of securities by both the Securities andExchange Commission (SEC) and FERC. In gen-eral, SEC regulates holding companies* under thePublic Utility Holding Company Act of 1935(PUI-ICA) in order to simplify their structures andto prevent abuses similar to those that occurredduring the 1920’s. SEC also regulates IOUS underthe Securities and Exchange Commission Act of1935 to protect investors and the public by pro-viding accurate information about a wide rangeof factors that may affect a utility’s financial posi-tion, and thus the relative risks associated withinvestment in its securities. Finally, under the pro-visions of the Federal Power Act, no utility mayissue securities, or assume any financial obliga-tion or liability (e.g., as guarantor, endorser, sure-ty, etc.) with respect to securities, without author-ization from FERC. FERC also must approve anyutility sale, lease, or other disposition of proper-ty worth more than $50,000, as well as mergersor consolidations of such property, if it finds theyare reasonably necessary or appropriate for theutility’s corporate purposes, are in the public in-terest, and will not impair the utility’s ability toprovide service. Utilities may file the same reportson securities with both FERC and SEC in orderto eliminate unnecessary paperwork.

Taxation.–Like financing, utility tax liabilitydepends to a large extent on ownership. IOUSare fully liable for all taxes—income, excise, prop-erty, and sales as imposed by various levels ofgovernment–whereas Federal and municipalutilities usually are exempt from all tax liability.However, Federal and municipal utilities oftenmake payments to local governments in lieu ofproperty taxes (about 25 to 50 percent of theotherwise exempted taxes). Cooperatives general-ly are exempt from income and excise taxes butliable for property and sales taxes. In addition,

*Holding companies are defined in PUHCA as those that direct-ly or indirectly control 10 percent or more of the outstanding votingsecurities of a utility (or other holding company) or that, in the judg-ment of SEC, could exercise a controlling interest over the manage-ment or policies of a utility or holding company sufficient to makeregulation necessary in the public interest.

cooperatives that derive more than 15 percentof their total revenues from nonmember servicesare liable for income taxes. In 1980, tax paymentsby IOUS averaged 12.7 percent of electric depart-ment operating revenues (20). The tax break-down for 1980 is shown in table 16.

Taxation is primarily an issue in electric utilityfinance and regulation to the extent it allowsspecial treatment that will reduce the cost ofcapital investments. The primary forms of specialtax treatment are the investment tax credit andaccelerated cost recovery coupled with specialfederally mandated accounting rules.

The investment tax credit (ITC) encourages in-vestment in new, used, or leased business prop-erty that is placed in service after 1980 and thathas a useful life of at least 3 years. The propertymust be depreciable (i.e., either tangible personalproperty or an improvement to real property usedin qualifying manufacturing or service busi-nesses). Buildings and real property are specifical-ly excluded from eligibility. Since 1975, treatmentof utilities under ITC provisions has been roughlyequal to that of other businesses.

The amount of ITC depends on the acceleratedcost recovery (ACRS) for the property. Propertyin the 3-year ACRS class (cars, light trucks, andresearch and development equipment) is eligi-ble for a 6-percent credit, and all other propertyreceives a 10-percent credit. There is a $125,000limit for qualifying investments in used propertyfrom 1981 through 1984, and a $150,000 limitafter 1984. If the available investment tax credit

Table 16.—Taxes Paid by Investor-Owned ElectricUtilities–Electric Department Only, 1980

Amount Percent o f(millIons of operating

dollars) revenue

Federal taxes:Income . . . . . . . . . . . . . . . . . . . . . . . . . . . . $1,242 1.5 ”/0Deferred taxes on Income . . . . . . . . . . . 1,347 1.7Other charges In lieu of taxesa . . . . . . . 1,392 1.7Miscellaneous . . . . . . . . . . . . . . . . . . . . . . 1,492 1.9

Total Federal taxes charged to income . . 5,473 6.8State and Iooal taxes. . . . . . . . . . . . . . . . . . 4,795 5.9

Total taxes charged to income . . . . . . . $10,268 12.7%alncludes Investment tax cradlts reported as charges to income for the current

year.

SOURCE: Edison Electric Inatltute, Stat/st/ca/ Yearbook of the E/ac@/c Ut///ty /rr-dustry, 1980, (VWshlngton, D. C.: Edlaon Electric Inatltute, November19s1).


exceeds a taxpayer’s liability in any year, the ex-cess credit may be carried forward for 15 yearsor backward for 3 years.

In addition to the standard ITC, an extra 10-percent credit may be available for investmentsin certain qualifying energy property (see table17) through December 1982. This energy taxcredit is not available on that portion of an in-vestment which is financed by tax-exempt orother subsidized financing (e.g., industrial devel-opment bonds). Moreover, public utility property(with the exception of hydroelectric equipment)does not qualify for the energy tax credit. Otherthan the exceptions outlined above, the rules per-taining to the energy credit generally parallelthose for the ITC.

The ITC and energy credit represent a directreduction in tax liability (for those businesses withsufficient tax liability to benefit from it) that, in

Table 17.—Energy Property Eligible for ITC Underthe Energy Tax Act of 1978

recuperators,heat wheels,heat exchangers,waste heat boilers,heat pipes,automatic energy control systems,turbulators,preheater,combustible gas recovery systems,economizers, orother similar property defined in regulations,

4.

5.6.

the principal purpose of which is to reduce the amount ofenergy used in any existing industrial or commercial proc-ess and which is installed in an existing industrial or com-mercial facility.Equipment used to sort and prepare for recycling or to re-cycle solid waste.Equipment for extracting oil from shale.Equipment for producing natural gas from geopressurizedbrine.

SOURCE: OffIce of Technology Assessment.

effect, reduces the cost of equipment purchases.Thus, these credits decrease the amount of in-vestment capital needed without reducing thebasis for cost recovery purposes. At present,many electric utilities have accumulated largebacklogs of excess credits due to the percentageoffset limitations and the accompanying carry-back and carryforward provisions (see table 16).If State regulators allow utilities to retain thebenefits of the ITC, they usually are used to helpdefray the costs of construction of new generatingcapacity rather than passed on to customers im-mediately.

The second form of tax treatment that canreduce the cost of capital investments is ac-celerated cost recovery. The Internal RevenueCode allows a deduction for “the exhaustion,wear and tear (including a reasonable allowancefor obsolescence)” of business or investmentproperty. Accelerated cost recovery allows prop-erty to be written off before its useful life hasended, either by shortening the useful life or byconcentrating larger deductions in the early yearsof the asset’s useful life. Under the Economic Re-covery Tax Act of 1981 (ERTA), cogeneratorsplaced in service after December 31, 1980, wouldbe in a 5-year cost recovery class, while publicutility property would be in a 5-, 10- or 15-yearclass, depending on its depreciation class underthe previous tax laws.

In a competitive industry, much of the reducedcapital cost that results from accelerated costrecovery would be passed on to customers in theform of lower prices. With regulated utilities,however, the State commissions have had todecide whether the taxes incorporated into therevenue requirement should be only those ac-tually paid (i.e., the benefits of accelerated costrecovery are “flowed through” to customers inyears of tax savings) or whether the taxes shouldbe “normalized” over the life of the investment(i.e., the taxes included in the revenue require-ment will be higher than actual taxes in the earlyyears and lower in later years and the benefitsare retained by the utility). Under ERTA, a publicutility that wants to take advantage of ACRS andITC must use normalization accounting to com-pute the tax expense for ratemaking purposes.If the utility uses flow-through accounting it must

Ch. 3—Context for Cogenerafion ● 69

use the same cost recovery method for both taxand ratemaking purposes.

In 1976, accelerated cost recovery is estimatedto have reduced customer rates by about $1.3billion (2.2 percent) and utility tax payments byabout $2 billion (51 percent). The ITC reducedrates to a much smaller extent (perhaps $200million), but decreased utility taxes by $1.3billion. The combined effect was a 2.6-percentreduction in customer billings, an 84-percentdecrease in Federal tax payments by utilities, anda 20-percent ($2 billion) increase in the cash flowsof normalizing utilities. In 1979, it is estimatedthat tax incentives provided IOUS with $3 billionper year additional construction funds (equivalentto 15 percent of annual construction expendi-tures). In some cases, these tax incentives mayrepresent the only source of internal funds forutilities (1 5).

Other provisions of Federal tax law that pro-vide investment incentives for utilities include adeduction for interest paid to bondholders thatreduces the cost of debt financing; a deductionfor IOUS of about 30 percent of the dividendspaid on preferred stock; and, a deduction for thecosts of repairs or improvements to depreciableproperty based on a specified annual percentageof the property’s cost.

REGULATION OF SERVICE AND OPERATIONS

The third major area of electric utility regula-tion is State and Federal jurisdiction over utilityservice and operations. The primary concerns ofsuch regulation are to ensure adequate service,to protect the public health and welfare, and tofurther national policy goals related to fuel use.

Service Regulation.– State PSCS have broadauthority over utility services, including grantingthe right to serve, defining service territories, andapproving major capacity additions. The primarymechanism by which a PSC exerts control overthese activities is the certificate of public con-venience and necessity, which essentially is a per-mit to operate a utility. In addition, many PSCSalso have jurisdiction over the operating charac-teristics of private (and some public) utilities, in-cluding authorizing or requiring interconnections,requiring utilities to operate as common carriers,ordering the joint use of facilities among two ormore utilities, and requiring line extensions withina utility’s service territory (see table 18).

The Federal Government’s primary role in reg-ulating utility service is through its authority overinterconnection and coordination among utilities.Under section 202(a) of the Federal Power Actof 1935, FERC (formerly FPC) was directed to

Table 18.—State Regulation of Utiiity Service and Operations

Number of PSCS according to -

type of utility regulatedAuthority Investor-owned Public Co-opCertificate of convenience and necessity

required for:Generating capacity additions . . . . . . . . . . . . . . . . 25 9 15Transmission line additions. . . . . . . . . . . . . . . . . . 28 14 20Distribution system additions . . . . . . . . . . . . . . . . 20 11 13Other plant additions . . . . . . . . . . . . . . . . . . . . . . . 16 8 11Initiating service . . . . . . . . . . . . . . . . . . . . . . . . . . . 31 13 20Abandoning facilities or service . . . . . . . . . . . . . . 34 17 21

Regulate State exports . . . . . . . . . . . . . . . . . . . . . . . . 6 2 3Allocate unincorporated territory among utilities . 33 14 22Establish standards for:

Voltage levels. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41 17 24Safetv. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 44 21 26

alncludes w State commissions plus District of Columbia, Puerto Rico, and Vir9in Islands.

SOURCE: Alan E. Finder, The States and Electric Utility Regulation (Lexington, Ky.: The Council of State Governments, 1977).

70 ● lndustrial and Commercial Cogeneration

“divide the country into regional districts for thevoluntary interconnection and coordination offacilities for the generation, transmission, and saleof electric energy” in order to ensure an abun-dant supply of electricity throughout the UnitedStates “with the greatest possible economy andwith regard to the proper utilization and conser-vation of natural resources.” Once these districtswere established, the Federal Government’s rolewas limited to promoting and encouraging volun-tary interconnection and coordination of facilitieswithin and among them.

PURPA expanded FERC’S authority in regardto interconnection and coordination in a numberof ways. Section 205(a) of PURPA authorizesFERC (either on its own motion or upon receiptof an application) to exempt a utility from Statelaws, rules, or regulations that prohibit or pre-vent voluntary coordination, including agree-ments for central dispatch, if the coordination isdesigned to obtain the economic utilization offacilities and resources in any area. Section 205(b)directs FERC to study the opportunities for energyconservation, increased reliability, and greater ef-ficiency in the use of facilities and resourcesthrough pooling arrangements. Where such op-portunities exist, FERC may recommend to utili-ties that they voluntarily enter into negotiationsfor pooling. Finally, PURPA expanded FERC’S au-thority to order interconnections to include thosewith qualifying cogeneration and small powerproduction facilities, and to include wheelingorders. These provisions are discussed in detailin the next section.

Public Health and Welfare.–Regulation ofutility operations in the interests of protecting thepublic health and welfare focuses on safety stand-ards and on environmental protection. At theState level, the primary responsibilities includethe implementation of federally mandated pro-grams as well as the establishment and enforce-ment of minimum standards for voltage, meter-ing accuracy, customer and employee safety, andemergency situations and curtailments.

Such Federal legislation affects powerplantsiting and operation substantially through re-quirements for environmental impact assessmentsand pollution monitoring and control, as well as

through provisions that limit the available sitesfor large generating facilities. The most importantFederal programs in this area include:

The National Environmental Policy Act of7969 (NEPA), which requires all Federalagencies to include a detailed environmen-tal impact statement on every major Federalaction significantly affecting the quality of thehuman environment.The C/can Air Act sets National Ambient AirQuality Standards that are implementedthrough standards of performance for newstationary sources and guidelines for Statecontrol strategies for existing sources, andthrough guidelines for regulatory programsdesigned to improve air quality in non-attain-ment areas and to prevent degradation of airquality in clean air areas.The Clean Water Act imposes effluent limita-tions on quantities, rates, and concentrationsof chemical, physical, biological, and otherconstituents discharged into navigablewaters, and are implemented through am-bient water quality standards, effluent stand-ards for new and existing sources, standardsfor thermal discharges, and permit programs.The Resource Conservation and RecoveryAct of 1976 seeks to control the land disposalof solid wastes (e.g., fly and bottom ash,scrubber sludge) through a system of Stateplans and permits for solid waste disposal.The Atomic Energy Act, which includes com-prehensive licensing and permitting pro-cedures for both the construction and opera-tion of nuclear powerplants.The Occupational Safety and Health Act(OSHAJ which establishes standards for theprotection of workers, requires recordkeep-ing, and sets up a process for periodic in-spections and the filing of complaints.The Endangered Species Act of 1973, whichrequires that all Federal departments andagencies consult with the Secretary of the in-terior to ensure that actions authorized,funded, or carried out by them do not jeop-ardize the continued existence of thesespecies or result in the destruction or adversemodification of their habitat.The National Historic Preservation Act of1970 which requires all Federal agencies to


●

●

●

determine whether a proposed action willaffect a site or structure listed or eligible forlisting in the National Register and, if so, toobtain comments from the Advisory Coun-cil on Historic Preservation.The Fish and Wildlife Coordination Act of1970, under which Federal agencies mustconsult with the Department of the Interior’sFish and Wildlife Service and with the Stateagency having jurisdiction over fish andwildlife prior to taking any action potential-ly affecting surface waters.Army Corps of Engineers requirements thatall projects affecting navigable waters obtaina permit from the Corps.The Coastal Zone Management Act, whichrequires Federal agencies to obtain certifica-tion that proposed actions are consistentwith approved State programs.

Although this list of Federal programs is not all-inclusive, it offers a general idea of the scope oflaws and regulations that affect the siting, con-struction, and operation of central station gen-erating plants. These regulations can lengthen theIeadtime for siting and building a powerplant, re-quire technological and other environmental con-trols in plant design and operation, and imposesignificant monitoring and recordkeeping re-quirements during plant construction and opera-tion, all of which increase the direct costs of elec-tricity generation.

Regulation of Fuel Use.–Prior to 1973, thechoice of fuel for utility and industrial plants wasprimarily a matter of resource availability, eco-nomics, and convenience, as influenced by in-direct regulation through tax and environmen-tal laws, and price controls. Then, natural gasshortages and the 1973 oil embargo drasticallychanged the economic and supply considerationsof fuel use and introduced direct Federal regula-tion. The primary Federal regulations on fuel usethat affect utilities derive from the Fuel Use Act(FUA) and the Natural Gas Policy Act (NGPA),both part of the National Energy Act of 1978.

The primary purpose of FUA is to encouragegreater use of coal and other alternate fuels asthe primary energy source in utility, industrial,and commercial generation of electricity or ther-

mal energy, and thus to conserve oil and gas forother uses. To achieve these purposes, FUA pro-hibits the use of natural gas or petroleum as aprimary energy source in new electric pow-erplants and new major fuel-burning installa-tions* and provides that no new electricpowerplants may be constructed without thecapability to use coal or any other alternate fuelas a primary energy source. FUA also prohibitsexisting powerplants from using natural gas astheir primary energy source after 1990 and, inthe meantime, from switching from any other fuelto natural gas or from increasing the proportionof natural gas used as the primary energy source.Moreover, the Secretary of Energy can issue pro-hibition orders for the involuntary conversion ofexisting powerplants to coal or another alternatefuel if the owner or operator of the powerplantcommences the proceeding by filing an affirma-tive certification that the plant has the technicalcapability to use coal or another alternate fuel,or could have that capability without substantialphysical modification or reduction in rated ca-pacity, and it is financially feasible for the facili-ty to use coal or other non-premium fuels.

Through December 1980, FUA prohibition or-ders had been issued for 53 oil burning units–mostly powerplants—and another 13 units wereundergoing voluntary conversion to coal. In ad-dition, 33 powerplants and 15 major fuel-burninginstallations (MFBIs) are subject to outstandingconversion orders under an earlier law (theEnergy Supply and Environmental CoordinationAct of 1974). Together, these 114 units have thepotential to displace around 400,000 barrels (bbl)of oil per day (19).

FUA prohibitions are subject to a wide rangeof temporary and permanent exemptions. Thetemporary exemptions are granted for a periodof 5 years; some of these can be extended to atotal of 10 years but in no case beyond December31, 1994. The most widely used of these exemp-tions is a special public interest exemption for thetemporary use of natural gas in existing power-

*The provisions of FUA apply to powerplants and other ~tationavunits that have the design capability to consume any fuel at a heatinput rate of at least 100 MMBtu/hr or to a unit at a site that hasan aggregate heat input rate of at least 250 MMBtu/hr.


plants that would otherwise burn middle distil-lates or residual fuel oils. The 1,058 petitions forthis exemption that have been granted or are inprocess have the potential to displace 83,523bbl/day middle distillate, 323,825 bbl/day residualfuel oil with a sulfur content of 0.5 percent or less,and 236,950 bbl/day residual with greater than0.5 percent sulfur (or a total of 644,298 bbl/day)(19).

The actual effect of FUA on fuel use in existingand new powerplants and MFBIs is difficult todetermine without a case-by-case analysis. Theconsiderations imposed by the act must beviewed in the context of economic, technical,and managerial concerns. Absent a FUA prohibi-tion order or exemption request, it is not alwayspossible to identify the determining factor in elec-tric utilities’ fuel choice. Many energy analystsargue that it became cheaper to convert existingoil-fired plants to coal or to replace them withnew coal or nuclear plants when the price ofresidual fuel oil reached $30 to $40/bbl (2,46).However, the economics of displacing existingoil-fired capacity may be outweighed by utilities’financial problems and the costs of using alter-nate fuels. Thus, fully two-thirds of the capacitythat is economically feasible to convert has yetto be converted. Moreover, of the 66 units beingconverted under FUA, only 13 are doing so vol-untarily (i.e., without a prohibition order), andthose 13 represent only about 4 percent of thetotal potential oil displacement in the 66 units(19).

NGPA was designed to increase energy sup-plies while reducing domestic consumption. Ingeneral, the act distinguishes among a numberof different classes and categories of natural gasaccording to the date the gas is committed to in-terstate commerce, whether the well is onshoreor offshore, and the depth and location of thereservoir. Varying price schedules that wouldeventually lead to decontrol are established forthe different classes and categories. Theseschedules are supplemented with rules for alloca-tion and pricing of gas to final consumers. Resi-dential customers generally have first priority forsupplies under contract to interstate pipelines,with any remaining supplies spread through vari-ous lower priority commercial and industrial cus-

tomers. There are complicated resale price sched-ules for all customer classes, with the highestpriority generally being given the lowest of alloutstanding prices.

NGPA assigns the lowest priority industrial gasusers an incremental price equal to the new gaswellhead price plus regulated pipeline transpor-tation margins. This higher incremental price ismitigated through a ceiling determined by the al-ternative fuel oil price. In some areas, the ceil-ing is based on number two distillate fuel and inothers on residual fuel. Several users that other-wise would be subject to the higher incremen-tal prices are specifically exempted, includingsmall industrial boilers (using less than an averageof 300 MCF/day); agricultural uses for which alter-native fuels are not economic or available;schools, hospitals, and other institutions; electricutilities; and qualifying cogeneration facilitiesunder section 201 of PURPA.

Current Status of Electric Utilities

Economic, energy, and utility analysts agreeunanimously that the electric power industry—particularly the investor-owned portion-is introuble due to its deteriorating financial condi-tion (34,64). The symptoms are abundant, in-cluding declining real returns on equity and in-terest coverage, increased capital spending anddebt/equity financing combined with high divi-dends per share, high payout ratios, and lowmarket-to-book values. This situation representsa somewhat abrupt turnaround in the industry’sfinancial health. During the two decades from1945 to 1965, utilities accommodated rapid de-mand growth while continually lowering pricesby taking advantage of economies of scale ingeneration as well as greater efficiency intransmission and distribution. Capital expendi-tures remained relatively constant on a per-customer basis and utility costs actually declinedin some years although prices within the econ-omy in general were rising. Return on equity rosesteadily, most utilities had high bond ratings, andthe market-to-book ratio more than doubled.Moreover, during those two decades energy con-sumption in general moved in line with othereconomic activity as electricity demand grew at

Ch 3—Context for Cogeneration . 73

roughly twice the rate of the economy and farfaster than energy usage as a whole. The priceof electricity declined on an absolute basis as wellas relative to prices as a whole and to the priceof competing fuels (34).

However, 1965 is considered the watershedyear for the electric utility industry. In that year,stock prices, rate reductions, and interest cover-age ratios peaked, while a number of eventsreshaped utility capital investment such thatmoney spent would not necessarily lead to re-duced costs. For example, the Northeast blackoutrequired expenditures to improve reliability ofservice, but those expenditures would neitherreduce costs nor automatically be associated withincreased revenues. Similarly, the environmen-tal movement required capital expenditures thatdid not make plants more efficient or increasecapacity. The military buildup in Vietnam sig-naled the onset of high inflation rates and broughtconstruction delays and labor productivity prob-lems. Emerging natural gas shortages caused utili-ties to shift to more capital-intensive types of pow-erplants, including coal and nuclear fueled plants,that took longer to build, cost more, and operatedless efficiently (34).

As a result, capital spending accelerated, ratebase increased more rapidly than sales, and alarger percentage of financing requirements hadto be met through new capital (i.e., sales ofsecurities). The combination of rising interestrates, an increasing amount of debt, and relativelyslow growth in income resulted in decreasing in-terest coverage ratios and a decline in the quali-ty of utility debt, and thus even higher interestrates. The combination of higher interest ratesand lower return on equity pushed stock pricesdown until they fell well below book values. Theaverage market-to-book ratio went from an all-time high of 2.35 in 1965 to a low of 0.67 in 1974,and back up to 0.80 in 1978. Thus, during aperiod when securities were claiming an everlarger share of total capitalization, each new issuefurther diluted the interests of shareholders. Atthe same time, utilities began to capitalize anallowance for funds used during construction(AFUDC) in their income statements, which in-creased the non-cash portion of their reportedearnings. Therefore the overall decline in return

on equity was greater than was apparent fromthe reported figures. The only available solutionto the problem was to increase rates (34).

in 1970, the average price of residential elec-tricity increased for the first time in 25 years, andhas continued to rise ever since from its low of$.0209/kWh in 1969 to its high in 1980 of $.0493/kWh ($.0536/kWh for IOUS). * The averageprice of all electricity also has risen–from a lowof $.0154/kWh in 1969 to a high of $.0437/kWhin 1980 (4.72 WkWh for IOUS) (20). However,the rate relief obtained in the last 10 years hasbeen inadequate to raise interest coverage andreturn on equity to their previous levels and bondratings have fallen, increasing interest charges stillfurther. Moreover, although the price of electrici-ty did not increase as rapidly as those of com-peting fuels, it did go up more than prices as awhole throughout the economy.

The electric power industry’s problems up untilthe early 1970’s were compounded by other fac-tors during the last decade. First, the 1973-74 oilembargo drastically changed both fuel suppliesand prices, and utility customers cut back onelectricity consumption. In 1974, electric usageper customer decreased for the first time since1946, and the previously steady pattern of rapidgrowth (about 8 percent per year from 1947 to1972) changed dramatically.** But the industryhad geared its capital spending and its expensebudget to the previous sales gains. Capacity ad-ditions begun before 1974 became excess capaci-ty as these gains failed to materialize. Moreover,much of the new capacity installed or announcedin the years immediately preceding the embargowas oil-fired in response to environmental objec-tions to coal and to uncertainties in natural gassupplies. This decline in demand growth caughtutilities in a squeeze between high fixed costs anddeclining base rate revenue due to falling sales(34).

A second factor that dramatically affected utilityfortunes during the 1970’s was one utility’s omis-sion of a common stock dividend—a first for theutility industry-in April 1974. In that month, the

*Prices expressed in current dollars.* *while ele~rici~ demand growth has slowed noticeably, since

1973 it still has been about twice that of energy as a whole.


utility stock average fell 18 percent, and by Sep-tember had fallen 36 percent, the largest dropin any calendar year since 1937. Also, 1974 wasthe year that market-to-book ratios hit their lowof 0.67. The increased risk in utility stocks car-ried over to the market in lower quality bonds,and for the first time, investors had to considerthe possibility of a financial risk in utility securities,and utilities had to face the prospects of evenhigher costs for new capital (34).

A third major event affecting the electric powerindustry during the 1970’s was the accident atthe Three Mile Island (TMl) nuclear powerplantin 1979. Even before TMI, some investors hadbeen leery of nuclear-oriented utilities becauseof the huge sums involved in one project thatcould be delayed or halted by a determined op-position. The TMI accident added another risk–ifan operating nuclear plant went out of service,the power company might have to purchase farmore expensive electricity from other utilities. Ifthe regulators did not allow the purchased powercosts to be passed on to consumers, the utilitycould suffer serious financial losses. GeneralPublic Utilities, whose subsidiaries owned TMI,was forced to omit its dividend and was unableto place securities in the public market after theaccident. In conjunction with a weakened finan-cial state and excess generating capacity in manyareas, the accident accelerated the cancellationor deferral of nuclear projects by many electricutilities (34).

Based on some indicators, the general econom-ic and financial deterioration of the electric powerindustry that began in the late 1960’s and con-tinued through the 197o’s seems to have begunto turn around. Electric utility earnings began torise sharply in late 1980 and continued to increasethrough 1981. The gain in earnings lifted the aver-age return on equity (for a sample of 85 electricutilities representing 95 percent of IOU revenue)to 12.3 percent by September 1981 —the highestreturn earned since the late 1960’s. The propor-tion of capital spending financed with internallygenerated funds (including common equity) rosewith the return on equity, reaching 43 percentlate in 1981, entirely offsetting the decline thatoccurred during 1979 and early 1980 (63).

However, other indicators are not so favorable.Even though the earned rate of return has in-creased steadily in the last 2 years, it still lagsbehind the authorized return–estimated to beabout 14.2 percent in 1980. In addition, althoughoperating revenues have risen (by 18.3 percentin 1980) due to a combination of increases inrates, fuel adjustment clauses, and sales toultimate customers, the gains in revenues weremore than offset by increased operating expenses(up 19 percent in 1980), primarily due to higherfuel costs (20). Similarly, the increased percent-age of equity financing has not been sufficientto offset the record high interest rates. Utility in-terest expenses have continued to rise at morethan 20 percent annually while interest coverageratios (the ratio of net income and income taxesto interest expense) have remained relativelystatic for the last 2 years. In late 1981, the averageinterest coverage ratio was 2.47 with AFUDC, and2.01 without AFUDC. Common stock dividendpayout ratios have risen steadily, to a record 75.8percent in 1980 (compared to a traditional IOUpayout ratio of 65 to 68 percent). Finally, salesof stock have continued to dilute the book valueat a rate that more than offsets the contributionof retained earnings (63).

As long as interest rates remain high and earnedreturns on equity remain lower than authorized,utilities will continue to have trouble regainingtheir financial health. Without additional ag-gressive rate relief, growth in earnings is likely tocontinue to lag behind that of revenues. The highinterest rates would continue to favor equity fi-nancing over long-term debt, and thus continueto erode book value and increase payout ratiosto the detriment of stockholders’ interests. As aresult, IOUS are likely to continue having troublefinancing their construction budget.

Possibie Future Paths forthe Electric Power industry

A wide range of options are available to utilityplanners today, perhaps wider than at any timein the past. The menu of generating and othertechnologies from which to choose, the array ofinstitutional arrangements for financing andmanagement, the possibilities for investment on

the customer’s side of the meter—all have ex-panded greatly in recent years. All of these op-tions must be considered in the context of theirpotential to reduce utility dependence on oil andreduce capital expenditures and operating costs,while enabling utilities to continue to providereliable service and protect investors.

Given the numerous unpredictable events thathave plagued the electric power industry over thelast 15 years, utilities will have to develop planswith sufficient flexibility to handle a wide arrayof contingencies in demand growth, technologyavailability, and economic conditions. In manycases, these plans will be substantially differentin character from traditional planning, either dueto their approach to the size and mix of generat-ing technologies, or through planned controls onthe rate or type of demand growth.

One possible way to achieve such flexibility isfor a utility to diversify its energy mix. Thus, ratherthan being heavily dependent on any one fuel(e.g., coal, nuclear), the utility’s capacity wouldbe spread among the available options, reduc-ing the risk of a capacity shortfall in the event ofunexpected fuel shortages (e.g., a coal strike, anuclear accident). Second, utilities will have toplan for financing flexibility. Conventional largebaseload plants are extremely capital intensive.Because of their size, they often lead to short-term excess capacity until sales have a chanceto grow sufficiently to match the increasedcapacity. In addition, their long construction lead-times often mean high interest charges. As wasseen in the previous section, unless these largebaseload plants substantially increase system ef-ficiency and reduce utility costs, they can con-tribute significantly to financial deterioration.Smaller capacity increments, on the other hand,are easier to phase in as demand develops, andallow greater short-term financing flexibility. Inthis sense, the smaller additions substitute finan-cial optimization in planning for the engineeringoptimization achieved in large conventionalplants.

A third option for utility planners is to investin energy and fuel efficiency at the point of use.

As was seen in the discussion of the current statusof electric utilities above, one of the factors thatcontributed to current utility financial problemswas utilities’ need to make capital investments(e.g., for environmental protection, increasedsystem reliability) that neither reduced costs norserved new customers. Thus, overall system pro-ductivity declined as costs increased. In order toreverse this trend, some utilities are planning toinvest heavily in technologies that contribute tosystem efficiency (e.g., conservation, load man-agement) in lieu of new capacity.

Beyond these three major options, there areseveral other steps a utility can take to improveits financial position with regard to meeting futureservice needs. For example, joint action agencies(see discussion of utility organizations, above)allow a utility to benefit from economies of scalewhile also receiving the advantages of investmentin small capacity increments, including financialand planning flexibility. In some areas, conver-sion to public ownership may be an option forimproving utilities’ financial status, since public-ly owned utilities have access to lower cost capitaland do not need to be concerned with protect-ing stockholders’ interests.

However, utilities’ system and financial plan-ning is only one aspect of the future of the elec-tric power industry. Without appropriate regula-tion, many of the options discussed above willnot be feasible and even well-managed utilitiescould face financial and service dilemmas.

Utility regulators at all levels of government alsohave a wider range of options than has existedin the past. The problems faced by electric utilitieshave led to a better understanding of utility eco-nomics and its regulatory implications. The resulthas been a wide range of regulatory innovationsthat could complement utility planning for flex-ibility. But if regulators fail to take advantage ofsuch options, or to ensure that utilities are com-pensated adequately for the increased risks theywill be facing, even the most innovative utilityplanning will be to no avail.


REGULATION AND FINANCING OF COGENERATION

Historically, cogenerators faced three major in-stitutional obstacles when seeking interconnectedoperation with an electric utility. First, utilitiesoften were reluctant to purchase cogeneratedelectricity at a rate that made interconnectedcogeneration economically feasible. Second,some utilities charged very high rates for pro-viding backup service to cogenerators. Third, acogenerator that sold electricity risked beingclassified as—and therefore being regulated underState and Federal law as–an electric utility. Asa result of these and other disincentives, cogen-eration was not able to compete, except in largestand-alone industrial applications, with electrici-ty generated in central station powerplants plusthermal energy from conventional combustionsystems.

In recent years, however, cogeneration has at-tracted a lot of attention as a means of increas-ing energy efficiency, easing utilities’ financialstress, and reducing the amount of oil neededto supply electric and thermal power to buildingsand industries. Where these benefits are available(see chs. 5 and 6), recent changes in Federal andState regulation and in financing practices mayimprove cogeneration’s ability to compete withconventional energy conversion systems. Thissection describes the regulatory and financingconsiderations that may affect utility, industrial,or commercial firms’ decisions to install cogen-eration capacity.

Federal and State Regulation

A number of recent legislative initiatives are in-tended to clarify the role of cogeneration withinnational energy and environmental policy, andto encourage its use under those circumstanceswhere it would save fuel or allow increased effi-ciency in electric utilities’ use of facilities andresources. The most significant of these initiativesinclude PURPA which provides guidelines for re-lations among cogenerators, utilities, and regu-lators; other parts of the National Energy Act thataddress the use and cost of premium fuels; andprovisions of various environmental regulationsthat have been adapted to cogeneration’s specialproblems and opportunities.

The Public Utility Regulatory Policies Act

Title Ii of PURPA was designed to remove thethree obstacles to interconnected cogenerationlisted above. Under section 210 of PURPA, util-ities are required to purchase electricity from, andprovide backup service to, cogenerators (andsmall power producers) at rates that are just andreasonable, that are in the public interest, andthat do not discriminate against cogenerators.Section 210 also allows FERC to exempt cogen-erators from state regulation of utility rates andfinancial organization, and from Federal regula-tion under the Federal Power Act and PUHCA.Electric utilities also are required to interconnectwith qualifying facilities and must offer to operatein parallel with them. In order to qualify for theseand other benefits available under PURPA, co-generators must meet the requirements of sec-tion 201 for operating characteristics, fuel use,and ownership.

At this time, the fate of the PURPA provisionsis unclear. In January 1982, the U.S. Court of Ap-peals for the District of Columbia Circuit ruledthat portions of the FERC regulations imple-menting PURPA were invalid. Specifically, the ap-peals court vacated the FERC rules on rates forutility purchases of cogenerated power, and oninterconnections between utilities and cogen-erators, but upheld the FERC regulations on fueluse and on simultaneous purchase and sale (1).The Supreme Court has agreed to review the ap-peals court decision.

As a result of this pending case, it is not possi-ble to say definitively what is the Federal policyon cogeneration. Therefore this section will out-line the statutory provisions of PURPA and theFERC rules implementing those provisions, andwill review the relevant court rulings and theireffect on PURPA’S implementation.

REQUIREMENTS FOR QUALIFICATION

The benefits of PURPA are afforded only to“qualifying facilities.” Section 201 defines a quali-fying cogeneration facility as one that produceselectricity and steam or other forms of useful ther-mal energy for industrial, commercial, heating,

Ch 3—Context fo r Cogeneration-” 77

or cooling purposes; that meets the operating re-quirements prescribed by FERC (such as require-ments respecting minimum size, fuel use, and fuelefficiency); and that is owned by a person notprimarily engaged in the generation or sale ofelectric power (other than cogenerated power).

Ownership Criteria. –The conference reporton PURPA makes it clear that Congress did notintend to preclude electric utilities altogether fromparticipation in qualifying facilities (14). Thus,either directly or through a subsidiary company,an electric utility can participate in the owner-ship of a qualifying cogenerator. Rather, the thrustof the ownership requirement is to limit the ad-vantages of qualifying status to cogenerators thatare not owned primarily by electric utilities ortheir subsidiaries. Under the FERC rules imple-menting section 201, the legal test is whethermore than 50 percent of the entity that owns thefacility is comprised of electric utilities or publicutility holding companies (70). This ownershiplimitation does not apply to gas or other utilities.

Efficiency and Operating Standards.–TheFERC regulations require topping cycle cogenera-tion facilities to meet both operating and efficien-cy standards. Because “token” topping cycle fa-cilities could produce “trivial amounts of eitheruseful heat or power,” an operating standardwas established to distinguish bona fide cogen-erators from essentially single purpose facilities.This standard specifies that at least 5 percent ofa topping cycle cogenerator’s total energy out-put (on an annual basis) must be useful thermalenergy (69). There is no operating standard forbottoming cycle plants because they produceelectricity from otherwise wasted heat, and thusdo not have the same potential for “token” pro-duction.

The topping cycle efficiency standard is de-signed to ensure that an oil- or natural gas-firedcogenerator will use these fuels more efficientlythan any combination of separately generatedelectric and thermal energy using efficient state-of-the-art technology (e.g., a 8,500-Btu/kWh com-bined-cycle generating station and a 90-percentefficient process steam boiler). The efficiencystandard established by FERC specifies that, fortopping cycle cogenerators: 1) for which any of

the energy input is oil or natural gas; and 2) forwhich installation began on or after March 13,1980, the useful electric power output plus one-half the useful thermal energy produced must be,during any calendar year, no less than 42.5 per-cent of the energy input of oil and natural gas.However, if the useful thermal energy output isless than 15 percent of the total energy produc-tion, the useful electricity output plus one-halfthe useful thermal energy production must be noless than 45 percent of the total oil or gas input.Topping cycle cogenerators that were installedprior to March 13, 1980, and those that use fuelsother than oil and gas do not have to meet anyefficiency standards in order to qualify underPURPA (69).

The 2-to-1 weighting in favor of electricity pro-duction in these topping cycle efficiency stand-ards reflects FERC’S view that “systems with highelectricity to heat ratios have the highest second-Iaw’ energy efficiencies,” and their developmentand use should be encouraged (see discussionof the thermodynamic efficiency of cogeneratorsin ch. 4) (76). This weighting will be moreequitable to the various cogeneration technolo-gies than a standard that simply summed elec-tric and thermal output on an equal basis, be-cause the latter would have made it relativelyeasy for steam turbines that produce little elec-tricity to qualify, but would have penalized higherE/S ratio systems through difficult heat recoveryrequirements.

Because bottoming cycle facilities produceelectricity from normally wasted heat, the effi-ciency standard only applies to those with sup-plementary firing heat inputs from oil and naturalgas. In such facilities, the useful output of the bot-toming cycle must, during any calendar year, beno less than 45 percent of the energy input ofnatural gas or oil for supplementary firing (i.e.,the fuels used in the thermal process “upstream”from the facility’s power production system arenot considered in the efficiency test) (69).

Environmental Criteria.– FERC’S original re-quirements for qualification under PURPA deniedqualifying status to diesel and dual fuelcogenerators built after March 13, 1980, pendingenvironmental review. FERC’S final environmen-


tal impact statement (FEIS), released in April 1981,acknowledged that “an increase in the numberof diesel and dual-fuel cogeneration facilities inan air regime may cause significant environmen-tal effects in the near term.” But the FEIS con-cluded that existing State and local air qualitymonitoring and permit programs would be ade-quate to prevent such effects, and “unregulatedproliferation of diesel and dual-fuel cogeneratorsis not a realistic scenario.” Based on these con-clusions, FERC has declared diesel and dual-fuelcogenerators eligible for PURPA benefits (28).

Fuel Use Limitations.—Section 201 of PURPAspecifies that a qualifying cogeneration facilitymust meet “such requirements (including re-quirements respecting minimum size, fuel use,and fuel efficiency) as the Commission may, byrule, prescribe.” In implementing this section,FERC interpreted the statutory language as discre-tionary and chose not to impose fuel use limita-tions on qualifying cogenerators. FERC offeredfour arguments to support their position that thisdecision was consistent with congressional intentand national energy policy. First, FERC reasonedthat if Congress had intended to deny qualifyingstatus to oil- and gas-fueled cogenerators, PURPAwould have contained explicit restrictions on fueluse similar to those that apply to small power pro-ducers. Second, Congress did include fuel userestrictions on oil- and gas-fired cogenerators inFUA, which was enacted at the same time asPURPA. Therefore, FERC determined it would beboth unnecessary and inappropriate to imposean additional set of fuel use regulations underPURPA. Third, FERC argued that Congress rec-ognized that qualifying cogenerators would burnnatural gas by expressly exempting such facilitiesfrom the incremental pricing program underNGPA (enacted at the same time as PURPA).Fourth, FERC noted that the findings in section2 of PURPA require “a program providing for . . .increased efficiency in the use of facilities andresources.” Thus, the commission argued that oiland gas burning cogenerators should be grantedqualifying status to the extent that they providefor more efficient use of these resources, and theefficiency standards discussed above would besufficient to ensure such use (76).

FERC’S decision was upheld by the U.S. Courtof Appeals, which agreed with these four argu-ments and held that the statutory language isdiscretionary and that the regulations promul-gated by FERC were a reasoned and adequateresponse to the congressional mandate.

UTILITY OBLIGATIONS TOQUALIFYING FACILITIES

Under section 210 of PURPA and the FERC reg-ulations implementing that section, electricutilities have a number of obligations to qualify-ing cogenerators. These include the requirementthat utilities offer to purchase power from andsell power to cogenerators at equitable rates (in-cluding simultaneous purchase and sale), thatthey offer to operate in parallel with cogenerators,and that they interconnect with cogenerators.

Obligation to Purchase.–Section 210 ofPURPA requires FERC to establish “such rules asit determines necessary to encourage cogenera-tion,” including rules that require electric utilitiesto offer to purchase electric power from cogen-erators. FERC interprets this provision as impos-ing on electric utilities an obligation to purchaseall electric energy and capacity made availablefrom qualifying facilities (QFs) with which theelectric utility is directly or indirectly intercon-nected, except during system emergencies orduring “light loading periods” (see below) (75).

PURPA specifies that purchase power ratesmust be just and reasonable to the electricutilities’ consumers and in the public interest, andmust not exceed the incremental cost to the utilityof alternative electric energy. The FERC regula-tions use the term “avoided costs” to representthese incremental costs, and define them as:

The incremental costs to an electric utility ofelectric energy or capacity or both which, butfor the purchase from the qualifying facility, suchutility would generate itself or purchase fromanother source (68).

The energy costs referred to in this definitionare the variable costs associated with the produc-tion of electricity, and include the cost of fuel andsome operating and maintenance expenses (see

discussion of rate structures in the previous sec-tion). Capacity costs are the costs associated withproviding the capability to deliver energy; theyconsist primarily of the capital costs of generatingand other facilities (75). Thus, if by purchasingelectricity from a qualifying facility, a utility canreduce its energy costs or can avoid purchasingenergy from another utility, the rate for the pur-chase from the QF must be based on those ener-gy costs that the utility can thereby avoid. Similar-ly, if a QF offers energy of sufficient reliability andwith sufficient legally enforceable guarantees ofdeliverability to permit the purchasing utility tobuild a smaller less expensive plant, avoid theneed to construct a generating unit, or reducefirm power purchases from the grid, then the pur-chase rates must be based on both the avoidedcapacity and energy costs (75). In each case, itis the incremental costs, and not the average orembedded system costs, that are used to deter-mine avoided costs.

One way of figuring the avoided cost is to cal-culate the difference between: 1 ) the total capaci-ty and energy costs that would be incurred bya utility to meet a specified demand, and 2) thecost the utility would incur if it purchased energyor capacity or both from a QF to meet part ofits demand and supplied its remaining needs fromits own facilities. In this case, the avoided costsare the excess of the total capacity and energycost of the system developed in accordance withthe utility’s optimal capacity expansion plan ex-cluding the QF, over the same total capacity andenergy cost of the system including the QF (75).The FERC rules require utilities to furnish dataconcerning present and anticipated future systemcosts of energy and capacity to enable potentialcogenerators to estimate avoided costs.

The FERC rules outlined three primary consid-erations in determining avoided costs. The firstis the availability of capacity or energy from aQF during system daily and seasonal peakloads.If a QF can provide electricity during peak periodswhen the utility is running its most expensive gen-erating units, the electricity from the QF will havea higher value to the utility than power suppliedduring off-peak periods when only lower costunits are running. The relevant factors in deter-mining the QF’s availability include:

The utility’s ability to dispatch the cogener-ator will enhance its ability to respond tochanges in demand and thereby enhancethe value of the cogenerated power (see dis-cussion of interconnection in ch. 4).The expected or demonstrated reliability ofthe cogenerator (i.e., whether it may go outof service during the period when the utili-ty needs its power to meet system demand)will determine whether the utility can avoidthe construction or purchase of alternativecapacity.The terms of any contractor other legally en-forceable obligation (including its duration,termination notice requirements, and sanc-tions for noncompliance) also will providea measure of the QF’s reliability.If maintenance of the QF can be scheduledduring the periods of low demand on theutility system or during periods when theutility’s own capacity will be adequate tohandle existing demand, it will enable theutility to avoid the expenses associated withproviding an equivalent amount of capaci-ty on peak.If the QF can provide capacity and energyduring system emergencies, and canseparate its load from its generation duringsuch an emergency, it may increase overallsystem reliability and thereby enhance thevalue of the cogenerated power.The aggregate or collective value of capaci-ty from a number of small QFs may be suffi-cient to enable a purchasing utility to deferor avoid scheduled capacity additions whennone of the QFs alone would provide theequivalent of firm power to the utility.The Ieadtimes associated with capacity ad-ditions from QFs maybe less than the lead-time required for a utility powerplant, andthus the QF might provide savings in the utili-ty’s total power production costs by permit-ting utilities to avoid the excess capacityassociated with adding large generating unitsor by providing greater flexibility in accom-modating changes in demand (see ch. 6)(72).

The second consideration in a State regulatorycommission’s determination of avoided costsunder the FERC rules is the relationship of energy


or capacity from a QF to the purchasing utili-ty’s need for such energy or capacity. If an elec-tric utility has sufficient capacity to meet its de-mand, and is not planning to add new capacity,then the availability of capacity from a cogen-erator will not immediately enable the utility toavoid any capacity costs. However, a utility withexcess capacity may plan to build new plants inorder to increase system efficiency or reduce oiland gas use. If purchases from a QF allow theutility to defer or avoid these capacity additions,the rate for such purchases should reflect theseavoided capacity costs as adjusted for the lowerenergy costs the utility would have incurred if ithad added the new capacity (75), That is, if defer-ring new construction may actually increasepower costs, the qualifying facility may be cred-ited only with the net of the deferred and in-creased costs.

Third, the utilities and State commissions musttake into account any costs or savings fromtransmission line losses. Power produced by aQF maybe nearer to or farther from the servicearea than the utility-generated power it supplants.Because all power is subject to transmission lossesas a function of distance, the rate for energy pro-vided by the QF is to be net of line losses or gains.

In general, avoided costs are determined ona case-by-case basis. However, for small QFs, in-dividualized rates may have very high transac-tion costs. Therefore, the FERC rules requireutilities to implement standardized tariffs forfacilities of 100-kW electrical capacity or less, andpermit the use of such tariffs for larger units. Thesetariffs must be based on the purchasing utility’savoided cost, as described above, but may dif-ferentiate among QFs on the basis of the supplycharacteristics of the particular technology (72).

The net avoided cost concept leads to the pos-sibility that, despite their inherent efficiencies,QFs may at times produce power that is moreexpensive than power produced by the utility(e.g., when the utility is under a low load situa-tion and operating only baseload plants). Thus,if the utility has to reduce its baseload plant out-put in order to accommodate power purchasesfrom a QF, it may also have to utilize higher costpeaking units when load increases or supplies

from qualifying facilities drop, due to the longerstartup times of baseload plants. A strict applica-tion of the avoided cost rules under such cir-cumstances would mean a negative avoided costthat would have to be reimbursed by the QF. Toavoid the anomalous result of forcing a cogen-erator to pay a utility for purchasing cogeneratedpower, the FERC rules provide that an electricutility is not required to purchase power from aQF when such a purchase would result in net in-creased operating costs to the utility. A utility thatwants to cease purchasing from a QF due to theseoperational circumstances must notify each af-fected QF in time for the QF to stop deliveringenergy or capacity. If the utility fails to provideadequate notice of a light loading period, it mustreimburse the QF for energy and/or capacity asif the light loading had not occurred. The ex-istence of a light loading period is subject toverification by the PSC (75).

The FERC rules for purchase power rates do notpreclude negotiated agreements between cogen-erators and electric utilities on terms that differfrom the PURPA provisions. However, a QF thatneeds a long-term contract to provide certaintyin return on investment can still obtain a purchaserate based on the utility’s avoided costs, eitherby establishing a fixed contract price for energyand capacity at the avoided costs at the time ofthe contract or arranging to receive the avoidedcosts determined at the time of power delivery(75).

Finally, the FERC rules do not preclude Statesenacting laws or regulations that provide for pur-chase power rates that are higher than those thatwould obtain under PURPA. However, the Statescannot require rates at less than full avoided costsbecause such lower rates would fail to providethe requisite encouragement to cogeneration andsmall power production (75).

As mentioned previously, the FERC rules forpurchase power rates were challenged by theAmerican Electric Power Service Corp. (AEP) andseveral other electric utilities, who argued thatFERC’S requirement that purchase power ratesequal the utility’s full avoided costs forecloses thesharing of any of the benefits of the purchase withthe utility’s other customers, and thus contra-

venes the PURPA section 210 requirement thatsuch rates be “just and reasonable to the elec-tric consumers of the electric utility and in thepublic interest.” The U.S. Court of Appeals forthe District of Columbia Circuit held that Con-gress, in the statute, had clearly distinguished be-tween a “just and reasonable” rate and onebased on the full avoided cost, and that, although“the two may coincide,” FERC had not adequate-ly justified its adoption of a uniform full avoidedcost standard (1).

In the preamble to its final rule on purchasepower rates, FERC states that:

The Commission interprets its mandate undersection 21 O(a) to prescribe “such rules as it deter-mines necessary to encourage cogeneration andsmall power production . . . “ to mean that thetotal costs to the utility and the rates to its othercustomers should not be greater than they wouldhave been had the utility not made the purchasefrom the qualifying facility (75).

FERC considered several alternative standardsthat would have set the purchase rate at less thanfull avoided cost, including rate standards basedon a fixed percentage of avoided costs and ona “split-the-savings” approach. The commissionnoted that these pricing mechanisms would trans-fer to the utility’s ratepayers a portion of the sav-ings represented by the difference between theQF’s costs and those of the utility, and thus wouldprovide an incentive for the utility to purchasecogenerated power (75). The same argument wasmade by California utilities in opposing purchasepower payments based on full avoided costs, butrejected by the Public Utilities Commission (seediscussion of PURPA implementation, below)(lo).

However, FERC argued that, in most instances,the resulting rate reductions would be insignifi-cant for individual ratepayers, while if the full sav-ings were allocated to the QF they would pro-vide a significant incentive to cogenerate. Further-more, FERC felt that a “split-the-savings” ap-proach would require a determination of thecosts of power production in a QF—exactly thesort of cost-of-service regulation from which QFsare exempt under PURPA. FERC also argued thata fixed percentage standard would lead QFs to

stop producing additional units of energy whentheir costs exceeded the price to be paid by theutility, and thus could force the utility to operateless efficient generating units or consume morepremium fuels (l).

Based on these considerations, FERC deter-mined that only a rate for purchases that equalsthe utility’s full avoided costs for energy andcapacity would simultaneously satisfy the stat-utory requirements that the rate be just andreasonable to ratepayers, in the public interest,and not discriminate against QFs, and fulfill thestatutory mandate to encourage cogeneration.

The Court of Appeals ruled that FERC had ap-propriately rejected the split-the-savings approachbecause that would “veer toward the public utili-ties-style rate setting that Congress wanted toavoid” (1). However, the court recognized thatother alternatives to the full avoided cost stand-ard might allocate benefits between cogeneratorsand utilities more evenly without requiring an in-quiry into the QF’s production costs, and thatFERC should take a harder look at these alter-native approaches. In particular, the court statedthat FERC should reconsider the percentage ofavoided cost approach to determine whether itwould disproportionately discourage cogenera-tion. The court argued that the “bare unquan-tified possibility that a rule permitting rates at lessthan full cost might be insufficient to encouragethe last kilowatthour of cogeneration” is incon-sistent with the clear intent of PURPA, whichseeks to strike a balance among the interests ofcogenerators, electricity consumers, and thepublic (l).

The court also outlined several additional waysthat the avoided cost standard could disadvan-tage utility ratepayers, and specified that FERCshould address these in its subsequent rulemak-ing. First, the commission should take into ac-count, if possible, elements of utilities’ avoidedcosts that cogenerators would not also have topay (e.g., where the utility is subject to higherpollution control standards than a cogenerator,when a utility pays taxes at a higher rate thancogenerators). Second, FERC should consider autility’s capacity situation. If a utility has excess


capacity, cogeneration stimulated by full avoided cost payments may result in higher rates for the utility’s remaining customers (without increasing the utility’s total costs) due to the fixed cost -declining demand situation, in which the cogenerator reduces the number of customer-purchased kilowatt-hours over which the utility can spread a share of the fixed costs of the extra capacity (see ch. 6). Third, the full avoided coststandard precludes consideration of competitivemarket forces, that might encourage utilities topurchase a substantial amount of cogeneratedpower at a price lower than the statutory ceiling ( l ) .

As a result of all of the above considerations, the court held that FERC had not adequately justified its decision to prohibit any purchase power rates below full avoided costs, and vacated the FERC rate regulations and remanded the matter to the commission. However, the court emphasized that its holding:

. . . should not be read as requiring FERC to es-tablish different standards for a variety of cogen-eration cases and methods. A general rule is ac-ceptable, but the Commission must justify andexplain it fully, particularly in its balancing of theinterests of cogenerators, the public interest, and“electric consumers” (l).

As noted above, the U.S. Supreme Court has agreed to review the appeals court decision.

The purchasing utility normally will be the one with which a cogenerator is directly interconnected (i.e., the “local” electric utility). In some instances, however, either the cogenerator or its local utility may prefer that a second, more distant electric utility purchase the cogenerator’s energy and/or capacity. For example, if the local utility has no generating capacity, its avoided cost will be the price of bulk purchased power, which ordinarily is based on the average embedded capacity cost and the average energy cost on the supplying utility’s system. But if the QF’s output were purchased by the supplying utility directly, that output usually would replace the highest cost energy on the supplying utility’s system at the time of the purchase, and the QF’s capacity may enable the supplying utility to avoid adding new generating plants. Thus, the avoided costs

of the supplying utility may be higher than thoseof the local nongenerating utility.

Similarly, if the local utility has excess gener-ating capacity and/or relatively inexpensive coalor other alternate-fueled baseload generation, itsavoided energy costs could be quite low and itmay not have any avoided capacity costs. Aneighboring utility, however, may have excessload or expensive oil-fired baseload plants, andthus relatively high avoided costs.

For circumstances such as these, the FERC rulesprovide that a utility that receives energy orcapacity from a QF may, with the consent of theQF, transmit that energy or capacity to a secondutility. However, if the QF does not consent totransmission to another utility, the local utility re-tains the purchase obligation. Similarly, if thelocal utility does not agree to transmit the QF’senergy or capacity, it retains the purchase obliga-tion. Because the transmission can only occurwith the consent of the utility to which the energyor capacity is first delivered, this rule does notconstitute forced wheeling of power (75).

The FERC rule on transmission of cogeneratedpower to other utilities specifies that any electricutility to which such energy or capacity is deliv-ered must purchase that energy or capacity underthe same obligations and at the same rates as ifthe purchase were made directly from the QF.As discussed above, these rates should take intoaccount any transmission losses or gains. If theelectricity from the QF actually travels across thetransmitting utility’s system, the amount of energydelivered will be less than that transmitted, dueto line losses, and the purchase rate should reflectthese losses. Alternatively, the transmission canbe fictionalized (as in simultaneous purchases andsales—see below). For instance, energy and/orcapacity from a cogenerator may displace bulkpower that would have been purchased by a non-generating utility, as in the example cited above.In this case, the energy from the QF may replacea greater amount of energy than would havebeen purchased from the supplying utility (sincethe power from the latter is subject to greater linelosses than the power from the QF), and the pur-chase rate should reflect the net transmission gain(72).


obligation to SeIl.–Section 210(a) of PURPAalso requires that each electric utility offer to sellelectric energy to QFs. The FERC regulations in-terpret this obligation as requiring utilities to pro-vide four classes of service to QFs: supplemen-tary power, which is energy or capacity used bya QF in addition to that which it generates itself;interruptible power, which is energy or capaci-ty that is subject to interruption by the utilityunder specified conditions, and is normally pro-vided at a lower rate than non interruptible serv-ice if it enables the utility to reduce peakloads;maintenance power, which is energy or capaci-ty supplied during scheduled outages of the QF–presumably during periods when the utility’sother load is low; and backup power, forunsceduled outages (e.g., during equipment fail-ure). A utility may avoid providing any of thesefour classes of service only if it convinces the PSCthat compliance would impair its ability to renderadequate service or would place an undue bur-den on the electric utility (73).

PURPA requires that rates for sales of thesefour classes of service be “just and reasonableand in the public interest, ” and that they notdiscriminate against QFs. The FERC regulationsimplementing this requirement contemplate theformulation of rates based on traditional cost-of-service concepts (see discussion of rate regula-tion in the previous section), and specify that ratesfor sales to QFs shall be deemed nondiscrimina-tory to the extent that they apply to a utility’s non-cogenerating customers with similar load or othercost-related characteristics (73).

Thus, the FERC rules provide that rates for salesof power to QFs must reflect the probability thatthe facility will (or will not) contribute to the needfor and use of utility capacity. If the utility mustreserve capacity to provide service to a cogener-ator, the costs associated with that capacity maybe recovered from the cogenerator if the utilitynormally would assess these costs to noncogen-erating customers. If the utility can demonstrate,based on accurate data and consistent system-wide costing principles, that the rate that wouldbe charged to a comparable non-cogeneratingcustomer is not appropriate, the utility mayestablish separate rates for QFs according to thesedata and costing principles. However, any such

separate rates must still be nondiscriminatory, sothat the cogenerator is not “singled out to loseany interclass or intraclass subsidies to which itmight have been entitled had it not generatedpart of its electric energy needs itself” (73).

The FERC regulations also specify that rates forsales of backup and maintenance power may notbe based, without adequate supporting data, onthe assumption that all QFs will experience forcedoutages or other reductions in output eithersimultaneously or during the system peak. Thus,QFs are to be credited for either interclass or in-traclass diversity to the same extent as non-cogenerating customers, because such diversitywill mean that utilities supplying backup ormaintenance power to QFs probably will notneed to reserve capacity on a one-to-one basis.In addition, rates for backup and maintenancepower must take into account the extent to whicha QF can usefully coordinate maintenance withthe utility (74).

Simultaneous Purchase and Sale.–The FERCregulations specify that a utility must offer to pur-chase all of a cogenerator’s electric power out-put at avoided cost rates regardless of whetherthat utility simultaneously sells power to the QFat standard retail rates (72). In effect, this ruleseparates the electricity production and con-sumption aspects of QFs, and thus equalizes thetreatment of facilities which consume all thepower they generate with that of cogeneratorswhich sell some or all of their power (75).

AEP, et al., challenged this rule on the groundsthat it misconstrued the statutory terms “pur-chase” and “sale,” because it requires utilitiesto treat cogenerators as if they have engaged ina purchase and sale when in fact none might haveoccurred. The Court of Appeals disagreed, hold-ing that FERC’S rule is consistent with PURPA. Thecourt noted that the narrower construction of thestatute urged by AEP would result—anomalous-Iy–in discriminatorily different treatment forcogenerators that use some or all of their poweronsite and those that sell all their electric output.With such a narrow construction, cogenerationcould be uneconomical because utility retail ratesusually are lower than the utility’s incrementalenergy and capacity costs and the cost of cogen-erating.


AEP also argued that FERC did not adequatelyconsider and explain its decision to require utili-ties to engage in the simultaneous transaction fic-tion. The court found that FERC had consideredthe impact of this rule on all interested partiesand thus that the rule had been adequately jus-tified (l).

Obligation to Operate in Parallel.–The FERCrules also require each electric utility to offer tooperate in parallel with a QF, provided that theQF meets the State standards for protection ofsystem reliability (71). By operating in parallel,a QF can automatically export any electric powerthat is not consumed by its own load. Thus, thesame customer circuits can be served simultane-ously by customer- and utility-generated elec-tricity.

Obligation to Interconnect. -In their regula-tions implementing section 210 of PURPA, FERCargued that electric utilities’ obligation to inter-connect with QFs is subsumed within the pur-chase and sale obligations of section 210(a).Moreover, FERC noted that it has ample authorityto require utilities to interconnect with QFs underthe general mandate of section 210 that the com-mission prescribe “such rules as it determinesnecessary to encourage cogeneration and smallpower production” (75). Consequently, the FERCrules specified that “any electric utility shall makesuch interconnections with any qualifying facili-ty as may be necessary to accomplish purchasesor sales” (71).

AEP, et al., challenged this rule on the groundsthat it was inconsistent with sections 202 and 204of PURPA (which became sec. 210 and 212 ofthe Federal Power Act), as well as with PURPAsection 210 itself. Section 202(a)(l) provides:

Upon application of any electric utility, Federalpower marketing agency, qualifying cogenerator,or qualifying small power producer, the Commis-sion may issue an order requiring—

(A) the physical connection of any cogen-eration facility, any small power produc-tion facility, or the transmission facilitiesof any electric utility, with the facilitiesof such applicant.

In issuing an order under section 202(a)(l), theCommission must issue notice to each affected

party and afford an opportunity for a full eviden-tiary hearing under the Administrative ProcedureAct.

Section 202(c) states that FERC may not issuean order under 202(a)(l) unless FERC determinesthat the order:

(1) is in the public interest,(2) would–

(A) encourage overall conservation of energyor capital,

(B) optimize the efficiency of use of facilitiesand resources, or

(C) improve the reliability of any electric utili-ty system or Federal power marketingagency to which the order applies, and

(3) meets the requirements of section [204].

The requirements of section 204 are that FERCdetermine that an order issued under section202(a)(l):

(1) is not likely to result in a reasonably ascer-tainable uncompensated economic loss forany electric utility, qualifying cogenerator, orqualifying small power producer . . . affectedby the order;

(2) will not place an undue burden on an electricutility, qualifying cogenerator, or qualifyingsmall power producer . . . affected by theorder;

(3) will not unreasonably impair the reliability ofany electric utility affected by the order; and

(4) will not impair the ability of any electric utili-ty affected by the order to render adequateservice to its customers.

Finally, while section 21 O(e) of PURPA authorizesFERC to exempt QFs from provisions of the Fed-eral Power Act, it specifically excludes sections202 and 204 from such exemption.

In the AEP case, FERC argued that compliancewith sections 202 and 204 of PURPA would im-pose an undue burden on cogenerators and thuswould be contrary to the entire thrust of sections201 and 210. in particular, FERC noted that inenacting sections 201 and 210, Congress hadalready determined that QFs serve the purposeof the act to optimize the efficiency of use offacilities and resources by electric utilities, andthus it would be both redundant and unduly bur-densome to require QFs to meet all the re-quirements of sections 202 and 204 in order tosell power to the grid.


However, the U.S. Court of Appeals agreedwith AEP, holding that FERC’S rule requiring in-terconnection was inconsistent with PURPA. Thecourt noted that FERC, in promulgating an inter-connection rule that is consistent:

need not impose substantial administrativeburdens on those facilities, but rather can adoptstreamlined procedures. If the Commission be-lieves that even streamlined procedures are tooburdensome, the necessary amendment mustcome from Congress (1).

In its petition for rehearing of the AEP decision,FERC emphasized the basic intent of PURPA toencourage cogeneration, and argued that, with-out the interconnection requirement, the obliga-tion to purchase and sell is meaningless. FERCalso contended that PURPA section 210 is inde-pendent of, and does not amend, the FederalPower Act, and thus the interconnection require-ment must be read into PURPA and the section202 and 204 provisions interpreted as an alter-native means of obtaining interconnection.

If the AEP decision is upheld by the SupremeCourt, then QFs who cannot get a utility to agreeto interconnect will have to apply for a FERCorder under the procedures outlined in section202(a)(l), and thus meet the evidentiary re-quirements of sections 202 and 204. However,the requirements of sections 202(c) and 204would be very difficult and expensive for a QFto meet. Even in well-understood situations, theexpenses and delays associated with evidentiaryhearings under the Administrative Procedure Actwill deter all but those who have a pressing needfor an administrative order. But the multiplestringent legislative tests of sections 202(c) and204 are couched in new, broad language that willhave to be construed, first, by FERC and then,in all likelihood, by the courts. Thus, these pro-visions pose a substantial deterrent to cogener-ators that cannot get an electric utility to volun-tarily interconnect with them–exactly the prob-lem PURPA was intended to remedy. Options forresolving this issue are discussed in chapter 7.

Under the FERC regulations implementingPURPA, a QF must reimburse any electric utilitythat purchases energy or capacity from the facility

for interconnection costs. These costs are definedin the regulations as:

. . . the reasonable costs of connection, switch-ing, metering, transmission, distribution, safetyprovisions, and administrative costs incurred bythe electric utility and directly related to the in-stallation and maintenance of the physical facil-ities necessary to permit interconnected opera-tions with a qualifying facility, to the extent thatsuch costs are in excess of the correspondingcosts which the electric utility would have in-curred if it had not engaged in interconnectedoperations, but instead generated an equivalentamount of electric energy itself or purchased anequivalent amount of electric energy or capaci-ty from other sources (68).

Interconnection costs must be assessed on a non-discriminatory basis with respect to noncogen-erating customers with similar load characteris-tics, and may not duplicate any costs includedin the avoided costs (74). Standard or classcharges for interconnection may be included inpurchase power tariffs for QFs with a designcapacity of 100 kW or less, and PSCS may alsodetermine interconnection costs for larger facil-ities on either a class or individual basis.

State regulatory commissions have the authori-ty to ensure that utility requirements for systemsafety equipment and other interconnection re-quirements and their associated costs are reason-able. In practice, utility interconnection re-quirements vary widely (see ch. 4) and few PSCShave addressed the interconnection questiondirectly.

OTHER PURPA BENEFITS

Qualifying cogenerators are exempt from reg-ulation as a public utility or a utility holding com-pany under the Federal Power Act and PUHCA,and from State laws regulating the rates, struc-ture, and financing of utilities. However, if a reg-ulated electric utility owns more than a 50-per-cent equity interest in a qualifying cogenerator,the cogenerator will be subject to the traditionaljurisdiction of ratemaking authorities to the ex-tent of utility ownership. In addition, qualifyingcogenerators may be eligible for an exemptionfrom the FUA prohibitions on oil and gas use andfrom the incremental pricing provisions of NGPA.

IMPLEMENTATION OF SECTION 210

The FERC regulations on section 210 of PURPArequired State public utility commissions (PUCS)to begin implementation of the regulations byMarch 1981. Since that time, a wide range of draft

Table 19.—Rates for Power Purchased

and final rules have been issued by the States,and utilities have published a variety of tariffs forcogenerated power (see table 19). The State PUCShave taken full advantage of the procedural lati-tude allowed by the FERC rules, using rulemak-ing, adjudication, and dispute resolution to es-

From QFs by State-Regulated Utilities

Capacity paymentsUtility Energy payments (cents/kWh) ($/kW-yr) Comments

AlabamaAlabama Power Co.

ArkansasArkansas Power & Light Co.

CaliforniaPacific Gas & Electric Co.

Southern California Edison

San Diego Gas & Electric Co.

ConnecticutConnecticut Light & Power Co. and

Hartford Electric Light Co.

IdahoUtah Power & Light Co.

Washington Water Power Co.

Idaho Power Co.

Illinois

Illinois Power

Commonwealth Edison

Central Illinois Light Co.

2.59 on-peak, June-October2.17 off-peak, June-October2.14 on-peak, November-May2.05 off-peak, November-May

Reverse metering currently used

6.58 on-peak6.219 mid-peak5.553 off-peak6.030 non-TOD6.6 on-peak6.0 mid-peak5.8 off-peak6.0 non-TOD8.333 on-peak7.069 mid-peak6.225 off-peak6.850 non-TOD

Firm power6.7 on-peak (114.5% of fossil fuels cost)5.4 off-peak (90.5% of fossil fuels coat)Nonflrm power6.6 on-peak (110% of fossil fuels cost)5.2 off-peak (86.5% of fossil fuels cost)

Firm power 1,2Non.firm power 2.6

Firm power 1.6

Nonfirm power 2.4Firm power 1.639

Nonflrm power1.41-3.86 (varies each month,2.4 average)

2.42 on-peak summer1.55 off-peak summer2.65 on-peak winter1.88 off-peak winterNon-TOO:1.89 summer2.18 winter5.31 on-peak summer2.90 off-peak summer5.17 on-peak winter3.37 off-peak winter34 kV or greater2.3 on-peak2.1 off-paak12 kV to 34 kV:2.4 on-peak2.2 off-peakLess than 12 kV:2.5 on-peak2.3 off-peak

$0.75-$1.50/kW-month

25% of full value

$0.70-$2.00/kW-month

88-268 Increasing withcontract length4-35 years.

96-280 Increaslng withcontract length4-35 years.

0.3cents/kWh116-318 Increasing withcontract length4-35 years.

Nuclear 24%, coal 58%, oil 1%, gas 3%, hydro 14%.Off peak purchase rates are offered for utilities withouttime-of-day metering. Rates are for facllities Iess than100 kW.

Nuclear 17%, coal 9%, oil 44%, gas 10%, hydro 20°AComments on proposed rates were due byJune 1, 1981.

Nuclear 4%, oil 67%’., gas 1%, hydro 25%, other 3%.Rates are for February-April 1981.

Rates are for February-April 1961.

Rates are for February-April 1981.

Nuclear 38%, oil 80°/0, hydro 2%.

Purchase rates are temporarily In effect pending ap-proval of utlllty proposals. Percentage is tied tomonthly fuel adjustment. Firm power rates are forfacilities greater than 100 kW. Off-peak purchaserates are offered for facilities without tlme-of-daymetering. No size restrictions apply to non-flrmfacilities.

Oil 1%, gas 3%, hydro 96%The Idaho PUC has ordered UP&L to add some capac-

ity credit to the non-flrm energy payment.

Rates are for facilities less than 100 kW.

The Idaho PUC has ordered IPC to add some capacitycredit to the non-flrm energy payment.

Nuclear 19%, coal 57%, oil 23°/0, < 1% gas,<1 % hydro, 1 % other.

1,000 kW or less.

Ch. 3—Context tor Cogeneration ● 87

Table 19.—Rates for Power Purchased From QFs by State-Regulated Utilities-Continued

Capaclty paymentsutility Energy payments (Cents/kWh) ($/kW-yr) Commenta

Interstate Power Co.

Central Illinois Public Service

South Beloit Water, Gas &Electric Co.

Union Electric

Indiana

Indiana & Michigan Eiectric Co.

Indianapolis Power & Light

Northern Indiana PublicService Co.

Public Service Co. of IndianaSouthern Indiana Gee & Electric

Richmond Power & LightKansasKansas Power & LightMassachusetts

Boston Edison

Commonwealth Electrlc

Eastern Edison

Massachusetts Electric

Cambridge Electric

Nantucket ElectrlcManchester ElectricFitchburg Gas & Eiectrtc

Western Massachusetts Electric

Michigan

Statewide purchase rate includes:Consumers Power Co. andDetroit Edison

Mlnnesota

2.45 on-peak, June-September2.05 off-peak, June-September2.19 on-peak, October-May2.05 off-peak, October-May1.978 on-peak summer (3 months)1.620 off-peak summer1.884 on-peak winter (3 months)1.861 off-peak winter1.805 on-peak (rest of year)1.565 off-peak2.30 on-peak1.70 off-peakNon. TOD:1.77 summer1.53 winterTOO:2.41 on-peak summer1.36 off-peak summer1.50 summer, weekends and holidays1.86 on-peak winter1.35 off-peak winter1.35 winter, weekends end holidays

TOO:1.36 on-peak0.81 off-peakNon.TOD: 0.811.14 general rateSeaaonal:1.19 on-peak summer1.07 off-peak summer1.28 on-peak winter1.08 off-peak winter2.62 on-peak summer2.29 off-peak summer2.61 on-peak winter2.29 off-peak winterNorr. TOD seasonal:1.86 summer1.83 winter1.331.49 on-peak summer1.02 off-peak summer1.15 on-peak winter1.00 off-peak winter0.914

1.60

6.971 on-peak4.047 off-peak5.543 flat7.16 on-peak6.15 off-peak6.51 flat8.792 on-peak5.161 off-peak5.995 fiat5.51 on-peak4.79 off-peak5.08 fiat7.22 on-peak5.91 off-peak6.34 fiat7.444.7486.081 on-peak3.313 off-peak4,940 flat5.813 on-peak4.238 off-peak4.979 flat

2.5

Nuclear O%, coal 89%, oil 8%, gas < 1%, hydro 1%,other 2%.

Coal 35%, Oil 11%, gas 55%.Rate is for a cogenerator on-line since the 1920’s.Nuclear 9%, coal O%, oil 72%, gas <1%, hydro 18°/0,other 1%.

Interim rates. Energy rates wIII be reset every 3 monthswhen fuel adjustment is figured. QFs of 30 kW or lesscan use reverse metering.

Nuclear 14°/0, coal 47%., oii 230/o, gee 4%, hydro 11 O/.,other 1‘/0.

This rate was established prior to PURPA compliance.New purchase rates implemented in March orApril of 1982.

Nuclear 21%, coal 55°/0, oil 19%, gas 1%, hydro 2%,other 2%.


Table 19.—Rates for Power Purchased From QFs by State”Regulated Utillties—Continued

Capacity paymentautility Energy payments (cents./kWh) ($/kW-yr) Comments

Northern States Power Co,

Montana

Montana Power

Montana-Dakota

Pacific Power & LightNebraska

Omaha Public Power District

NevadaIdaho Power

Sierra PacificNevada Power Co.

New HampshireStatewide rate

New Jersey

Firm power2.08-3.07 increasing with contract length

5-25 years.TOD metering service:2.15 on-peak1.39 off-peakNonfirm power : 1.35Occasional power 1.66

2.7842

Nonfirm power2.21 on-peak1.57 off-peakNon firm, non-TOD: 1.91Firm power:1.97-3.08 (depending on contract length)

1.34-1.88

TOD metering:1.60 on-peak summer1.00 off-peak all year1.20 on-peak winterStandard rate: 1.10

1.71 (February)-4.16 (August)4.093.802 on-peak, October 1961

1.943 off-peak, October 1981

3.528 on-peak, November 1981

2.331 off-peak, November 1981

4.311 on-peak, December 1981

2,630 off-peak, December 1981

Firm power 8.2Nonfirm power 7.7

Jersey Central Power and Light Co. Approximate only:6.0-7.5 on-peak2.0-5.0 off-peak

Atlantic City Electric Co. Temporary rate: 2.5

New York

77.24 (25-yesr contractonly)

3.75-7.37 per kW-month

116.00-263.00 (1981)

6.1cents/kWh8.55 on-peak

October 19810.07 off-peakOctober 1961

0.14 on-peakNovember 1981

0.00 off-peakNovember 1981

0.14 on-peakDecember 1981

0.00 off-peakDecember 1981

Statewide minimum rate includes: 6.00 minimumLong island Lighting Co.,Niagara Mohawk Power Co.,New York State Electric &Gas CO.,

Consolidated Edison,Orange & Rockland Utilities, Inc.,Central Hudson Gas & Electric

Corp. and othersNorth Carolina(Note: North Caroiina capacity payments are given as cents/kWh not $/kW-yr as shown above.)Carolina Light & Power Co. 2.60-5.55 on-peak 1.49-2.39 summer

month2.074.04 off-peak 1.29-2.08 non-summer

monthsDuke Power Co. 2.38-5.20 on-peak 1.11-1.88 on-peak

months1.78-3.91 off-peak 0.68=1.00 off-peak

monthsVirginia Electric & Power CO. 4.23-9.30 on-peak summer 1.61-2.50 summer

3.59-4.30 peak non-summer 1.42-2.25 non-summer2.82-5.77 all others

Nanthahala Power & Light Co. 2.05 2.50North Dakota(Note: proposed rates–not yet finished.)Northern States Power Co. 2.15 on-peak 2.06-3.07 (cents/kWh)

1.39 off-peak

Temporary rate schedule in effect until further studiesare completed. These rates are intended to complywith PURPA requirements and are restricted to facili-ties less than 100 kW. Capacity credits are includedin firm power purchase rates. Non-firm power ratestake effect in the event that a firm producer does notprovide dependable generation. Occasional power islimited to 500 kWh/month.

Nuclear 0%, coal 32%, oil 5%, gas 1%, hydro 61 O/.,other 1%.

Non-firm rates for QFs of 100 kW or less.

Nuclear 26°/0, coal 48°/0, oil 130A, gas 9%., hydro 30A,other 3%.

Rates apply to facilities of 100 kW or less.

Nuclear OO/., coal 540/’, oil 5%, gee 23%, hydro 18%.Energy payments vary monthly. Capacity payments varyby length of contract.

Energy payments and capacity payments vary monthly.

coal 30%, oil 47 %, hydro 23%.Granite State Electric Utility is not required to pay the

firm power rate due to excess capacity.Nuclear 14%, coal 13%, oil 690/’, gas 1%, hydro 3%.Actual rates are determined by averaging marginalenergy rates for previous 3-month on-peak and off-peak hours. The rate appiies to facilities between10 and 1,000 kW.

This October 1980 rate was greater than averageenergy costs. The utility has proposed that buybackrates may be set at time of interconnection.

Nuclear 13%, coal 8%, oil 83%, hydro 15%°, gas andother 1%.

Nuclear 110/0, coal 71%, oil 6%, hydro 12%.

Rates increase with contract length.



NP&L purchases power from TVA.Coal 82%, oil 4%, hydro 14%.

Rates apply to facilities less than 100 kW. Capacitypayments increase with length of contract 5-25 years.Facilities larger than 100 kW treated case-by-case.

Ch 3—Context for Cogeneration . 89

Table 19.—Rates for Power Purchased From QFs by State-Regulated Utilities—Continued

Capacity paymentsUtlllty Energy payments (cents/kWh) ($/kW-yr) Comments

Nuclear O%, coal 20%, oil 3%, gee 65°/0, hydro 80A,other 40/o.

Formulae have been established to treat purchase ratesfor various types of small power producers. Bothenergy and capacity components are considered.

Nuclear 12%, coal 00/’, oil 70A, gas 1%, hydro 78°/0,other 2%.

Nuclear O%, coal O%, oil 99%, gas O%, hydro 1 %.

Okiahoma

0.66-3.05 depending on firmness ofcapacity

Statewide rate schedule includes:Oklahoma Gas & Electrlc Co.Public Service Co.

Oregon Reverse metering currently used

Rhode IslandNew England Power Co. 5.5247 on-peak

4.5339 off-peak4.9643 averagePrimary:6.412 on-peak4.642 off-peak5.511 averageSecondary:6.726 on-peak4.965 off-peak5.723 average4.473 on-peak4.093 off-peak4.317 average

Blackstone Valley Electric Co.

Newport Electric Co.

Nuclear 29%, coal 300/., oil 210/0, hydro 19°/0, gas andother 1%.

Rates are for facilities less than 5 MW.

South Carolina

Carolina Power & Light Co.

Duke Power Co.

46.68 summer40.20 non-summer60.00 (Based on

integrated capacityduring peak monthsJune-September,December-March).

2.60 on-peak2.07 off-peak1.96 on-peak1.49 off-peak

Coal 86%, oil 2%, gas 2%, hydro 1O%.Purchase rates are for facilities less than 1,000 kW(100 kW for hydro). Larger facilities are consideredcase-by-case (up to 3.5cents/kWh).

UtahUtah Power & Light Co. 2.2 (temporary rate) 2.6cents/kWh

C.P. NationalVermontStatewide rate schedule

2.2 (temporary rate) 2.66cents/kWhNuclear 57%, coal 3%, oil 16°/0, hydro 24%.Avoided costs are higher than would be expected from

Vermont’s capacity mix due to dispatch and account-ing practices of NEPOOL.

7.8 standard rateTOD rates:9.0 on-peak6.6 off-peak

Nuclear 17%, coal 59%, oil 170/., gas 20/., hydro 5°/0.Purchase rates are for facilities less than 200 kW.

Larger facilities are treated case-by-case.Purchase rates are for facilities less than 200 kW.

Larger facilities are treated case-by-case.

WisconsinWisconsin Power & Light Co.

Madison Gas & Electric Co.

1.60 on-peak1.75 off-peak (includes capacity)2.75 on-peak summer1.50 off-peak summer2.22 on-peak winter1.50 off-peak winterFirm power:3.65 on-peak summer1.45 off-peak summer3.45 on-peak winter1.45 off-peak winterNon firm power:2.90 on-peak1.45 off-peakFor 20 kW or less:1.81 on-peak1.14 off-peakFor 21-500 kW after 1986:1.60 on-peak1.14 off-peak1.90

Wisconsin Electrlc Co.

Northern States Power Co. $4/kW/month Prior to 1966 the rates for 20 kW and less apply to21-500 kW. No capacity credits will be paid until after1966. Facilities greater than 500 kW are treatedcase-by-case.

S4/kW-month

Lake Superior District Power Co. S6.02/kW-month Purchase rates are for facilities between 6 and 200 kW.Smaller facilities receive no payments. Larger facili-ties are considered case-by-case.

Wisconsin Public Service Corp. 1.65 on-peak1.32 off-peak

To be determinedaccording to character-istics of each facillty.

Coal 93%, hydro 6%, oil and gas 10/..

Purchase rates are for facilities less than 100 kW.

Wyoming(Note: All of the Wyoming purchaseUtah Power & Light Co.

rates are “experimental.”)Non-firm power: 2.2Firm power 2.60.53Cheyenne Light, Fuel and

Power Co.

Tri-County Electric Association

Available on demonstra-tion of demandreduction.

1.07

0.405

This is a non-generating utility which has based itsavoided costs on wholesale supply rates.

Montana-Dakota Utilities Co. Available on demonstra-tion of capacity dis-placement or demandreduction potential.

SOURCE: Reiner H. J. H. Lock and Jack C. Van Kuiken, “Cogeneratlon and Small Power Production: State Implementation of Section 210 of PURPA,” 3 Solar L Rep.659 (November-December 1961).

98-946 0 - B 3 - 7 : Q L 3

tablish rates and operating criteria. These pro-cedures have resulted in a wide diversity in Stateapproaches to PURPA as well as in the rates es-tablished thereunder. A comprehensive surveyof State implementation actions and cogenera-tion potential is beyond the scope of this assess-ment. Moreover, the status of these actions isuncertain due to the Court of Appeals case dis-cussed above. Therefore, this section will presentcase studies based on the implementation of titleII in three areas: California, where cogenerationhas a potentially large market and the State gov-ernment is actively promoting its use; Illinois,where cogeneration’s technical potential couldbe significant but the market will be limited bythe electric utilities’ large construction budget;and New England, where existing excess capaci-ty, extensive pooling agreements, and plannedconservation measures will influence cogenera-tion’s market potential. It should be emphasizedthat these case studies do not typify the range ofState and utility actions on PURPA. Rather, theyrepresent examples of three kinds of planningsituations that will affect PURPA’S implementa-tion. The same case study areas are used in theanalysis of cogeneration’s potential impacts onutility planning and regulation in chapter 6.

California.—The dominant factor in Californiautilities’ capacity planning is not demand growth,but the need to reduce their dependence on oil.Planning and construction of new coal and nu-clear baseload facilities was limited during the1970’s as demand growth declined, and cancella-tions and postponements of coal and nuclear ca-pacity left the State’s utilities heavily dependenton oil and natural gas. The California EnergyCommission’s (CEC) 1981 final report on electrici-ty projects an annual energy growth rate (meas-ured in GWh) of less than 1.5 percent through1992, but a capacity growth rate of approximately2.5 percent per year (5). The capacity growth rateis higher because it includes a projected 30-per-cent reserve margin (in case the energy growthrate is higher than 1.5 percent), the replacementof retired powerplants and expired purchasepower contracts, and the reduction of utility oiland gas consumption Statewide to one-half the1979 level by 1992.

The CEC report identifies three priorities thatshould be sufficient (according to the report) toprovide the needed energy and capacity for the1980-92 period: 1) additional conservation andpower pooling; 2) geothermal and renewable re-sources (biomass, wind, solar, small hydro, andexisting reservoirs); and 3) cogeneration and in-terstate electricity transfers. CEC estimates thatcogeneration could provide up to 3,000 MW ofgenerating capacity by 1992. Their estimate isbracketed by the California utilities’ long-rangeresource plans, which project 1,900 MW of co-generation capacity by 1992, and the NaturalResources Defense Council estimate of 4,300MW by 1995 (5).

State regulators in California had taken a num-ber of regulatory actions favoring cogenerationeven before the FERC rules implementing PURPAsection 210 became final. The California PublicUtilities Commission (CPUC) investigated the roleof cogeneration in utility resource planning (seefig. 13) and, in 1979, ordered Pacific Gas& Elec-tric (PG&E), in particular, and all of the State’selectric utilities in general, to adopt a specifictimetable for bringing cogeneration capacity intothe electrical system. Under the CPUC order,PG&E was expected to bring 2000 MW of cogen-eration into the resource base by 1985, principal-ly through contracts tied to the avoided cost ofoil-fired utility capacity that is displaced (8). Ina companion decision (this time in a PG&E gen-eral rate case), CPUC imposed a rate-of-returnpenalty on the company’s electric division for fail-ure to implement cogeneration projects aggres-sively. The penalty, which represented over $7million in annual revenues, or 0.2 percent inreturn on equity, was to be restored if PG&Ebrought 600 MW of cogeneration capacity undercontract by 1982 (7). Although PG&E was not ableto meet this goal, the CPUC staff recommended,late in 1981, that the penalty be discontinuedbecause the utility’s performance in encourag-ing cogeneration has been adequate (41).

PG&E planners argue that the CPUC goals of2,000 MW by 1985 are unrealistic. In a majorplanning study, PG&E estimated the cogenera-tion market potential in their service area to bebetween 204 and 903 MW of capacity additions


Flgure 13.–Statewide Utility Resource Plan Additions 1981=82:Renewable/lnnovative Technologies

4,500

I Biomass

3,600

1,800

900

0

Fuel cells

Fuel cells160/0

Wind 2Biomass 3

%

%

Fossilco-

gener-ation

Utility fi l ing - Utility filing Utility filing

with CPUC with CEC with CEC

1972 1974 1976 1978 1980 1980

July December

SOURCE: California Energy Commission, Electricity Tomorrow: 1981 Final Report (Sacramento, CalIf.: Ca/item/a EnergyCommission, 19S1).

by 1990 (beyond the 472 MW already operating),and their long range resource plan projects 190MW additional cogeneration capacity by 1985,and 600 MW by 1992. PG&E’s anaiysis suggeststhat industry would have to commit approximate-ly 12.5 percent of their total annual capital ex-penditures to cogeneration in order to meet theCEC goal of 2,000 MW under contract by 1985(41).

The California regulatory climate is unique. Inno other State has the public utility commissionparticipated so actively in capacity and resourceplanning. Encouraging cogeneration is an explicitpolicy expressed in price signals to the utility andfrom the utility to the potential cogenerator. De-spite these attitudes that favor cogeneration de-velopment, however, there remain significantquestions and uncertainties about the amount ofcogeneration capacity that can be counted on,and thus about the other types of capacity addi-tions that may be needed.

one major difficulty in assessing the extent offuture cogeneration development in Californialies in the special nature of the market, namely,the potential for large enhanced oil recoverycogeneration projects. The heavy oilfields in KernCounty, Calif., require steam injection or otheradvanced techniques for economic production.Converting existing steam boilers in these fieldsto cogeneration would involve projects with 200to 300 MW of generating capacity. CEC has stud-ied at least six of these projects, and one con-tract has been signed for 66 MW. Aggregate co-generation potential in the California oilfields hasbeen estimated by various sources to be between700 and 10,000 MW or more, depending on theprice of oil and the cogeneration technologyemployed (5,6,31 ,59).

In January 1982, CPUC issued their final deci-sion on rates and other standards for cogenera-tion and small power production pursuant to theFERC rules implementing sections 201 and 210

of PURPA. In general, this decision, known asOIR-2, requires utilities to file standard offers ap-plicable to QFs larger than 100 kw and tariffs forsmaller facilities. Both the standard offers and thetariffs are complete packages that include pricesfor power purchases and sales, requirements forinterconnection, and other relevant factors. Oncea utility’s tariff and standard offer terms are ap-proved by CPUC, purchases can be made underthem without further administrative review, andthe utility can recover its expenses for such pur-chases through an energy cost adjustment clausein the same manner as it recoups other purchasepower expenses (10).

Under OIR-2, utilities must file an array ofstandard offers based on different terms and con-ditions in order to provide QFs larger than 100kw with a sufficiently wide choice of options tomeet their particular needs, and thus to minimizethe use of nonstandard contracts that would haveto be reviewed individually by CPUC. In general,these include standard offers for energy andcapacity delivered by a QF both “as-available”and under a firm contract, and for energy andcapacity prices based on both the utility’s short-run and Iongrun marginal cost.

Standard offers for “as-available” energy andcapacity are based on the utility’s avoided costat the time of delivery, which is the cost the utilitywould have to incur to produce an equivalentamount of power at that time, or the utility’sshortrun marginal cost. The energy componentof this standard offer is defined as the highestvariable operating cost per unit of electricity pro-duced at a given time, and equals the productof: 1 ) the purchase price of oil used as the mar-ginal fuel over the last 3 months, and 2) theforecast incremental heat rates* of the plants ac-tually used by the utility to follow load. The as-available energy price also includes an aggregateadjustment for transmission and distribution costsand line losses or savings. In OIR-2, CPUC de-cided that it was not reasonable to treat thesecosts on an individual basis except for facilitieslarger than 1 MW at remote sites.

*Heat rate is a measure of thermal efficiency expressed in Btuinput per net kilowatthour output (see ch. 4). The marginal, or in-cremental, heat rate is calculated as the additional (or saved) Btuto produce (or not produce) the next kilowatthour.

The as-available capacity payment equals amarginal shortage cost that reflects the effects ofthe added increment of production on reservemargins and reliability, and is determined basedon the 1982 estimated cost of peaking capacity(represented by a combustion turbine). Thiscapacity payment is in cents/kWh varying by timeof delivery, and is available only for energydelivered through a meter to the utility. Thus,simultaneous purchase and sale QFs will receivethe capacity value for all the electricity theygenerate because their entire output is meteredat the generator before any goes to the QF’s loador the utility. Other QFs will only receive thecapacity value of the electricity actually deliveredto the utility (10).

Standard offers for energy and capacitydelivered under long-term contracts can bebased on either the utility’s shortrun or Iongrunmarginal cost. For shortrun marginal costs, energyprices can be contracted for up to 5 years basedon a forecast of the utility’s variable operating cost(described above). The QF must commit to de-liver all the electricity it produces to the utilityover the contract period. These contractual ener-gy payments can be combined with either as-available capacity payments or with firm capacitypayments based on shortrun marginal costs (1 O).

Firm capacity is equivalent to an increase insupply with corresponding standards, terminationprovisions, and sanctions regarding dispatch-ability, reliability, availability, and other factorsspecified in the FERC rules. The value of each ofthese factors is calculated based on the same per-formance standards utilities impose on their owngenerating plants. If a QF exceeds utility stand-ards, its capacity value should be increased cor-respondingly. The sum of each of these factorsdetermines the overall capacity value, which isto be offered on both a $/kW/yr and a cents/kWhbasis (10).

Alternatively, QFs can choose a contractperiod of up to 25 years with a firm pricing struc-ture for energy and capacity based on the utili-ty’s Iongrun marginal costs. This standard offeroption was included due to concerns that short-run marginal costs would be too volatile to pro-vide financial certainty and would not adequatelyreflect a QF’s value in the utility’s long-range

resource plans. The longrun marginal costs areestimated based on the fixed costs associated withthe utility’s resource plan and the correspondingsystem projected marginal operating costs (10).

Standard tariffs for QFs smaller than 100 kWprovide for purchase power payments incents/kWh calculated in the same manner as theas-available rates for larger facilities (describedabove). These tariffs may be time-differentiated,but if a small QF chooses not to buy a time-of-use meter, the utility may offer capacity paymentsthat aggregate over 1 year to 50 percent of thecapacity provided by facilities with such meters(lo).

Both standard offers and tariffs also provide forsales of supplementary, backup, maintenance,and interruptible power to QFs. The first threenormally are provided under the regular rateschedules applicable to all customers of the sameclass. However, the demand charges associatedwith such rates are substantially lower for QFsthan for other customers, and may be waived ifthe facility maintains an 85-percent on-peakcapacity factor. Interruptible rates apply to QFsto the extent their generation is used to serve theirown load (10).

Finally, CPUC allows nonstandard offers (thosethat vary from the terms described above) whenthey are necessary to shift some of a project’s riskfrom the QF to the ratepayers (e.g., in the caseof debt guarantees, Ievelized payments, or pay-ment floors). in return for accepting such risks,ratepayers are afforded some reduction onavoided cost payments. In general, the reason-ableness of nonstandard offers will be determinedduring the annual review of energy cost adjust-ment clauses or other normal rate proceedings.However, during the first 2 years of OIR-2’S im-plementation CPUC will provide advance reviewof those nonstandard offers about which a utili-ty has significant questions (10).

It is not clear how the California Public UtilitiesCommission would revise OIR-2 in the event thatthe FERC regulations implementing PURPA arerevised to require payments for QF power at lessthan the utility’s full avoided cost. The utilitieshave argued that full avoided cost paymentsbased on their highest variable operating cost,

as determined by the price of oil used on themargin, does not reflect the utilities’ actual fuelmix, and thus does not allow ratepayers to sharethe benefits of QF generation at a cost potential-ly below the utility’s marginal cost, nor does itcompensate utilities or their shareholders for thepotentially higher risks of reliance on QF energyand capacity. In issuing OIR-2, CPUC consideredarguments by the patties that full avoided costpayments disadvantage ratepayers (the same ar-gument accepted by the U.S. Court of Appealsagainst the FERC rules, as discussed previously).However, CPUC found that only full avoided costpayments would parallel the prices that wouldbe established in a competitive market, and thusgive consumers an efficient price signal and “en-courage the fullest possible efficient developmentof QF resources that can effectively and econom-ically compete with utility resources” (1 O).

On the other hand, CPUC did explicitly rec-ognize that payments at less than the full avoidedcost are appropriate when some of the risk of in-vesting in QFs is transferred to the ratepayers.CPUC also requested comments from interestedparties on whether utilities should receive apercentage of the avoided cost (e.g., one-half of1 percent) as a brokerage fee for serving as in-termediaries between QFs and electricity con-sumers. However, in such a scheme, the fullavoided cost would still be passed on to rate-payers through the energy cost adjustment clause(lo).

It is instructive to contrast the Californiacogeneration planning situation with roughlyanalogous efforts in New York by the Consoli-dated Edison Co. (ConEd). The potential cogen-eration market in ConEd’s service territory maybe large, but the principal ConEd customers likelyto cogenerate are large commercial buildings.Their primary economic motive would be toavoid high electricity bills, and they are less like-ly to sell excess power to the utility than Califor-nia projects. Given the large number and homo-geneity of ConEd’s potential cogenerators, it ispossible to analyze the market systematically.

Con Ed constructed a model of the cogenera-tion investment decision that calculates the costsand benefits of investing in cogeneration and

measures the internal rate of return from such in-vestments. Where this return, on an aftertax basis,would be 15 percent or better over a 10-yearhorizon, Con Ed assumed the investment wouldbe made. In order to estimate market size, thismodel was applied to the load data describingConEd’s 4500 largest customers. Depending oninput assumptions, Con Ed found a high range ofup to 750 potential cogenerators with a combinedpeakload of 1,483 MW, and an expected out-come or base case of 395 cogenerators with acombined peakload of 1,086 MW. ConEd hasused this model to characterize the sensitivity ofmarket size to the policies that would reduce their“loss exposure” to cogeneration (48).

ConEd’s loss exposure stems from a fixed-cost/declining demand problem. Because de-mand is not expected to grow, cogenerators leav-ing the system will shift a burden of fixed costsonto the other remaining customers. This wouldnot be a problem if there were enough new kWhsales or customers to replace the cogeneratorsleaving the system, but ConEd does not anticipatesuch growth. Situations such as the fixed-cost/declining demand problem, in which cogenera-tion has a potential to operate to the financialdetriment of utilities, are discussed in more detailin chapter 6.

If State regulators are asked to protect utilitysales from loss exposure, the utilities mustdemonstrate that the problem is real and substan-tial in magnitude. ConEd’s cogeneration modelpurports to make such a demonstration. How-ever, the New York Public Service Commission(NYPSC) argued that the model results were ex-tremely sensitive to input assumptions, and askedCon Ed to run the model using slightly higher costsfor cogenerators but holding utility rates constant.The result was an extremely small market poten-tial, with only 27 customers (130 MW of peak-Ioad) leaving the system (48). At this level of loss,there is no substantial economic threat to Con Ed.The NYPSC staff argued further that the actualmarket may be either smaller or larger than thisestimate, and until market penetration is morecertain, no policy changes are needed to protectConEd’s sales from loss exposure.

This loss exposure problem has not arisen inCalifornia. Thus, while CPUC is creating a climate

favorable to large-scale cogeneration develop-ment, it also is encouraging or ordering utilitiesto aggressively pursue conservation plans, in-cluding developing investment/finance plans forresidential weatherization and solar water heatingretrofit (9).

Illinois.–Electric utilities in Illinois currently areengaged in a massive construction program thatbegan before the 1973 escalation in oil prices.The largest companies, Commonwealth Edison(CWE) and Illinois Power (1P) are most heavily in-volved in new construction. CWE has six nuclearunits at various stages of completion, while 1P,a company roughly one-fifth the size of CWE, hasone.

The financial burden of this construction hasbecome increasingly onerous as utility kwh salesgrowth has lagged behind expectations. In thecase of CWE, the strain has appeared in the rapiddecline of their bond rating. In June 1980, Stand-ard and Poor’s lowered the rating on CWE deben-tures and pollution control bonds to BBB, thelowest rating acceptable to institutional investors.The rapid downgrading threatens to limit themarket for CWE debt securities, because investorsmay not want to risk the possibility of furtherrating cuts (35).

Moreover, in order to finance their $1 billionper year construction program, CWE needs morecash income. In 1979, CWE reported $297 mil-lion in net income to stockholders, but $222million of this was for AFUDC. Thus, 75 percentof net income did not represent cash (comparedto an industrywide 1979 average of 38 percent)(13). To improve CWE’S cash flow (as well as thatof 1P), the Illinois Commerce Commission (ICC)has allowed some portion of construction workin progress (CWIP) to be included in the ratebase. At the end of 1980, CWE had a balance of$4.14 billion in their CWIP account, while IP had$920 million (24).

Planning under these conditions leaves relative-ly few options for the utility and the Stateregulators. ICC has initiated investigations intoelectric load forecasting and reserve margin/reliability issues, but the only feasible option isdelaying part of the CWE construction program.With this option, the tradeoff is between extra

fuel savings and avoided escalation of costs fromcompleting construction, versus delayed fixedcharges by postponing it. The relative value ofthese factors depends on the projected growthrate in kWh sales. Lower sales growth meanssmaller fuel savings and a decreased value ofcompleting construction. In its study of delayingtwo of CWE’S nuclear units, the ICC staff foundthat even with zero growth in kWh sales, it wasbetter to complete construction without delay(65).

In contrast to the California regulatory system,ICC has not developed an independent forecast-ing capability. Instead it has channeled its ad-ministrative resources into financial analysis andproduction cost modeling to allow independentregulatory assessment of the costs and benefitsof construction delays (albeit with many engineer-ing assumptions determined by utility data). Theproduction cost modeling will provide a basis forestablishing purchased power rates as requiredby PURPA section 210. By contrast, the Califor-nia agencies have devoted relatively few re-sources to financial and production cost model-ing, but instead have concentrated on demandforecasting (35).

Given the lack of flexibility in any of the con-struction commitments of CWE and 1P, ICC haschosen to avoid conflict over future demandgrowth expectations. The sensitivity of ICC to thefinancial strains of the utilities makes it unlikelythat any effort will be directed toward demandreduction policies (35). The more relevant ques-tion in this jurisdiction is the extent to which ICCcan shelter the utilities from the damaging finan-cial impacts of competition either from conser-vation measures or from cogeneration and smallpower production.

ICC established purchase power rates for QFsbased on a time-of-day rate structure that reflectsavoided costs both on-peak and off-peak as wellas seasonal adjustments. These rates vary depend-ing on the utility’s fuel mix. Thus CWE—whichis roughly 40 percent coal, 30 percent oil, and30 percent nuclear—offers energy payments on-peak that are only slightly lower than those of-fered by PG&E (see table 19). However, the othermajor Illinois utilities, which have 85 to 98 per-

cent coal-fired capacity, have much loweravoided costs. None of the Illinois utilities is of-fering capacity payments to QFs, due to the cur-rent excess capacity situation in that State (39).

The future avoided cost path for CWE dependscritically on the growth rate of kwh sales. Highgrowth will require continued reliance on oil andgas for a significant fraction of annual energy re-quirements, but at an average annual rate of 2percent or less the primary avoidable fuel will becoal. Average avoided fuel cost estimates for CWEduring 1981-88 are shown in figure 14 for growthrates of zero and 2 percent. Figure 14 illustratesa situation of declining avoided costs; other CWEcalculations indicate a more conventional out-come, with increasing avoided costs over time(35). While the declining cost outcome is by nomeans certain to occur, it represents a risk to the

Figure 14.—CWE Average Avoided Cost Paths:Baseiine Construction~

1981 1983 1985 1988

aCalculations based on data supplied to the ICC by CWE.

SOURCE: Edward Kahn and Michael Merritt, Dk?persed E/ectr/c/ty Ganerat/omP/arm/rig and Regu/at/orr (contractor report to OTA, February 1981).

potential investor in cogeneration if economicfeasibility depends on sales of excess power tothe utility.

New England .–Electric power planning inNew England is dominated by the influence ofthe New England Power Pool (NEPOOL), a re-gional pool that fully integrates both operationsand planning, and by the fragmented nature ofthe regional utility industry. Most New Englandutilities are small by national standards, and eventhe larger New England systems are associationsof small companies. Under these conditions itwould be impossible for any individual companyto achieve the economies of scale offered by largebaseload units without undue risk and extra cost.By cooperating in joint venture projects, how-ever, the New England utilities are able to over-come the regional fragmentation and to captureeconomies of scale. From a regional perspectivethis has been a significant political achievement(35).

The New England utilities also can purchasecapacity from NEPOOL for minimal cost due tothe substantial excess capacity on the system (theNEPOOL reserve margin in 1979 was 38.6 per-cent or 5890 MW above the 15,278 MW winterpeakload) (17). A NEPOOL member can meet hiscapacity responsibility by paying a “deficiencycharge” of $22/kW annually to the pool. If thedeficiency is above 2 percent, then an additional$14/kW is required for this capacity (57). Evenallowing for some escalation in these charges, thisis a much lower opportunity cost of capacity thanthat estimated for potentially capacity shortregions such as California. PG&E, for example,is currently offering over $60/kW/yr for short-termcapacity contracts in the early 1980’s (54).

The principal problem facing NEPOOL and theNew England utilities is reducing oil dependencein face of the deteriorating financial condition of,and increasing opposition to, the region’splanned nuclear power projects. With the sub-stantial generation reserves in NEPOOL, approvalof new projects is more difficult politically. Theextreme regulatory risk is that completed projectswill not be entered into the rate base on thegrounds that they are unnecessary. Such a rul-ing has recently been made in Missouri (43).

Given the relatively large number of jurisdictionsin New England, the requirements for politicalconsensus on large-scale projects is severe. Bar-ring such consensus, the economy of scale capac-ity expansion strategy will fail (35).

Within this planning context, the New EnglandStates have adopted a variety of means of im-plementing PURPA, including two statewide ap-proaches (New Hampshire and Vermont), andone based on the cost differences between agenerating utility and its nongenerating sub-sidiaries (Massachusetts). Although most Stateregulatory commissions have adopted standardpurchase power rates based on each individualutility’s capacity mix and operating characteris-tics, nothing in PURPA precludes statewide oreven regional rates if they are appropriate andthey further PURPA’S goals of encouraging co-generation and small power production and pro-moting the efficient use of utility facilities andresources. Statewide or regional rates may beperceived as advantageous when, as in NewEngland, the operations of utilities are closely in-tegrated so that they effectively form a singlepower system. In this case, a rate that reflects theavoided costs of the system rather than of in-dividual utilities may provide a better signal ofthe value of QF power throughout the State orregion (38,75).

The New Hampshire PUC established a state-wide rate for utility purchases of QF power thatuses, as a substitute for individual utility’s avoidedcosts, the operating and maintenance costs of“the most recently constructed and most efficientoil generating station” (Newington) of the State’slargest utility (Public Service of New Hampshire)(38). Newington’s running costs were deemed tobe a “reasonable proxy” for statewide fullavoided costs because the other utilities in NewHampshire also rely primarily on oil for electricitygeneration from units with operating costs at leastas high as Newington’s.

The New Hampshire purchase rate can beraised to reflect the avoided costs of less efficientunits when the load exceeds Newington’s capaci-ty or when Newington is not operating. However,the rate cannot be lower. That is, the PUC es-tablished a lifetime guaranteed minimum (or


“floor”) rate for all QFs that begin operation priorto the completion of Seabrook I (a large nuclearunit). The guaranteed minimum encourages oil-displacing QFs to come on-line as soon as possi-ble rather than waiting to see how avoided costswill be affected by the completion of Seabrook,and provides assurance that QFs will have asteady income stream despite the volatility in oilprices. If avoided costs do drop after SeabrookI is completed, QFs that come on-line before thenwill be subsidized through the guaranteed min-imum, but such subsidies are authorized underthe New Hampshire Limited Electrical EnergyProducers Act, the State’s “mini -PURPA.” Thus,the primary question surrounding the guaranteedminimum rate is whether future PUCS will bebound by the decision of the present PUC or willdiscontinue the guarantee (38).

The Vermont Public Service Board based theirstatewide purchase rate on the estimated avoidedcosts of NEPOOL, as determined by the averageof the actual operating costs of three of theregion’s most efficient oil-fired baseload plants.The result was similar to that achieved in NewHampshire (see table 19). The Vermont rates willensure that QFs are not paid more than the costof oil-fired units in operation at any time, and willenable the State’s utilities to readily market QFpower either through NEPOOL or elsewhere. Therates are subject to annual revision, but cannotbe decreased by more than 10 percent in anyyear without a strong factual showing that agreater reduction is justified (38). This proceduredoes not provide as much protection againstchanges in avoided costs as the New Hampshireguaranteed minimum, but it does limit the rateof decrease if NEPOOL’S avoided costs drop sud-denly (e.g., if a new, more efficient baseload plantcomes on-line) and it conforms to the traditionalratemaking practice of not subjecting consumersto sudden, drastic changes in rates. As in NewHampshire, the Vermont rate guarantee couldresult in some subsidization of QFs, but probablywill average out over time and thus be within thelimits on such subsidies anticipated in the FERCreguIations.

A third approach was necessary in Massachu-setts to accommodate “all-requirements” con-tracts among the corporate members of the New

England Electric System, a public utility holdingcompany whose subsidiaries include a wholesalegeneration and transmission company (NewEngland Power) and two retail distribution com-panies that have “all-requirements” contractswith New England Power (a third distribution subsidiary purchases at least 75 percent of its elec-tricity needs from New England Power). Underthe FERC rules implementing PURPA, avoidedcost calculations are supposed to be based onthe supplying utility’s costs if the power is actuallywheeled, and otherwise on the nongeneratingutility’s cost of purchased power. The Massachu-setts Department of Public Utilities (DPU) peti-tioned FERC for avoided cost rates based on thesupplying utility’s costs, when the two utilities arecorporate affiliates, regardless of whether thepower actually is wheeled. DPU argued that suchrates would reflect “the true avoided costs of pro-ducing that power by the appropriate utility sys-tem,” rather than an intracorporate transfer pricethat might be kept artificially low (38). AlthoughFERC has not issued a decision on the DPU peti-tion, this approach does not seem to be pre-cluded by the FERC rules so long as it encouragesQF generation. However, if this approach re-quired DPU to look at the reasonableness of thewholesale rates between two corporate affiliates,it could infringe on Federal jurisdiction over suchrates under the Federal Power Act (38).

The basis for setting purchase power rates inNew England is likely to be tied to oil costs forat least the next 10 years. There is, however, morethan one way to reflect oil dependence in PURPArates. The New Hampshire decision, for exam-ple, is based on projected rather than actual oilcosts. Presumably such a procedure is intendedto correct the accounting lags that occur whenactual costs are used and prices are rising rapid-ly. The California rates discussed above achievea similar result by indexing rates to the averageoil cost in the previous quarter (8,1 O). The Califor-nia approach will match rates more closely withavoided costs and eliminate the uncertainty ofprojecting oil prices, but also will result in lowerpayments.

Given the current excess capacity in NewEngland, any capacity payments made to cogen-erators will be limited by NEPOOL deficiency


charges. For example, the New Hampshire andConnecticut capacity payments of 5 mills/kWh(the difference between the payments for firmand nonfirm power) correspond roughly to theNEPOOL deficiency charge of $22/kW, wherethis capacity would be required 4,400 hr/yr($22/kW / 4,400 hrs = 0.5 cents/kWh) (34).

The introduction of QF power into NEPOOLinterchanges raises the question of whetherNEPOOL billing procedures might reimburse theVermont utilities on a basis other than fullavoided cost. NEPOOL has a complex “split-the-savings” formula that allocates 50 percent of thesaving to cover NEPOOL overhead and appor-tions the remaining 50 percent among utilitiesbased on their volume of business with NEPOOLover a certain period. Due to the relatively lowvolume of business Vermont utilities do withNEPOOL and the large difference between theutilities’ incremental cost and NEPOOL’S decre-mental cost, in most cases Vermont utilities willnot receive the full NEPOOL avoided cost for QFpower they supply to the pool. If the utilities mustpay QFs the full NEPOOL avoided cost, but re-cover less than that from the pool, the utilitiesmust either absorb the difference as a loss or passit on to their ratepayers. The most obvious solu-tion is for NEPOOL to recognize QFs as “sourcesof power” to utilities under the pool agreement.This is the approach adopted by New EnglandPower in several recent contractual arrangementswhich identify dispatchability as the main oper-ative distinction: a purchased power resource thatcan be dispatched by the utility or NEPOOL isa generation resource. Anything else is a negativeload (38).

Alternatively, NEPOOL could change its bill-ing practices to accommodate full avoided costrates by treating QF power as its marginal powerrather than mixing it in with other power fur-nished by a utility. In this case, NEPOOL would,in effect, directly purchase QF power at its fullavoided cost and the utility would merely serveas a conduit. Thus, this approach is similar to theFERC provisions for wheeling power through alocal utility to a more distant utility.

FUTURE AVOIDED COST PATHS

Given the wide regional variation in the eco-nomic and regulatory environment of electricutilities, uniform implementation of PURPA sec-tion 210 pricing incentives is unlikely. The pat-tern of avoided costs over time will depend onexisting regional fuel mix and reserve margin, aswell as on regulatory policy toward rates andcapacity expansion. Figure 15 illustrates severalgeneric paths for average utility avoided costs.A given company will start off on the left-handside of this figure with its fuel base dominatedby oil, coal, or nuclear steam generation. As cur-rent construction is completed and fuel costs con-tinue to increase, the fuel base and its value willchange. The basis of PURPA payments, avoidedcosts, also depends on future demand growth.To the extent that supply and demand are outof equilibrium, there will be cost implications forcogenerators and small power producers. Onepossibility of this kind is the potential for perma-

Figure 15.–Generic Paths for Average AvoidedCosts (mills/kWh)

180

120

80

SOURCE: Edward Kahn and Michael Merritt, L)/spamed E/ectr/c/ty Generation:P/ann/ng and Ffegu/at/on (contractor report to OTA, February 1981).


nent excess capacity; e.g., if State regulatorsauthorize construction of central station plantsto displace oil. Resulting reserve margins maybeso great as to preclude PURPA payments for ca-pacity. To examine the potential variety of out-comes, it is-helpful to trace out various pathwaysthrough figure 15.

Starting at the upper left with the shortrunmarginal cost (SRMC) of oil, several develop-ments are possible. At some point, this shortrunmarginal cost curve will intersect the Iongrunmarginal cost (LRMC) curve. If the utility mustcontinue to displace large amounts of oil at thispoint, the avoided cost will continue to increaseat the oil price escalation rate. Two other alter-natives are possible. The utility fuel mix may bein equilibrium when SRMC (oil) = LRMC. In thiscase avoided cost becomes Iongrun marginalcost, which is likely to rise much more slowlythan oil prices. The third alternative is permanentexcess capacity. This could occur in any numberof ways; all that is required is for constructioncommitments to exceed long-term demand. Inthis scenario avoided costs level out over timeand converge ultimately to the shortrun marginalcost of coal or nuclear plants (35).

Starting out from a fuel base of excess coal ornuclear capacity, a utility’s average avoided costsalso will eventually reach equilibrium with long-run marginal cost. This may not occur verysmoothly, as figure 15 indicates. At some timeexcess capacity will be exhausted and new facil-ities will be necessary. At this point the avoidedcost will take a major step upward. Addition ofnew facilities in such circumstances would posethe practical problem of allocating the Iongrunmarginal cost to capacity and energy for the pur-pose of designing rate schedules for purchasedpower (35).

Regulation of Fuel Use

Cogenerators’ fuel choice may be influencedby the FUA prohibitions on oil and gas use andby the allocation and pricing rules of NGPA, aswell as by environmental requirements and taxincentives (see following sections).

The Fuel Use Act.-A cogenerator may be sub-ject to the FUA prohibitions if it has a fuel heat

input rate of 100 million Btu per hour (MMBtu/hr)or greater (or if the combination of units at anyone site exceeds 250 MMBtu/hr), and if it comeswithin the statutory definition of either a power-plant or a major fuel-burning installation. UnderFUA, a powerplant includes “any stationary elec-tric generating unit, consisting of a boiler, a gasturbine, or a combined-cycle unit that produceselectric power for purposes of sale or exchange,”but does not include cogeneration facilities if lessthan half of the annual electric output is sold orexchanged for resale. A major fuel-burning in-stallation is defined as “a stationary unit consistingof a boiler, gas turbine unit, combined-cycle unitor internal combustion engine.” However, theprohibition against the use of oil and gas in newmajor fuel-burning installations applies only toboilers.

Cogenerators can seek any of four different ex-emptions from FUA. The one most likely to beused is the cogeneration exemption. If this doesnot apply, the permanent exemption for the useof a fuel mixture or the temporary exemptionsfor the future use of synthetic fuels or for publicinterest considerations may be available.

FUA allows a permanent exemption for cogen-erators if the “economic and other benefits ofcogeneration are unobtainable unless petroleumor natural gas, or both, are used in such facilities.”The Department of Energy (DOE) interprets thephrase “economic and other benefits” to meanthat the oil or gas to be consumed by the cogen-erator will be less than that which would other-wise be consumed by conventional separate elec-tric and thermal energy systems. Alternatively, ifthe cogenerator can show that the exemptionwould be in the public interest (e.g., a technicallyinnovative facility, or one that would help tomaintain employment in an urban area), DOE willnot require a demonstration of oil/gas savings(72). The regulations to implement the cogenera-tion exemption are in the process of being revisedin order to simplify the procedures for calculatingoil and gas savings. Therefore, it is uncertain howdifficult it will be to meet the exemption re-quirements, and thus how FUA will affect themarket penetration of cogeneration (67).

Although the permanent exemption for cogen-eration is likely to be the preferred route for

100 ● Industrial and Commercial Generation

potential cogenerators subject to the FUA pro-hibitions, several other exemptions may be ap-plicable in certain circumstances. First, a perma-nent exemption is available to petitioners whopropose to use a mixture of natural gas orpetroleum and an alternate fuel. Under this mix-tures exemption, the amount of oil or gas to beused cannot exceed the minimum percentage ofthe total annual Btu heat input of the primaryenergy source needed to maintain operationalreliability of the unit consistent with maintaininga reasonable level of fuel efficiency. Second, atemporary exemption is available to petitionerswho plan to use a synthetic fuel (derived fromcoal or another fuel) by the end of the exemp-tion period. Third, a temporary public interestexemption may be obtained when the petitioneris unable to comply with FUA immediately (butwill be able to comply by the end of the exemp-tion). One of the cases where this public interestexemption may be granted is for the use of oilor gas in an existing facility during the ongoingconstruction of an alternate fuel-fired unit (77).

NGPA grants an exemption from its incremen-tal pricing provisions to qualifying cogenerationfacilities under section 201 of PURPA. However,a similar exemption also is available to small in-dustrial boilers and to utilities. Thus, the poten-tially lower gas prices should not affect the rel-ative competitiveness of gas-fired cogenerationsignificantly. Moreover, plants burning intrastategas may not realize any savings because the fuelprice is often at the same level as the incremen-tal price. In addition, deregulation could largelyremove incremental pricing. These uncertaintiesmean that NGPA probably will not be a majorfactor in cogeneration investment decisions (58).

Environmental Regulation

Federal, State, and local requirements for en-vironmental and safety regulation will affectcogeneration, although not to the same degreeas they do central station powerplants. The prin-cipal effects will result from permitting re-quirements and from the multiple jurisdictionalresponsibility for such permitting, which couldincrease the cost and Ieadtimes for deploymentof cogenerators and impose additional burdenson State agencies.

THE CLEAN AIR ACT

As discussed in chapter 6, cogeneration canhave significant impacts on air quality, especial-ly in urban areas. Depending on a cogenerator’ssize and location, it may be subject to one ormore of the Clean Air Act provisions, includingnew source performance standards (NSPS) andprograms for meeting and maintaining the Na-tional Ambient Air Quality Standards (NAAQS)in nonattainment and prevention of significantdeterioration (PSD) areas.

At present, NSPS exist for two types of sourcesthat might be used for cogeneration, and havebeen proposed for a third. NSPS have been im-plemented for electric utility steam units ofgreater than 250-MMBtu/hr heat input. However,cogeneration facilities in this category are exemptfrom NSPS if they sell annually less than either25 MW or one-third of their potential capacity.The other promulgated NSPS is for gas turbinesof greater than 10 MMBtu/hr heat input at peak-Ioads, but units in the 10-to 100-MMBtu/hr rangeare exempt until October 1982 and, in addition,have higher allowable nitrogen oxide (NOX)emission limits than units above 100 MM Btu/hr.NSPS have been proposed for NOX emissionsfrom both gasoline and diesel stationary engines.As proposed, they would apply to all dieselengines with greater than 560 cubic inch dis-placement per cylinder. Finally, the Environmen-tal Protection Agency is considering an NSPS forsmall fossil fuel boilers. The agency is reported-ly considering lower limits in the range of 50 to100 MMBtu/hr heat input. However, regulationshave not yet been proposed. Thus, only the NSPSfor gas turbines and the proposed standards forstationary internal combustion engines seem like-ly to affect cogeneration systems, and then onlyif they are larger than the prescribed limits.

PSD regulations would apply to fossil fuelboilers of greater than 250-MMBtu/hr heat inputthat emit more than 100 tons per year (tpy) ofany pollutant, and also to any stationary sourcethat emits more than 250 tpy of any pollutant(assuming that controls are in place). A PSD per-mit is only issued following a review of projectplans, and an assessment of project impacts onair quality based on modeling data and up to 1

Ch 3—Context for Cogeneration • 101

year of monitoring. These modeling and monitor-ing requirements can be expensive. For instance,one estimate suggests that the requisite model-ing and other PSD requirements add from$35,000 to $80,000 to the installation costs of a3-MW diesel cogenerator in New York City (1 2).

The application of the nonattainment area re-quirements to cogenerators also depends on sys-tem size; here the trigger is the capability of emit-ting 100 tpy of a pollutant. Sources with higheremissions must meet the lowest achievable emis-sion rate (LAER), secure emissions offsets, anddemonstrate companywide compliance with theClean Air Act. Smaller sources must use reason-ably available control technology and are sub-ject to the general requirement for “reasonablefurther progress” toward the NAAQS in nonat-tainment regions.

OTHER FEDERAL REQUIREMENTS

In addition to the potentially extensive permit-ting requirements for cogenerators under theClean Air Act, facilities with any cooling waterdischarges may also need National Pollutant Dis-charge Elimination System (NPDES) permitsunder the Clean Water Act. The NPDES permitgenerally specifies the applicable technologicalcontrols or effluent limitations required to achievethe water quality standards for the receivingwaters. These permits are only likely to be re-quired for large industrial cogenerators.

Because the only major Federal permit or au-thorization requirements for cogenerators arethose under the Clean Air and Water Acts, theyare not likely to be subject to the NEPA processor to the other environmental requirements ap-plicable to central station powerplants. However,operating cogeneration facilities can come underthe purview of OSHA, especially with regard tonoise standards and the general OSHA record-keeping requirements. Any restrictions imposedshould not be sufficiently burdensome to dis-courage the deployment of cogenerators.

STATE REGULATION*

State governments are required to implementthe Federal permit processes under the Clean Air

*Except where noted otherwise, the discussion in this section isdrawn from Energy and Resource Consultants, Inc. (22).

and Water Acts. States may or may not have otherenvironmental or safety regulations beyond thosemandated by Federal law, and State implemen-tation of the Federal requirements may vary wide-ly, depending on their orientation toward regula-tion as well as on the regional environmentalquality. A survey of all State requirements for en-vironmental and safety regulation of cogeneratorsis beyond the scope of this report. However,some general trends are noted below with a spe-cific comparison of a State with more rigorousrequirements (California) and one that has fewrequirements beyond those mandated by Federallaw (Colorado).

Colorado.–The permitting process in Coloradoclosely tracks the requirements of Federal laws(described in the previous section). One Coloradoenvironmental law deserving some explicit atten-tion is the Colorado Air Quality Control Act(CAQCA), which deviates from the Federal re-quirements in three ways. First, CAQCA requiresessentially all new or modified sources to file anAir Pollution Emission Notice (APEN). Second, allnew or modified sources must apply for an emis-sion permit which is required for both nonattain-ment and PSD areas, and which applies to vir-tually all fossil fuel facilities except small stationaryinternal combustion engines and gas burners withless than 750,000-Btu/hr heat input. Third,CAQCA’S significance levels for nonattainmentareas are considerably lower than those specifiedunder the Federal program (e.g., 10 tpy of par-ticulate or sulfur dioxide (S02) rather than the40 tpy under Federal regulations). Otherwise, thepermitting procedures under the Colorado Actare essentially the same as those under the Fed-eral requirements.

The length and complexity of the permittingprocess for cogeneration in Colorado will dependon the choice of site. Important site-specific fac-tors may include whether Federal or State landsare involved, impacts on surface waters, and am-bient air quality levels. Permitting agencies shouldbe contacted simultaneously in order to reducethe time required for licensing and decrease theamount of paperwork.

For this assessment, the Colorado permittingprocess was applied to two hypothetical cogen-eration facilities: a large cogeneration unit con-sisting of a new coal-fired boiler of 200-MMBtu/hr


heat input, with steam turbine topping capabili-ty, located in an urban area and not selling anyexcess electricity to the grid; and a small cogen-eration unit, represented by a commercial firm’sretrofitting a 15-MMBtu/hr diesel engine to supplya maximum of 2-MW electrical output with ex-cess power available to the grid during times ofpeak demand.

Large Cogeneration Project-Air Permits: Muchof the front range area in Colorado is nonattain-ment for particulate; however, with only min-imal control, the 200-MMBtu/hr boiler will notemit over 100 tpy of particulate and thus wouldnot be subject to the strict nonattainment arearequirements. Because the entire State is in at-tainment for S02 the plant would require a PSDpermit only if it emits more than 250 tpy. Assum-ing a 70 percent load factor and the use of coalwith a 1 percent sulfur content, the uncontrolledS02 emissions could approach 1,000 tpy, whichwould not meet the S02 emission rate of less than1.2 lb/MMBtu for an emission permit under thenew fuel burning equipment regulations. Thus,the sponsors for this hypothetical project mustchoose between achieving a 75-percent reduc-tion in S02 emissions or going through the PSDpermit process. Note that under the bubble con-cept for PSD, the source may have some emis-sion credits from the existing boiler.

Large Cogeneration Project– Water Permits: Ifthe boiler’s cooling system were to result indischarge to surface waters, a waste dischargepermit would be required, as part of the State im-plementation of the NPDES program. Althoughexisting sources can negotiate a complianceschedule for achieving discharge limits, newsources must meet those limits from the start.

Small Cogeneration Facility: The smallcogenerator will have to file an APEN and applyfor an emission permit. A 15-MMBtu/hr diesel unitdoes not qualify as a major source under eitherthe PSD or new source review programs for par-ticulate or S02, and at present no NOX standardhas been promulgated for diesels. However, itwill be subject to the (as yet undefined) minorsource requirements for particulate because itis located in a nonattainment area.

There is little experience with which to judgethe impacts of the Colorado permitting processon cogeneration facilities. There are only threecogeneration units in the State, and none is in-terconnected with the utility grid. Colorado hasno special laws, procedures, or exemptions thatmight suggest a State “policy” toward dispersedgenerating technologies. Rather the existing reg-ulations derive principally from Federal man-dates, which (except for PURPA and the cogen-eration exemption under FUA) make no specialrecognition of dispersed facilities. Thus, theregulatory obstacles to dispersed facilities in Col-orado are not severe. Most of the required per-mits and approvals can be secured in less than6 months and at modest expense, and, further-more, have cost and time requirements commen-surate with the project size. The only regulatoryobstacles would likely be the nonattainment areaand PSD requirements for large cogenerationunits, and the time the developers will have tospend determining what permits will be necessaryfor their facilities. At present, there is no centralclearinghouse dispensing information on the per-mitting process.

California.– Regulation of cogeneration inCalifornia is complex, but highly organized. Theincreased complexity arises in two ways: first, dueto the large number of agencies and commissionswith regulatory responsibility in California; andsecond, due to the regionalism of major regula-tory programs, notably air, water, and coastalzones. For example, the California Air ResourcesBoard (CARB) administers the Clean Air Act inCalifornia. Yet 46 local and regional air pollutioncontrol districts (APCDS) are responsible for con-trolling pollution from stationary sources throughpermitting, enforcement, and the adoption ofcontrol standards (often more stringent than thoserequired by CARB). Similarly, although the StateWater Resources Control Board administers theClean Water Act in California, most decisionsregarding permits and enforcement are made bynine regional boards and their staffs.

The high degree of organization of the permit-ting process in California stems from the roleplayed by the Office of Permit Assistance (located

Ch. 3—Context for Cogeneratlon . 103

in the Governor’s Office of Planning and Re-search), which helps project sponsors identify andmeet regulatory requirements. The office screenspermit applications and acts as an intermediarybetween projects and agencies. Another unit withthe Office of Planning and Research, the StateClearing House, attempts to coordinate the prep-aration of, and comments upon, environmentalstatements—either environmental impact reportsunder the California Environmental Quality Act(CEQA), or joint statements under CEQA andNEPA.

The permitting process in California centersaround the requirement for an environmental im-pact report (EIR) under CEQA. If the lead agen-cy decides that an EIR is required, one is preparedby that agency in consultation with all other per-mitting agencies, who must propose definitemeasures to mitigate any significant impacts iden-tified in the EIR. The entire process is subject toa schedule, defined by statute, such that all deci-sions on a project must be complete within 18months of the date the initial application was ac-cepted by the lead agency.

The permitting process in California was ana-lyzed for the same hypothetical large and smallcogeneration facilities as discussed for Colorado,above.

Large Cogeneration Project–Air Permits: Everysource of air pollution in California requires atwo-stage permit. The first stage is an authorityto construct based on a review of project plans,and the second stage, following construction, isa permit to operate based on a performance test.The authority to construct and permit to operaterequire compliance with the emission limitationsset by the local APCD. New source review rulesalso will apply if the source triggers any nonat-tainment area requirements. Although the basicnonattainment area rules (such as LAER, emissionoffsets, and companywide compliance) applyacross all APCDS, each APCD determines the trig-ger levels, in terms of pounds of emissions perday, for nonattainment areas. Although concep-tually straightforward, the regulations generatedby 46 APCDS for several classes of sources andhalf a dozen individual pollutants are volumi-nous.

Most APCD trigger levels for new source reviewin nonattainment areas are more stringent thanthe Federal requirements. Much of California isin attainment for S02, but the industrial areas aregenerally nonattainment for TSP and NOX. As-suming that the 200-MMBtu/hr coal boiler hasNOX emissions of 0.7 lb/MMBtu, it would emit140 lb/hr of NOX, thus triggering the LAER re-quirement. In addition, an EIR under CEQA maybe required. In any event, a final decision by theAPCD whether to issue an authority to constructmust be made within 1 year.

Large Cogeneration Project–Water Permits:California’s waste discharge requirement programpredates the Clean Water Act but encompassesthe same sources as the NPDES and section 401programs. For a point source discharge to sur-face waters, the State waste discharge require-ment serves as an NPDES permit. Similarly, re-quests for a section 401 Water Quality Certificatewill result in either a waste discharge requirementif the proposed project would affect water quality,or a letter to the effect that no certificate is re-quired because no impacts are anticipated. Allpermitting is done by the regional boards in ac-cordance with general standards and criteriadeveloped in their water pollution control plansand, in the case of sources subject to NPDES,using the various Federal technological standards.The waste discharge requirement applies to allpoint source discharges and additionally to anydischarges onto land or to a private pond, andwould thus be required for most large cogenera-tion projects.

Srnall Cogeneration Facility: in addition to anauthority to construct, the small cogenerator mayneed to meet nonattainment area requirementsfor NOX. A 15-MMBtu/hr heat input cogeneratorwith emissions of 3.5 lb/MMBtu would result inover so lb/hr of NOX emitted. These would beoffset (under the bubble concept) by the emis-sion level of the diesel engine before the retrofit(if any); so the net increase mayor may not ex-ceed the applicable trigger level.

The differences between environmental regula-tion in California and Colorado primarily resultfrom the environmental review process man-dated by CEQA, and California’s aggressive but

104 ● Industrial and Commerc ia l Cogenerat ion

helpful approach to regulating energy develop-ment. The guidelines under CEQA and NEPA forconducting environmental review are quite sim-ilar; in fact, many projects will prepare statementsacceptable under both guidelines even if CEQAalone is thought to apply. However, the impactof CEQA in California, as compared to NEPA inColorado, is greater because the environmentalreview process can be triggered by State, coun-ty, and municipal actions, whereas NEPA is trig-gered only by Federal action. Thus, many moreprojects may need to prepare environmental re-views in California than in Colorado. This putsmore projects into the public arena, but shouldnot result in delays so long as the statutory sched-ules for permitting are followed.

On the other hand, there are several initiativesin California that encourage cogeneration andmay help shorten part of the permitting process.First, new State legislation makes it easier for 50MW or smaller cogenerators to obtain air quali-ty permits. Under this legislation, cogeneratorswill receive an emissions credit equal to the emis-sions that would have come from a powerplantgenerating the same amount of electricity. In ad-dition, the statute requires CARB and the APCDSto develop a procedure to determine the avail-ability and magnitude of the offsets which resultwhen cogeneration facilities displace power-plants. Thus, in effect, the statute shifts the burdenof acquiring nonattainment area offsets from thepotential cogenerator to the APCD (1 1).

As a further aid to cogeneration, two specialadministrative offices have been established toassist prospective cogenerators with regulatoryrequirements: the Cogeneration Desk of the Of-fice of Permit Assistance, and the Project Evalua-tion Branch of the Stationary Source Control Divi-sion in CARB. Both of these offices are designedto provide assistance in obtaining permits andmeeting air quality requirements. Moreover, theGovernor’s Task Force on Cogeneration (whichincludes directors from CARB, the Office of Plan-ning and Research, the California Energy Com-mission, and the public Utilities Commission) isactively seeking ways to encourage cogenerationin the State. Each of these agencies has specialpersonnel available to assist potential cogener-ators with all aspects of their project, including

legal and technological problems. The ex-periences of recent California cogeneration proj-ects suggest that environmental and other regu-latory requirements are not a major obstacle,especially for smaller facilities. However, poten-tial cogenerators may perceive the permittingprocess to be onerous, and the principal task forState agencies is likely to be convincing poten-tial cogenerators that the regulatory requirementsare not insurmountable.

Financing and Ownership

The basic aspects of financing electric utilitycapacity additions (reviewed in the previous sec-tion) are applicable to cogenerators. A numberof other elements special to cogeneration arediscussed below, including the tax and financ-ing aspects of cogeneration and considerationsrelated to the different ownership categories:private investors, IOUS, tax-exempt entities, andrural electric cooperatives. *

General Considerations

General considerations related to financing andownership of cogeneration technologies includethe ownership and purchase and sale terms ofPURPA (discussed above), the utility financingprovisions of the National Energy ConservationPolicy Act (NECPA) of 1978 (as amended by theEnergy Security Act of 1980), tax incentives of theNational Energy Act, the Windfall Profits Tax Act,and the Economic Recovery Tax Act, aspects ofproject financing and lease relationships, andcapital recovery factors.

The most important sections of the EnergySecurity Act for the purposes of this assessmentare contained in title IV—Renewable Energy ini-tiatives, and title V—Solar Energy and Energy Con-servation. Title IV establishes incentives for theuse of renewable energy resources includingwind, solar, ocean, organic wastes, and hydro-power; only those provisions related to the useof organic wastes as fuel are applicable to cogen-erators. Funding of $10 million in fiscal year 1981was established to promote renewable energy re-

*Except where noted otherwise, the analysis in this section is fromL. W. Bergman & Co. (37).

Ch. 3—Context for Cogeneration • 105

sources under a 3-year pilot energy efficiencyprogram.

Title V set up a Solar Energy and Energy Con-servation Bank in the Department of Housing andUrban Development to make payments to finan-cial institutions in order to reduce either the prin-cipal or interest obligations of owners’ or tenants’loans for energy conserving improvements to res-idential, multifamily, agricultural, and commer-cial buildings. For commercial buildings, the eligi-ble improvements specifically include cogenera-tion equipment. Direct grants to owners andtenants of residential or multifamily buildings alsowere authorized but were limited to lower in-come people. No investment tax credits (onlyenergy credits) were allowed for any projects in-stalled under loans from the Solar Bank, and ex-penditures were to have been made after January1, 1980. The bank was intended to continue op-erations through September 30, 1987, but thefiscal year 1981 budget eliminated all funding forthe Bank and its future is, at best, highlyuncertain.

The Energy Security Act also amended NECPAto permit utilities to supply, install, and financeconservation improvements or alternate energysystems (including cogenerators) as long as inde-pendent contractors and local financial institu-tions are used and no unfair competitive prac-tices are undertaken by the utility. Utilities areeligible to qualify as lenders and receive subsidiesto pass on to customers. Local governments andcertain nonprofit organizations are eligible bor-rowers.

In addition to the regular investment tax creditof 10 percent on most capital investments, severalenergy incentives have been passed in recentyears. Under section 48(1) of the Internal Rev-enue Code a number of “energy properties” aredefined and set aside for special treatment underthe investment tax credit (see section on “Taxa-tion, ” above). Property is not eligible for thesespecial incentives to the extent that it uses sub-sidized energy financing (including industrialdevelopment bonds), or is used by a tax-exemptorganization or governmental unit other than acooperative. public utility property (that for whichthe rate of return is fixed by regulation) is ex-

cluded from these energy incentives even if itutilizes solar, wind, biomass, or other alternativesources of energy such as synthetic liquid orgaseous fuels derived from coal.

The methods of project finance are particularlyappropriate to the financing of distributed elec-tricity generation. project financing looks to thecash flow associated with the project as a sourceof funds with which to repay the loan, and to theassets of the project as collateral. For successfulproject financing, a project should be structuredwith as little recourse as possible to the sponsor,yet with sufficient credit support (through guar-antees or undertakings of the sponsor or third par-ty) to satisfy lenders. In addition, a market for theenergy output (electrical or thermal) must be as-sured (preferably through contractual agree-ments), the property financed must be valuableas collateral, the project must be insured, and allGovernment approvals must be available (47).With the adoption of PURPA, a source of reve-nues (rates for power purchases) has becomeavailable for small-scale energy project finance.

However, the uncertainty surrounding futurerates for power purchases (due to the 1982 Courtof Appeals decision discussed previously and thepending Supreme Court review of that decision)has chilled the interest of potential financialbackers of cogeneration and small power proj-ects. The revenue stream from utility purchasesof cogenerated power is used to secure the proj-ect financing. Because the future level of thatrevenue stream is in doubt, bankers and otherinvestors are reluctant to commit funds until theissue is resolved.

Leasing is a form of project finance becausefixed payments are used to amortize capitalequipment. Two types of lessors may be involvedin project financing: sponsors of a project wholease to the project company, and third-pattyleasing companies that are in the finance busi-ness. The third-party lessors may have more at-tractive rates because they utilize the tax benefitsof owning the equipment.

The Economic Recovery Tax Act of 1981substantially changed the tax treatment of leas-ing to make it very attractive for projects like

98-946 0 - 83 - 8: QL 3

106 ● Industrial and Commmercial Cogeneration

cogeneration. If a cogenerator is unable to takeadvantage of tax credits (e.g., already has a lowtax liability), the tax advantages can be transferredto another party under the safe harbor leasingprovisions of ERTA. In essence, these provisionsallow the property to be sold for tax purposesonly to a corporation in a higher tax bracket. Thecorporation would give the cogenerator a cashpayment (e.g., 25 percent of the property’s value)and a note for the remainder of the purchaseprice, and then lease the equipment back to thecogenerator. Payments due under the note wouldbe matched exactly by the lease payments. Thus,no money actually changes hands after the in-itial cash payment, and with the exception of thetax difference between lease payments (which areexpensed in full) and income from the note(which reflects only its interest component), thetransaction is extremely advantageous to bothparties (33).

The capital recovery factor, as used in this sec-tion, is the cost per kilowatthour which the ownerof a cogenerator must receive to recover itscapital in a given period of time. Table 20 com-pares capital recovery factors for four classes ofownership that reflect different income tax struc-tures: a nonutility investor with a 50-percentmarginal tax rate; a utility with a 50-percentmarginal tax rate; a utility with a 10-percentmarginal tax rate that is unable to take advantageof investment tax credits because it already hasan excess of such credits; and a nontax-payingentity. In all cases the capital recovery factors aregreatest for utilities in the high tax brackets andlowest for nontaxable entities.

One way for an investor to get around highcapital recovery factors is to use long-term bondfinancing. With high leverage, the equity investor

is able to recover his investment in a shorterperiod of time because the bond holder is will-ing to wait to recover his capital. However, highleverage increases the risk to the equity investorand therefore also increases the required returnon equity. Thus, depending on the terms of debtand equity markets, debt financing can makethese investments more attractive. It is also im-portant to note that utilities are more comfortablewith longer capital payback periods than nonutili-ty equity investors, and that nonprofit entitieshave a different set of criteria for evaluatinginvestments.

Industrial, Commercial, and Privateinvestor Ownership

Industrial, commercial, vendor, and privateownership share (for the most part) a commontax status and will be discussed together. As notedpreviously, energy tax credits, coupled withregular investment tax incentives and the PURPAbenefits, encourage private firms to enter smallpower production. The ability to obtain up to25-percent investment tax credits offers an enor-mous boost to cash flow early in the project’s life.These tax credits can be further magnified, in rela-tion to invested equity, by debt leverage by a fac-tor of 4. PURPA provides a guaranteed marketfor the power output and it encourages the de-velopment of contractual relationships betweencogenerators and utilities. In project finance, suchcontracts are preferable to operating under a tariffstructure because contractual relationships areless subject to arbitrary cancellation or alterationof the terms of delivery.

While the incremental investment tax credit forcogeneration is limited (particularly if the cogen-erator uses oil or gas), industrial companies have

Table 20.—Capltal Recovery Factors for Cogenerationa

(cents per year per kllowatthour, In 1980 cents)

Nonutility High tax rate Low tax rate Nontax payinginvestor utility utility utility

5 year . . . . . . . . . . . . . . . . . . . 3.6cents 4.2cents 3.Ocents 2.8cents10 year . . . . . . . . . . . . . . . . . . . 1.6 1.9 1.515 year . . . . . . . . . . . . . . . . . . . 1.1 1.2 0.99 0.9320 year . . . . . . . . . . . . . . . . . . . 0.77 0.91 0.74 0.70a1980 capital cost $700/kw; usage 5,000 hrs/yr; depreciation Iifetime 20 years.

SOURCE: L. W. Bergman &Co., Financing and Ownership of Dispersed E/ectriclty Generating Technologies (contractor reportto the Office of Technology Assessment, February 19S1).


some experience with cogeneration and nowhave the added advantage of PURPA’S purchaseand sale requirements. Continued Federal andState Government support of simultaneous pur-chase and sale at full avoided costs is viewed bysome as the single most important factor in over-coming industry indecision to cogenerate (27).

Existing and potential industrial cogenerationparticipants include industrial parks, integratedpulp and papermills, other process industries(e.g., chemicals, petroleum refining, steel, foodprocessing, textiles), and heavy oil recovery proj-ects (see analysis of industrial cogeneration in ch.6).

Financing options for industrial cogenerationmay be quite varied depending on the size andfinancial strength of the industrial firm. These op-tions include:

●

●

●

●

●

●

●

retained earnings;debt issues (including bonds, bank loans, andprivate placements with insurance compa-nies, pension funds, and similar institutions);equity issues;joint ventures with other industrial firms (seecase 1 ) or with utilities;joint partnership with equity investors suchas insurance companies (who may be bothlenders and equity investors) and tax sheltersyndicates (see case 2);leasing arrangements with third parties andvendors, including leveraged leases and safeharbor leases (under ERTA); andjoint ventures and operating relationshipswith tax-exempt entities such as municipali-ties and public power companies. Tax-exempt parties can raise lower cost debtwhile transferring tax ownership and taxbenefits to the private parties.

The incentive to commercial firms to invest incogeneration will rest heavily on a comparisonbetween the cost of cogenerated electricity (es-pecially the fuel cost) and the price the commer-cial cogenerator pays for its electricity and heat(comparative basis). Because of their smaller size,commercial firms often do not have financialresources equivalent to those of industrial firmsand will be less interested in large scale projectsunless they can be cooperatively owned (50).


Sources of financing for commercial cogenera-tion would be similar to those for industrialcogeneration with the following qualifications:

● banks will be a more important source offunds than for industrial firms;

. there will be a greater dependence on out-side developers and financial packages;

● joint venture funding will be very useful forregional malls, large buildings, and commer-cial parks; and

. vendors and third-party lessors will be quiteimportant, particularly for diesel cogenera-tion (see case 3).

Private investors may be interested in cogen-eration because of the unusual tax incentivesavailable and the possibility of an above invest-ment return in unusually promising situations.Joint venture relationships will be most advan-tageous to private investors, including tax sheltersyndicates that provide the equity portion of aleveraged lease and shift tax ownership amongthe partners. Vendors might provide financingand traditional lease arrangements, particularlyin the case of diesel cogenerators, or third par-

ties could take advantage of ERTA’s-safe harborleasing provisions.

Where the owner (industrial, commercial, pri-vate investor) is a single entity and no outsidejoint ventures are involved, project financing viaequity, secured or unsecured bank loans, debt,or lease arrangements is straightforvvard. Certainassurances or guarantees will be needed, how-ever, in structuring the financing. These mightinclude:

contractual arrangements with a utility forelectricity purchases under a take-or-pay con-tract;contractual arrangements with the thermalenergy purchaser; ortrustee relationships between the lender andrevenue source with excess revenues overfixed charges remitted to the project owner.

Finally, some IOUS may also have financial as-sistance programs for industrial, commercial, andother private investors in cogeneration. For ex-ample, Southern California Gas Co. offers, fund-ing assistance of up to $100,000 or 20 percentof the capital cost (excluding installation labor)for their cogenerating customers. Southern Cali-fornia Gas will co-fund upto$10,000 for the fea-sibility study (or 10 percent of the study’s cost,whichever is less). If the feasibility study ispositive, then the company will co-fund up to$40,000 (or 50 percent) of the cost of the designphase of the project, leaving $50,000 for installa-tion and startup (62).

lnvestor-Owned Utility Ownership

Because almost all electric IOUS are in the busi-ness of generating electricity, they are logicalpotential owners of dispersed generation facilities.The small size, shorter Ieadtimes, and lower cap-ital requirements of cogeneration systems mayprovide short-term advantages to utilities in plan-ning for uncertain demand growth. However, thePURPA limitations on utility ownership discour-age utility investment in cogeneration. Moreover,most large utilities do not see dispersed generat-ing facilities—including cogeneration—as havingthe ability to replace future central generating sta-tions, and the low-earned utility rates of returnin recent years may not be high enough to en-


courage utility investment in technologies withuncertain electricity output.

Full (100 percent) utility ownership may bevery advantageous if a utility faces revenue lossesdue to industrial or commercial cogeneration (seech. 6). For instance, Arkansas Power & Light(AP&L) estimates that if their 35 industrial custom-ers who are prime cogeneration candidates hadcogenerated in 1981, AP&L’s estimated revenueloss for that year would have been almost $40million. However, if AP&L developed and ownedthe cogeneration systems for those 35 industrialcustomers, not only would they retain that indus-trial market for electricity, but they would havean additional revenue stream from steam sales—potentially $500 million in the mid-1980’s (44).Moreover, if potential industrial or commercialcogenerators are unable to burn coal (e.g., dueto space or environmental limitations), or are un-willing to assume the risk of advanced technol-ogies (e.g., gasification), utility ownership withelectricity and steam distribution can centralizethe burden of using alternate fuels. However, thefull incremental ITC is not available for utility-owned cogenerators nor are PURPA benefitsavailable if an IOU owns more than 50 percentof the cogeneration facility. (The potential advan-tages and disadvantages of full utility ownershipare discussed in detail in ch. 7.)

Alternatively, a utility may decide to participatein a joint venture for a cogeneration facility (seecases 4 and 5) in order to structure the owner-ship in such a way that the investment tax creditand other tax benefits are diverted to the nonutili-ty participants. in addition, financing can bestructured so that any debt related to the facility(with the exception of relatively small amountsfor working capital) will not appear on the utili-ty’s balance sheet. This structuring would be ap-propriate for utility-financed industrial cogenera-tion or biomass projects.

Tax= Exempt Entities

The key advantage enjoyed by municipalitiesin issuing debt is the tax-free status of the interestpaid on their obligations, which results in a lowerinterest rate than that paid on taxable securities.The current spread in yields between new AAA

long-term IOU bonds and AAA municipal generalobligation bonds is around 375 basis points (100basis points equals 1 percentage point); betweenthe same utility bonds and revenue bonds thespread is around 330 basis points.

Section 103 of the Internal Revenue Code setsout the provisions for a security to receive tax-exempt interest treatment. Section 103(a) ex-empts the interest on an obligation of a State orpolitical subdivision (which would include gen-eral obligation bonds). Section 103(b), however,

110 . Industrial and Commercial Cogeneratlon

denies tax-free status for industrial developmentbonds (IDBs) except for specific exemptions. Inorder for IDBs to qualify for tax-exemption, morethan 25 percent of the proceeds of an obligationmust be used by a nonexempt person for businesspurposes; a major portion of the principal or in-terest must be secured by business property; and,in the case of a take-or-pay contract with an elec-tric facility, the contract must be with a nonex-empt person and in exchange for payments total-ing more than 25 percent of the total output debtservice. Moreover, the facilities financed by tax-exempt IDBs must be for general public use andfor specified activities including:

solid waste disposal facilities for the local fur-nishing of electric energy;air or water pollution control facilities; andacquisition or development of land for in-dustrial parks, including development forwater, sewer, power, or transportation pur-poses.

Under the Windfall Profits Tax, solid waste-to-energy facilities are eligible for tax-exempt financ-ing with IDBs if over half of the fuel is derivedfrom solid waste, and the facility is owned by agovernmental authority, although year-to-yearmanagement contracts with business corpora-tions are allowed.

Perhaps the most important exemption for tax-free financing is the small issue exemption, underwhich up to $1 million in IDBs (or $10 millionprovided total capital expenditures do not exceed$10 million) can be issued for any trade or busi-ness for the acquisition of land or property sub-ject to depreciation. However, if all of the pro-ceeds of a bond issue are used to finance a proj-ect for which an Urban Development ActionGrant (UDAG) has been made, then the capitalexpenditure can be $20 million, of which $10million must come from sources other than tax-exempt obligations. Renewable energy proper-ty is eligible for a special exemption if the bondsused to finance it are general obligations.

Cogeneration is not eligible for special energytax incentives if over 25-percent fueled from oilor gas. As the technology becomes available,coal-fired cogeneration plants will qualify forspecial tax incentives and be economically attrac-

tive. In the meantime, the best financing strategyfor municipalities to foster cogeneration develop-ment using available technologies may be to max-imize the use of tax-exempt financing (see case 6).

Industrial parks also are an excellent applica-tion in which municipalities can foster the devel-opment of cogeneration. Tax-exempt IDBs canbe issued without limit under a specific exemp-tion for the acquisition of land for industrial parksand its upgrading including water, sewage, drain-age, communication, and power facilities priorto use. Cogeneration facilities (including steamdistribution lines) presumably would fall into thisspecific exemption. The requirements encouragejoint ventures between the exempt entity andbusinesses, but the funds must be used by thenonexempt entity in a trade or business andpayments secured by an interest in property usedin a trade or business. Moreover, some State lawsprohibit municipalities from entering into cor-porate relationships with the private sector, butindependent public bonding authorities usuallycan be established to get around such prohibi-tions.

Any number of lessor-lessee relationships alsoare possible between a municipality and a cor-poration. An important aim of the financing struc-ture would be to allow the corporation to pickup the lo-percent investment tax credit (see case7).


Finally, an innovative financing option formunicipal utilities and other local governmentagencies that has attracted a lot of attention inCalifornia is the municipal solar utility (MSU). Asoriginally conceived, an MSU would reduce thecapital and maintenance costs of solar hot watersystems (or other alternative energy or conser-vation measures) by: 1) only charging customersfor their installation; 2) spreading that charge over

the lifetime of the system in the monthly electricbills; and 3) providing continued maintenance(28). More recently, the MSU concept has beenexpanded to include programs such as brokerageof different financial and service packages,dedicated deposits of city funds in local banksfor low interest alternative energy loans, ortechnical assistance and other community out-reach programs (60).

Rural Electric Cooperative Ownership

Rural electric cooperatives are finding it moredifficult to purchase additional electricity fromtheir traditional sources (IOUS and Federal powerauthorities) and consequently are being forcedto build or participate in new generating capaci-ty. Within this context, dispersed facilities (in-cluding cogeneration) may be advantageous dueto the shorter construction times, greater plan-ning flexibility, and lower capital costs. In addi-tion, alternate energy projects are more readilyfinanced at favorable terms. Such financing in-cludes 35-year loans for feasibility studies underthe REA insured loan program, and is designedto help overcome the lack of engineering exper-tise and other resource constraints faced by smalldistribution co-ops that wish to add generatingcapacity. As with other electric utilities, co-opswill prefer projects that provide most of their ad-ditional capacity during peak demand periodsand whose electricity output is not intermittent(e.g., biomass, hydroelectric, and industrialcogeneration projects).

For a project with IOO-percent co-op owner-ship, all the benefits accrue to the cooperative’smembers (e.g., no taxes are paid and no profitsare distributed to investors). Capital is raisedthrough an REA guaranteed loan, which meansthat the cost of capital will be lower than for aprivate investor because the U.S. Governmenthas guaranteed the loan. Other financing optionsfor cooperatives include joint ventures with localgovernments or with industrial concerns (see case8).


1.

2.

3.

4.

5.

6.

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53.

Lock, Reinier H. J. H., “Statewide Purchase RatesUnder Section 210 of PURPA,” 3 Solar f.. Rep. 419(September/October 1981).Lock, Reinier H. J. H., and Van Kuiken, Jack C.,“Cogeneration and Small Power Production: StateImplementation of Section 210 of PURPA,” 3 SolarL.. Rep. 659 (November/December 1981).Messing, Marc, Friesema, H. Paul, and Morrell,David, Centralized Power (Washington, D, C.: En-vironmental Policy Institute, 1 979).Meyer, Joseph G., “One Utility’s Approach,”paper presented at The Energy Bureau Conferenceon Cogeneration, Washington, D. C., Oct. 13-14,1981.Mississippi v. FERC, Civil Action No. J79-0212(c), (S.D. Miss., 1980).Missouri Public Service Commission, Report andOrder in Case No. ER-80-48, June 19, 1980.Mitchell, Ralph C., Ill, et al., presentation to OTAstaff on Cogeneration in the Arkansas Power &Light Co. service area, Washington, D. C., Nov. 19,1981.National Rural Electric Cooperative Association,personal communication to the Office of Technol-ogy Assessment.Navarro, Peter, “The Soft, Hard, or Smart Path:Charting the Electric Utility Industry’s Future,” 107Pub. Util. Fort. 25, June 18, 1981.Nevitt, Peter K., Project Financing report preparedfor BankAmeriLease Group Companies by Ad-vanced Management Research, Inc. (2d cd.).New York public Service Commission, Case27574, 1980.North American Electric Reliability Council, Elec-tric Power Supply and Demand 1982-1991(Princeton, N.J.: North American Electric Reliabil-ity Council, 1982).Office of Technology Assessment, U.S. Congress,Energy Effciency of Buildings in Cities, OTA-E-168(Washington, D. C.: U.S. Government Printing Of-fice, March 1982).Office of Technology Assessment, U.S. Congress,The Direct Use of Coal OTA-E-86 (Washington,D. C.: U.S. Government Printing Office, April1979).Office of Technology Assessment, U.S. Congress,World Petroleum Availability; 19802000–ATechnical Memorandum, OTA-TM-E-5 (Washing-ton, D. C.: U.S. Government Printing Office, Oc-tober 1980).Olson, Charles E., “Public Utility Regulation inPractice and Its Impact on Electricity Demand and


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Chapter 4

Characterization of theTechnologies for Cogeneration

Contents

Pageintroduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . 117

Cogeneration Technologies . . . . . . . . . . . . . . . 122Steam Turbines. . . . . . . . . . . . . . . . . . . . . . . . 122Open-Cycle Combustion Turbines . . . . . . . . 125Closed-Cycle Combustion Turbines . . . . . . . 127Combined Cycles . . . . . . . . . . . . . . . . . . . . . . 129Diesels . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 131Rankine Cycle Bottoming . . . . . . . . . . . . . . . 133Fuel Cells . . . . . . . . . . . . . . . . . . . . . . . . . . . . 137Stirling Engines . . . . . . . . . . . . . . . . . . . . . . . . 139

Use of Alternative Fuels in Cogeneration . . . . 142Fluidized Bed Combustion Systems . . . . . . . 142Gasification . . . . . . . . . . . . . . . . . . . . . . . . . . . 143

{interconnection . . . . . . . . . . . . . . . . . . . . . . . . . 146Power Quality . . . . . . . . . . . . . . . . . . . . . . . . 146Metering . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 151Controlling Utility System Operations . . . . . 151Safety . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 153Liability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 154

Summary of RequirementsQuality of interconnection

Page

. . . . . . . . . . . . . . 154Equipment . . . . . 154

Guidelines for interconnection ~ . . . . . . . . . . 155Costs for interconnection . . . . . . . . . . . . . . . 157Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 158

Thermal and Electric Storage . . . . . . . . . . . . . . 159Thermal Storage.. . . . . . . . . . . . . . . . . . . . . . 159Electric Storage.. . . . . . . . . . . . . . . . . . . . . . . 161

Cogeneration and District Heating. . . . . . . . . . 163

Chapter preferences . . . . . . . . . . . . . . . . . . . . 165

Tables

Table No. Page

21. Thermal Analysis of ldeal and RealHeat Engines . . . . . . . . . . . . . . . . . . . . . . . . 118

22. Performance Characteristics of AlternativeElectricity-and Steam-ProductionSystems . . . . . . . . . . . . . . . . . . . . . . . . . . . . 119

Table No. Page

23.24.25.

26.

27.

28.

29.

30.

Summary of Cogeneration Technologies. . 120Diesel Engine Characteristics . . . . . . . . . . . 131Estimates of Steam Bottoming CycleOperation and Maintenance Costs . . . . . . 136Cogeneration interconnection Samplecosts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 157Interconnection Costs for Three TypicalSystems . . . . . . . . . . . . . . . . . . . . . . . . . . . . 158Thermal Energy Storage CapacityRange v. Plant Size. . . . . . . . . . . . . . . . . . . 160Cost and Performance Characteristics ofAdvanced Batteries . . . . . . . . . . . . . . . . . . . 162Expected Technical and CostCharacteristics of Selected ElectricalEnergy Storage Systems . . . . . . . . . . . . . . . . 163

Figures.

Figure No. Page16. Comparison of Energy Utilization in a

Cogeneration System and a ConventionalPowerplant. . . . . . . . . . . . . . . . . . . . . . . . . . 119

17. Steam Turbine Topping System in aCogeneration Configuration . . . . . . . . . . . . 123

18. Estimated Steam Turbine CogeneratorSystem Installed Costs With DifferentHeat Sources . . . . . . . . . . . . . . . . . . . . . . . . 124

19. Combustion Turbine . . . . . . . . . . . . . . . . . . 12520. Schematic of a Simple Open-Cycle

Combustion Turbine in a CogenerationApplication . . . . . . . . . . . . . . . . . . . . . . . . . 126

21. Combustion Turbine Cogenerator CostEstimates for the Prime Mover andTotal Installed System . . . . . . . . . . . . . . . . . 127

22. Closed-Cycle Gas Turbines With andWithout Regeneration . . . . . . . . . . . . . . . . . 128

23. Closed-Cycle Gas Turbine CogeneratorInstalled Cost . . . . . . . . . . . . . . . . . . . . . . . . 129

24. Schematic of a Combined-CycleCogenerator. . . . . . . . . . . . . . . . . . . . . . . . . 130

Figure No. Page25. Total Installed Costs for Combined-

CycIe Cogenerator Systems . . . . . . . . . . . . 13126. Diesel Engine Cogenerator . . . . . . . . . . . . . 13227. Diesel Cogenerator Total Installed

Costs for Current and AdvancedPrime Movers . . . . . . . . . . . . . . . . . . . . . . . 133

28. Steam Rankine Bottoming Cycle . . . . . . . . 13329. Organic Rankine Bottoming Cycle. . . . . . . 13430. Organic Rankine Bottoming Cycle

Efficiency-Variation With Peak CycleTemperature . . . . . . . . . . . . . . . . . . . . . . . . 135

31. Typical Energy Balances for SteamRankine Bottoming Systems . . . . . . . . . . . . 135

32. Estimated Installed Costs forCondensing and Non-condensing SteamRankine Bottoming Systems . . . . . . . . . . . . 136

33. Estimated Installed Costs for OrganicRankine Bottoming System. . . . . . . . . . . . . 136

34. Schematic Diagram of a Fuel Cell . . . . . . . 13735. Schematic ofa Fuel Ceil Powerplant. . . . . 13836. Representative Performance of Fuel

Cell Powerplants . . . . . . . . . . . . . . . . . . . . . 13937. Future Estimates of Total Installed

Costs for Fuel Cell Powerplant Systems. . . 14038. Schematic of a Stirling Cycle Engine . . . . . 14039. Waste Heat Availability From Different

Engines . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14140. Future Installed Costs for Stirling

Engine Cogenerator Powerplants . . . . . . . . 14141. Possible Power System Additional

Equipment Requirements to ServeQualifying Facilities . . . . . . . . . . . . . . . . . . . 155

42. Low-Temperature Thermal StorageCost per kWht v. Storage Capacity . . . . . . 160

43. High-Temperature Thermal StorageCost per kWht v. Storage Capacity.. . . . . . 161

44. European Cogeneration DistrictHeating System . . . . . . . . . . . . . . . . . . . . . . 164

Box

A. Thermodynamic Efficiency ofCogeneration. . . . . . . . . . . . . . . . . . . . . . . . . 118

Chapter 4

Characterization of the Technologies for Cogeneration

INTRODUCTIONCogeneration systems recapture otherwise

wasted thermal energy, usually from a heat en-gine producing electricity (such as a steam tur-bine, gas turbine, or diesel engine), and use it forspace conditioning, industrial processes, or as anenergy source for another system component(31 ). This “cascading” of energy use is what dis-tinguishes cogeneration systems from conven-tional separate electric and thermal energy sys-tems (e.g., a powerplant and an industrial boiler),or from simple heat recovery strategies. The auto-mobile engine is a familiar cogeneration systemthat provides mechanical shaft power to movethe car, produces electricity with the alternatorto run the electrical system, and recirculates theengine’s otherwise wasted heat to provide com-fort conditioning in the winter.

This chapter characterizes the technical fea-tures of cogeneration systems, including an over-view of the general fuel use and energy produc-tion considerations common to all cogenerators,a description of the operating characteristics andcosts of both commercially available and promis-ing future cogeneration technologies, and a dis-cussion of ancillary systems such as those forinterconnecting cogenerators with the utility grid,for improving cogenerators’ fuel flexibility, andfor storing the electric or thermal energy. A moredetailed characterization of cogeneration tech-nologies may be found in volume II of this report.

The principal technical advantage of cogenera-tion systems is their ability to improve the effi-ciency of fuel use in the production of electricand thermal energy. Less fuel is required to pro-duce a given amount of electric and thermal en-ergy in a single cogeneration unit than is neededto generate the same quantities of both types ofenergy in separate, conventional technologies(e.g., turbine-generator sets and steam boilers).This is because waste heat from the turbine-gen-erator set, which uses a substantial quantity ofthe fuel used to fire the turbine, becomes usefulthermal energy in a cogeneration system (e.g.,process steam) rather than being “wasted. ” To

be sure, this usually requires some reduction inthe amount of electricity produced compared toa stand-alone turbine generator, but this “sacri-fice” usually is acceptable to gain the 10- to30-percent increase in overall fuel efficiencyoffered by cogeneration (31 ). To see more clearlyhow this gain is achieved, box A provides a de-tailed look at the thermodynamics of cogenera-tion.

The relative efficiency of cogenerators and con-ventional powerplants is shown in figure 16. Ina conventional steam plant (which generally usesa Rankine cycle), energy must be added to thefeedwater in the boiler in sufficient amounts toraise it up to point A in figure 16 (steam for powergeneration). However, due to inherent inefficien-cies in the Rankine cycle turbine, the condens-ing turbines that drive the generators can onlyutilize the amount of energy between points Aand C in the figure (steam at the boiling point)to generate electricity. Thus, the large amountof energy from the boiler feedwater level to pointC is lost as the steam is condensed by coolingwater, carrying off the heat, and rejecting it tothe environment.

In the cogeneration plant in figure 16, the en-ergy from A to B (steam) is used to generate elec-tricity, the energy from B to D (water at boilingpoint) is used as process steam, and only the en-ergy from D down to the feedwater level is re-jected to the environment. Thus, the cogeneratorallows use of some of the energy that the conven-tional powerplant otherwise would waste. LevelB is determined by the temperature required forthe process steam.

Different types of cogenerators have differingfuel use characteristics and produce different pro-portions of electricity and steam. The electricity-to-steam (E/S) ratio refers to the relative propor-tions of electric and thermal energy produced by a cogenerator. The E/S ratio is measured in kilo-watthours per million Btu (kWh/MMBtu) of steam(or useful thermal energy), and varies among the

117

Ch. 4—Characterization of the Technologies for Cogeneration • 119

Figure 16.—Comparlson of Energy Utilization In a Cogeneratlon Systemand a Conventlonal Powerplant

A. Energy level at which steam —for power generation Is produced

B. Energy level at which process —steam is made available

C. Steam at boiling point — —

D. Water at boiling point — —

F e e d w a t e r ( e n e r g y a d d e d ) — —

Electricity only(conventional powerplant)

Electricity(cogenera t

and steamion plant)

SOURCE: Dow Chemical Co., et al., Energy industrial Canter Study (Washington, D. C.: National Science Foundation, June 1975).


different types of cogeneration technologies (seetable 23).

The total heat rate refers to the total amountof fuel (measured in Btu) required to produce 1kwh of electricity, with no credit given for theuse of “waste heat.” The net heat rate (alsomeasured in Btu/kWh) credits the thermal out-put and denotes the fuel required to produceelectricity, beyond what would be needed to pro-duce a given quantity of thermal energy in a sep-arate facility (e.g., a boiler). In a central power-plant, where no heat is recovered, an averagetotal heat rate is 10,500 Btu/kWh (60). Cogenera-tors have a net heat rate of about 4,300 to 7,500Btu/kWh depending on the characteristics of thethermal energy produced. Thus, depending onthe cogenerator type and how completely thethermal output is utilized, electricity can be pro-duced by a cogenerator with about one-half to

three-fourths the fuel used in central power gen-eration (45,60). Fuel use efficiency for a cogener-ator gives credit to the thermal output; hence itis the ratio of electric output plus heat recoveredin Btu to fuel input in Btu.

Table 21 presents a numerical example of heatrates and fuel efficiency-based on modern steamturbines—that compares: 1 ) an ideal engine ex-hausting to a low temperature, 2) a real engineexhausting to a low temperature (typical of a util-ity powerplant), 3) a real engine exhausting at ahigher temperature with the heat wasted (some-thing that is best to avoid), and 4) a real engineexhausting at a higher temperature with the heatutilized (as with a cogenerator). it is noted that,in the example in table 21, the fuel use efficiencyvaries from 35 percent for the utility powerplantto 75 percent for the cogenerator.

Table 23.—Summary of Cogeneration Technologies

Part-loadFull-load (at 50°/0 load)

Average annual electric electrlc Total Net heat Electriclty-to-Fuels used availability efficiency efficiency heat rate rate steam ratio

Technology Unit size (present/possible In future) (percent) (percent) (percent) (Btu/kWh) (Btu/kWh) (kWh/MMBtu)

A. Steam turbine 500 kW-100 MW Natural gas, distillate, 90-95 14-28 12-25 12,200-24,000 4,500-6,000topping

30-75residual, coal, wood,solid waste/coal- or bio-mass-derived gases andIiquida.

Natural gas, distillate,treated resldual/coal- orbiomass-derived gasesand liquids.

Externally fired—can usemost fuels.

Natural gas, dlstlllate,resldual/coal- or blomass-dertved gases and liquids.

Natural gas, distillate,treated residual/coal- orbiomass-derived gasesand liquids, slurry orpowdered coals.

B. Open-cycle gas 100 kW-100 MWturbine topping

90-95 24-35 19-29 9,750-14,200 5,5004,500 140-225

G. Glosed-cycle gas 500 kW-100 MWturbine topping

D. Comblned gas 4 MW-1OO MWturbine/steamturbine topping

E. Diesel topping 75 kW-30 MW

90-95

77-65

60-90

30-35

34-40

33-40

30-35

25-30

32-39

9,750-11,400

8,000-10,000

5,400- 6,500

5,000- 6,000

6,000-7,500

150-230

175-320

350-7006,300-10,300


Steam 500 kW-10 MW Waste heat. 90 10-20 Comparableto full loadComparableto full load

374534-40

17,OOO-34,1OO NA NA

Organic 2 kW-2 MW Waste heat. 80-90 10-20 17,OOO-34,1OO NA NA

G. Fuel cell topping 40 kW-25 MWH. Stirling engine 3-100 kW

topping (expect1.5 MW by1990)

Hydrogen, distlllate/coal.Externally fired—can usemost fuels.

90-92Not known-expected to besimilar to gas tur-bines and diesels,

37-4535-41

7,500-9,3008,300-9,750

4,300-5,5005,500-6,500

240-300340-500

Ch. 4—Characterization of the Technologies for Cogeneration . 121

Table 23.—Summary of Cogeneration Technologies—Continued

Operation and maintenance cost construction

Total installed Annual fixed cost Variable cost Ieadtime Expected lifetimeTechnology cost ($/kW)a ($/kW) (millions/kWh) (years)b (years) Commercial status Cogeneration applicability

A. Steam turbine 550-1,600 1.6-11.5 3.0-8.8 1-3 25-35topping

Mature technology —com-mercially available In largequantities.

This Is the most commonlyused cogeneration tech-nology. Generally used inindustry and utility appli-cations. Best suited forwhere electric/thermalratio is low,

Potential for use in residen-tial, commercial, andindustrial sectors if fuelis available and costeffective.

Best suited to larger scaleutility and industrial ap-plications. Potential forcoal use is excellent,

Most attractive wherepower requirements arehigh and process heat re-quirements are lower,Used in large industrialapplications such asSteel, chemical, andpetroleum refiningindustries.

Reliable and available, canbe used in hospitals,apartment complexes,shopping centers, hotels,Industrial centers if fuel isavailable and cost effec-tive, and if can meet envi-ronmental requirements.

B. Open-cycle gasturbine topping

320-700 0.29-0.34 2.5-3.0 0.75-2 20 natural gas15 distillate

Mature technology —com-mercially available in largequantities.

C. Closed-cycle gas 450-900 5 percent of Included in 2-5turbine topping acquisition fixed cost

cost per year

20 Not commercial in theUnited States; is well de-veloped in several Euro-pean countries.

Commercially available;advanced systems by1965.

430-600 2-3D. Combined gasturbine/steamturbine topping

5.0-5.5 3.0-5.1 15-25

E, Diesel topping 350-600 6.0-8.0 5.0-10.0 0.75-2.5 15-25 Mature technology —com-mercially available in largequantities.


Steam 550-1,100 1,6 3.7-6.9 1-3 20 Commercially available Industrial and utility usealmost exclusively. Al-though efficiency is low,since it runs on wasteheat no additional fuelis consumed. Can reduceoverall fuel use.

Same benefits/limitationsas steam Rankine bottom-ing except that it can uselower-grade waste heat.Organic Rankine bottom-ing is one of the fewengines that can usewaste heat in the 2000600”F range.

Modular nature, low emis-sions, excellent part-loadcharacteristics allow forutility load following aswell as applications incommercial and industrialsectors.

High efficiency and fuelflexibility contribute to alarge range of applica-tions Could be used inresidential, commercial,and industrial applica-tions. Industrial usedepends on development

4.9-7.5 1-2 20 Some units are commerciallyavailable but technologyis still in its infancy.

Organic 600-1,500 2.8

G. Fuel cell topping 520-840C 0.26-33 1.0-3.0 1-2 10-15 Still in development andexperimental stage. phos-phoric acid expected by1965, molten carbonate by1990.

H. Stirling engine 420-960C

topping5.0 8.0 2-5 20 Reasonably mature technol-

ogy up to 100-kW capacitybut not readily available.Larger sizes beingdeveloped.

of large Stirling engines.

“NA” means not applicable.al 960 dollars.bDepends on system size and heat source.CCost estimates assume successful development and commercial-scale production, and are not guaranteed.


122 • Industrial and Commercial Cogeneration

COGENERATION TECHNOLOGIESMost cogeneration systems can be described

either as “topping” systems or “bottoming” sys-tems, depending on whether the electrical orthermal energy is produced first. * In a toppingsystem—the most common cogeneration mode—electricity is produced first. The thermal energythat is exhausted is captured and used for suchpurposes as industrial processes, space heatingand cooling, water heating, or even producingmore electricity (18). Topping systems would beused in residential/commercial and most indus-trial cogeneration applications.

In a bottoming system, high-temperature ther-mal energy is produced first for applications suchas steel reheat furnaces, glass kilns, or aluminum-remelt furnaces. Heat is extracted from the hotexhaust waste stream and transferred to a work-ing fluid, generally through a waste heat recoveryboiler. The fluid is vaporized and used to drivea turbine (Rankine cycle) to produce electricalenergy (18). Bottoming cycles are used mostly inindustries where high-temperature waste heat isavailable, and thus are limited to a few industrialprocesses. Further, they tend to have a highercapital cost than topping systems.

The cogeneration systems described below are:1) steam turbine topping, 2) open-cycle gas tur-bine topping, 3) closed-cycle gas turbine topping,4) combined-cycle (gas/steam turbine) toppingsystems, 5) diesel topping, 6) Rankine cycle(steam and organic) bottoming, 7) fuel cell top-ping, and 8) Stirling engine topping. A fuel cell,being a chemical device, is the only technologythat is not a heat engine although it is considereda topping cycle cogeneration system.

These technologies include small systems (75kW to 10 megawatts (MW)) that might be usedto supply electricity and heat for a single buildingor a building complex such as a shopping center;intermediate size cogenerators of several to tensof megawatts for industrial applications; and large

*Operating and efficiency standards for topping and bottomingcycle cogenerators promulgated by the Federal Energy RegulatoryCommission under the Public Utility Regulatory Policies Act arediscussed in ch. 3.

centralized systems that could supply electricityto the utility grid and distribute steam to nearbyindustries or to district heating systems. Poten-tial cogeneration applications in industry, com-mercial buildings, and rural areas are discussedin detail in chapter 5.

The steam turbine, open-cycle gas turbine,combined-cycle, diesel, and steam Rankine bot-toming cogenerators represent commerciallyavailable technologies although advanced modelswith improved efficiency, lower cost, and greaterfuel flexibility are under development. Theclosed-cycle gas turbine is available in othercountries and could be introduced in the UnitedStates at any time. Organic Rankine bottomingcycles, fuel cells, and Stirling engines are notcommercially available in the United States, butare sufficiently well developed to be considered“near term” cogeneration technologies (availablewithin 5 to 15 years). As with all predictions ofcommercial readiness for developing technolo-gies, however, care must be exercised and ac-tual progress observed closely–as noted from thelong and difficult history of Stirling engines.

The general operating and performance char-acteristics and costs of these cogeneration tech-nologies are summarized below and in table 23.Detailed technology descriptions may be foundin volume Il.

Steam Turbines

Historically, steam turbines have been the pri-mary cogeneration technology, providing me-chanical and electric power and steam for a vari-ety of industrial processes. A schematic of a steamturbine in a cogeneration application is shownin figure 17. The system consists of a boiler anda back pressure turbine. Mechanical energy isproduced as the high-pressure steam from theboiler drives the turbine. The mechanical energyis then converted to electricity by turning a gen-erator rotor attached to the turbine. The steam,which leaves the turbine at a reduced pressureand temperature (300° to 700° F), can be usedin many industrial applications (see ch. 5).

Ch. 4—Characterization of the Technologies for Cogeneration ● 123

Figure 17.—Steam Turbine Topping System in a Cogeneration Configuration

SOURCE: Thermo Electron Corp., Analysis of Cogerrerat/on Systems App//cab/e to the State of New Jereey (VValtham, Mass.:Thermo Electron Corp., TE5486-103-8O, December 1979).

The technical and operating characteristics ofsteam turbines present both advantages and dis-advantages relative to other types of cogenera-tors. Steam turbine engines are available in a widerange of sizes, from 500 kW to well over 550MW, although 100 MW is probably a reasonableceiling for most industrial applications. Currently,steam turbine boilers can accommodate a widervariety of fuels than other available cogenerationsystems (including oil, natural or synthesis gas,coal, wood, solid waste, and industrial byprod-ucts), although individual boilers can only be de-signed to accommodate two fuel sources at onetime (i.e., dual-fueled boilers can be built to useoil or gas, coal or oil, gas or coal). Steam turbinecogenerators also have extremely high unit relia-bility, availability, and service lifetime. With re-spect to reliability, steam turbines have a maxi-mum forced outage rate of around 5 percent.Their unit availability also is quite high (90 to 95percent) because scheduled maintenance re-quirements are relatively low. The expected serv-

ice lifetime of steam turbine cogenerators is from25 to 35 years.

A final technical advantage of steam turbine co-generators is their high overall fuel efficiency,which ranges from 65 to 85 percent, and general-ly is not affected by turbine inlet temperaturesor by part-load operation (when less than themaximum possible amount of electricity is beingproduced). However, steam turbines’ efficiencyof electricity generation increases with increas-ing inlet temperature and pressure ratio, and withsize up to about 30 MW.

On the other hand, steam turbine cogeneratorshave relatively long installation Ieadtimes–12 to18 months for smaller systems and up to 3 yearsfor larger units—from the time equipment is or-dered until operation begins. This is due primarilyto the time required to certify and install high--pressure boilers. For coal burning systems, theinstallation of fuel handling equipment can addsignificantly to the Ieadtime.

124 • Industrial and Commercial Cogeneration

Steam turbines also have relatively low ratiosof electric-to-thermal power production (E/S ratio)because they have a relatively low upper temper-ature limit. It is this temperature which, in com-bination with the desired steam temperature, de-termines the amount of electricity that can begenerated. Of the 85 percent useful energy ob-tainable in steam turbine cogeneration systems,typically 14 percent would be electric power and71 percent process heat. However, the E/S ratiowill vary according to the amount of high-pres-sure steam that is directed from the boiler forprocess heat. Thus, an increase in process steamtemperature corresponds to a decline in electricpower production and an increase in heat pro-duction. Overall fuel utilization (power plus heat)remains relatively constant at a variety of processtemperatures. All that changes is the proportionof total fuel use devoted to electric generationand process heat. Research and development(R&D) efforts are underway on advanced steamturbine models that would operate at higher tem-peratures and pressures and thus would be moreefficient generators of electricity.

The costs of steam turbine cogenerators varydepending on the size of the system, the kind offuel it uses, and its combustion source (e.g., boil-er, fluidized bed combustor, gasifier). Figure 18presents total installed costs for steam turbinesystems. Coal-fired steam turbines with flue gasdesulfurization (FGD) (for environmental controlpurposes) range in cost from $800 to $1 ,600/kWinstalled capacity. These systems constitute themost expensive steam turbine option, with costsgenerally $200/kW greater than turbines with flu-idized bed boilers, which would not need FGDin order to meet air quality standards. Oil-firedboilers for steam turbines constitute the least ex-pensive option, with installed cost estimates rang-ing from $550 to $800/kW—about $200 to $600/kW below the expected costs for atmosphericfluidized bed (AFB) boiler turbines. * Economiesof scale are evident for steam turbine cogenera-tors larger than about 10 MW.

*lt should be noted that estimates for steam turbine system costsvary greatly according to the data source. The degree of accuracyof the different estimates is difficult to verify without actual construc-tion of the various systems.

Figure 18.—Estimated Steam Turbine CogeneratorSystem Instaiied Costs With Different Heat Sources

‘O 10 20 30 40 50 60 70 80 90 100

Electric power output (MW)

SOURCE: Off Ice of Technology Assessment.

The cost for advanced steam turbine primemovers also differs according to the size of theunit. For smaller units (less than 5 MW), advancedsteam turbine installed costs may be $150 to$200/kW greater than the cost of current steamturbines. For 1O-MW units, the incremental costof advanced steam turbines is approximately $5oto $100/kW greater, while for 100-MW units, theprices are approximately the same as currentlyavailable systems (55).

Estimates for variable operation and mainte-nance (O&M) costs for steam turbine toppingcycles (excluding fuel cost) vary from 3.0 to 8.8milis/kWh depending on the source of the esti-mate. For a residual oil-fired steam turbine, ingeneral, a 4.0 mills/kWh O&M cost appears tobe a reasonable estimate. Estimates of O&M costsfor large steam turbines are 6.0 mills/kWh withFGD, 4.2 mills/kWh without FGD, 5.2 mills/kWhwith AFBs, and 8.8 mills/kW/h with pressurized

Ch. 4—Characterization of the Technologies for Cogeneration “ 125

fluidized beds. Fixed annual O&M costs rangefrom $1.6 to $1 1.5/kWh of installed capacity.

Open= Cycle Combustion Turbines

Most combustion turbines are open-cycle sys-tems in which air is drawn in from the atmos-phere and exhaust gases are released to the at-mosphere (i. e., the air or other working fluid isnot recirculated). Figure 19 provides system sche-

matics for both simple and regenerative open-cycle gas turbines. Figure 20 presents the config-u ration a simple open-cycle combustion turbinewith a heat recovery unit would take in a cogen-eration application. For both simple and regener-ative turbine types, air is compressed, thenheated in the combustion chamber to the re-quired turbine inlet temperature, and expandedthrough the turbine. The primary difference be-tween the simple and regenerative open-cycle

Figure 19.— Combustion Turbine

Air Exhaust

SOURCE: Arthur D. Little, Inc., Distributed Energy Systems: A Review of Re/ated Technologies (Washington, D. C.: USDepartment of Energy, DOEIPE 03871-01, November 1979).


1,100

Figure 20.-Schematic of a Simple Open-Cycie Combustion Turbine in a Cogeneration Application

Process100,000 lb steam/hour

700oF, 600 psi

T = 770oFP

Air,000 lb/hour

SOURCE: United Technologies Corp., Cogeneration Technology Alternative Study (CTAS) — Volumes I-VI (Cleveland, Ohio: National Aeronautics and Space Admin.istration, Lewis Research Center, and Washington, D. C.: U.S. Department of Energy, DOE/NASA/00W80/1 -6, January 1980).

turbines is that in the latter, the low-pressure hotexhaust gases are used to preheat the high-pres-sure compressor discharge air in a regenerator.The waste heat boiler system recovers heat fromthe hot gas produced by the turbine and gener-ates high- and low-pressure thermal energy to beutilized in industrial processes or for space condi-tioning.

Simple open-cycle combustion turbine systemswith waste heat boilers currently are available insize ranges from 100 kw to 100 MW. Regenera-tive turbines are available in sizes from about 16MW to 70 MW. Most combustion turbines burnnatural gas or diesel oil, and can be convertedfrom one to the other in about 1 day. Becauseturbine blades in open-cycle systems are exposedto the products of combustion, these productsmust be free of impurities (e.g., sodium, potassi-um, calcium, vanadium, iron, sulfur, and particu-Iates) that can cause corrosion, and the residualsolids must be small enough to avoid erosion ofthe turbine blades. As a result, currently availableopen-cycle combustion turbines cannot use solidfuels (coal, biomass) directly (i.e., without firstliquefying or gasifying them), and cannot burnresidual oil or liquid or gaseous fuels from coalor biomass without an auxiliary fuel cleaningsystem (see discussion of fuel flexibility in the nextsection).

Open-cycle combustion turbine cogeneratorshave a shorter installation Ieadtime than steamturbines—around 9 to 14 months for gas turbinesup to 7 MW, and as long as 2 years for largerunits. The reliability of combustion turbines andtheir average annual availability should be com-parable to that of steam turbines, although unitsthat burn liquid fuels or that are operated onlyintermittently will require about three times moremaintenance—and thus will have a lower percentavailability—than those that use natural gas. Onthe other hand, the expected useful service lifeof open-cycle combustion turbines tends to belower than that of steam turbines–typically 15to 20 years—and poor maintenance, the use ofliquid fuels, or intermittent operation can reducethe service life substantially.

Open-cycle combustion turbine cogeneratorstend to have slightly lower overall fuel efficiencythan steam turbines, but the most efficient com-bustion turbines can have a higher overall effi-ciency than the least efficient steam turbines. onthe other hand, open-cycle combustion turbineshave much higher E/S ratios than steam turbines(typically 140 to 225 kWh/MMBtu for combus-tion turbines, as compared to 30 to 75 kWh/.MMBtu for steam turbines), and a higher elec-tric generating efficiency at both full- and part-Ioad operation (see table 23). Unlike steam tur-


Figure 21.—Combustion Turbine Cogenerator CostEstimates for the Prime Mover and

Total Installed System

800

700

500

300

200

100

00 10 20 30 40 50 60 70 80 90 100



low and tend to be about $0.29/kW for simplecycles and $0.34/kW for regenerative cycles.

Closed-Cycle Combustion Turbines

In closed-cycle combustion turbine systems,the working fluid (usually either helium or air)circulates through a closed circuit, and is heatedto the required inlet temperature by a heat ex-changer. This arrangement ensures that both theworking fluid and the turbine machinery are iso-lated from both the combustion chamber (heatsource) and the products of combustion, and thuserosion and corrosion problems in the turbineare avoided. This external combustion design


thus permits greater fuel flexibility than is possi-ble in currently available open-cycle turbines.Closed-cycle systems can burn coal, industrial ormunicipal wastes, biomass, or liquid or gaseousfuels derived from them. Nuclear or solar energymay be used for these systems in the future. Fig-ure 22 presents schematics of closed-cycle com-bustion turbine systems with and without regen-erators. In the regenerative closed cycle, heatfrom the working fluid that is leaving the turbineis used to preheat the working fluid that is leav-ing the compressor. Closed-cycle combustion tur-bine cogenerators have not been commerciallyavailable in the United States in the past, but havebeen successful in Europe and Japan and couldbe introduced here at any time.

The actual configuration of closed-cycle com-bustion turbine systems will vary according to theheat source. Likely heat sources for these systemsinclude coal-fired AFB combustors and liquid-fueled high-temperature furnaces. The installa-tion Ieadtime for a 25-MW system with an AFBis estimated to be 4.5 to 5 years, with an expectedservice life of about 20 years.

In closed-cycle systems, any gas can serve asthe working fluid. Air has the advantage of reduc-ing sealing requirements and mechanical compli-cations. Heavy molecular weight gases (such asargon) reduce the size of the turbomachinery but

increase that of the heat transfer components,while light molecular weight gases (such as heli-um) require more extensive turbomachinery andminimize the size of heat transfer equipment. Thisflexibility’ contrasts sharply with open-cycle com-bustion turbine systems, which are limited to thehot combustion gases as the working fluid.

Closed-cycle combustion turbines are thusphysically smaller than open cycles, but requiremore piping and heat exchangers. In addition,the small physical size of the turbomachinery Iim-its the power of closed-cycle turbines. Conse-quently, systems with capacities below 500 kWare not considered economically attractive. Elec-tric capacity in currently operating closed-cyclegas turbine systems (in Europe and japan) rangesfrom 2 to 50 MW.

The average annual reliability and availabilityof closed-cycle combustion turbines is expectedto be at least as good as that for open cycles oncesufficient operating experience has been accumu-lated with the former. However, because theclosed-cycle configuration reduces wear and tearon the turbine blades, closed-cycle systems mayrequire less maintenance (and thus have a higheravailability) than open cycles.

The overall fuel efficiency of closed-cycle com-bustion turbine cogenerators also is expected tobe comparable to that of open cycles, as is the

Figure 22.—Closed-Cycle Gas Turbines With and Without Regeneration

SOURCE: United Technologies Corp., Cogeneration Technology Alternative Study (CTAS)— Volumes /-V/ (Cleveland, Ohio: National Aeronautics and Space Administra-tion, Lewis Research Center, and Washington, D. C.: U.S. Department of Energy, DOE/NASA/OOW-8011 -6, January 1960).

Ch. 4—Characterization of the Technologies for Cogeneration “ 129

E/S ratio (see table 23). Similarly, use of a regen-erator with a closed cycle will increase electric-ity output but reduce the temperature of the re-covered heat. Unlike open-cycle systems, how-ever, part-load operation of a closed-cycle gas tur-bine cogenerator does not reduce electric gener-ating efficiency, and may actually increase itwhen a regenerator is used. In this case a closed-cycle system is much like a steam turbine in thatthe working fluid and the combustion gases areseparate. This allows more control, which in turnmakes possible more constant part-load opera-tion. The effect of part-load operation on overallfuel efficiency will depend on the part-load effi-ciency of the heat source (e.g., fluidized bed, hotgas furnace). Finally, overall efficiency will tendto increase slightly with system size up to about25 MVV.

Detailed installed cost information for closed-cycle combustion turbine cogenerators is limiteddue to the lack of experience with these systemsin the United States. Figure 23 presents estimatesfor various size systems showing a range for totalinstalled costs (exclusive of heat source) from$450 to $900/kW. Economies of scale are signifi-cant for larger systems (approximately 25 MW

Figure 23.—Closed-Cycle Gas Turbine CogeneratorInstalled Cost (exclusive of heat source)

O 10 20 30 40 50 60 70 80 90 100

Electric power outlet (MW)

SOURCE: Off Ice of Technology Assessment

and above), primarily as a result of the low incre-mental cost of fuel handling equipment with in-creasing capacity.

The lack of U.S. operating experience withclosed-cycle combustion turbine cogeneratorsprecludes any definitive estimate of O&M costs.A representative estimate for fixed plus variableO&M costs in the literature surveyed is 5 percentof installed cost per year of operation.

Combined CyclesThe term “combined cycle” is applied to sys-

tems with two interconnected cycles operatingat different temperatures. The higher temperature(topping) cycle rejects heat that is recovered andused in the lower temperature (bottoming) cy-

cle to produce additional power and improveoverall conversion efficiency. Currently availablecombined-cycle cogenerators use a combustionturbine topping cycle in combination with asteam-bottoming cycle.

A schematic of such a combined-cycle plantis shown in figure 24. The major components ofthe system are the combustion turbine generator,the heat recovery boiler, and the steam turbine.Note that this system is like the combustion tur-bine cogeneration systems discussed previouslyexcept that steam from the heat recovery boileris used first to generate electricity and then ex-hausted for process heat and ultimately wasteheat. In most combined-cycle systems, extra fuelis burned in the heat recovery boiler to supple-ment the heat in the combustion turbine exhaust,The high percentage of oxygen (17 percent) inthe combustion turbine’s exhaust guarantees effi-cient supplemental combustion under the heatrecovery boiler. Supplemental firing generally im-proves thermal efficiency at part-load operation,but makes combined-cycle plant operation con-trol more complex and thus increases mainte-nance costs.

Combined-cycle cogenerators typically areavailable in sizes ranging from 22 to about 400MW. However, smaller units have been installed,and at least one company currently is develop-ing small, prepackaged combined-cycle units inthe 4-to 11 -MW size range (50). Installation timefrom the date the equipment is ordered ranges


Figure 24.—Schematic of a Combined-Cycle Cogenerator

SOURCE: United Technologies Corp., Cogeneratlon Technology Alternat/ve Study (CTAS)– Volume I-VI (Cleveland, Ohio: Na-tional Aeronautics and Space Administration, Lewis Research Center, and Washington, D. C.: US. Department ofEnergy, DOE/NASA/0030-’60H -6, January 1980).

from 2 to 3 years. It is generally possible to havea two-stage installation in which the combustionturbine system can be operable within 12 to 18months. The steam turbine can then be installedwhile the combustion turbines are in operation.

Combined-cycle systems require less floorspace than separate combustion or steam tur-bines producing comparable amounts of electricpower. Advanced combined-cycle systems(which will consist of advanced combustion tur-bines and current technology steam turbines) willbe even smaller. Reduced space requirementsshould increase the potential cogeneration appli-cations for combined-cycle systems.

Fuels employed by available combined-cyclecogenerators are the same as those used by com-mercial combustion turbines—natural gas, lightdistillate oil, and other fuels that are free fromcontaminants. Heavy fuels, such as residual oil,heavy distillates, and coal-derived fuels that arecontaminated with trace metals can be used butmust be cleaned first. Advanced combined-cyclesystems will be able to incorporate fluidized bedcombustors that can burn coal (or almost anyother fuel). Systems utilizing indirect firing andheat exchangers (i.e., closed cycles) also will beable to run on a wider variety of fuels, because

the combustion turbine blades will be isolatedfrom the corrosive influence of fuel combustion.

The maintenance requirements for a com-bined-cycle system are similar to those for theseparate turbines, and average annual availabilityis lower than for either technology alone (77 to85 percent). Reliability is around 80 to 85 per-cent. Economic service life is between 15 and 25years. However, as with open-cycle combustionturbines, poor maintenance, lower quality fuels,and intermittent operation will decrease the avail-ability, reliability, and service life.

The electric generating efficiency of combined-cycle cogenerators is greater than for simple com-bustion turbine systems because of the additionalelectricity generated by the steam turbine. Cur-rent combined-cycle systems achieve electricgenerating efficiencies of between 34 and 40 per-cent, with 37 percent being typical. This in-creased efficiency, however, is achieved at theexpense of total fuel use (additional fuel is usedfor supplemental heating of the heat recoveryboiler). While available combustion turbinesequipped with waste heat boilers typically havea fuel use efficiency of approximately 80 percent,overall fuel efficiency for combined-cycle systemsusually is below 60 percent. The electric conver-

.


sion efficiency of combined cycles increases withcapacity up to around 80 MW and remains con-stant above that size.

As with open-cycle combustion turbines, part-Ioad operation reduces the efficiency of com-bined cycles. As the gas turbine’s generating effi-ciency drops, more waste heat is supplied to thesteam turbine and its percentage of electric loadincreases. However, the overall efficiency de-clines because of the increasing amount of wasteheat from part-load operation that cannot be re-covered.

Typical E/S ratios for combined cycles are 175to 320 kWh/MMBtu—significantly higher thanthose for steam turbine topping cycles, and com-parable to or slightly higher than open-cycle com-bustion turbines. However, as mentioned above,as E/S ratio in a combined-cycle system increasesthe overall fuel efficiency decreases.

Figure 25 presents estimates of total system in-stalled costs for combined cycles. These costsrange from approximately $800/kW for a 4-MWunit down to approximately $430/kW for 100-MW units, Combustion turbines represent a larg-er percentage of the prime mover installed coststhan do the steam turbines in these systems.

Figure 25.—Total Installed Costs for Combined-Cycle Cogenerator Systems

800

700

600

500

400.

n“ O 10 20 30 40 50 60 70 80 90 100

Electric power output (MW)SOURCE: Office of Technology Assessment.

Maintenance costs for the combined-cycle sys-tem are directly related to the type of fuel used.The lowest maintenance costs are associated withnatural gas use, while using residual oil in thecombustion turbine will result in the highestmaintenance costs, primarily because of the ne-cessity to clean the fuel. Variable O&M cost esti-mates for combined-cycle systems range from 3.0to 5.1 mills/kWh while annual fixed O&M costsare from $5.0 to $5.5/kW installed capacity.

Diesels

The diesel engine is a reciprocating internalcombustion engine and is a fully developed andmature technology. Cogeneration systems usingdiesel engines are topping systems and are classi-fied according to whether the diesel engine oper-ates at high, medium, or low speed. Table 24summarizes the engine speeds for each type ofdiesel, its capacity range, and its usual applica-tions. All three types have been used in electricpower generation —medium- and low-speed die-sels by electric utilities for intermediate and peak-Ioad use, and high-speed diesels in the “totalenergy systems” of the past.

A typical diesel engine topping cogenerator isshown in figure 26. The major system compo-nents include an engine, generator, heat recoveryunit, fuel handling equipment, and environmen-tal controls. The engine is cooled with water andthe heated water used for process steam, heat,or hot water applications. Exhaust gases can beused in a similar manner.

Diesels usually burn natural gas, distillate oil,or treated residual oil, and often have dual fuel

Table 24.-Diesel Engine Characteristics

CapacityType RPM (MW) UsesHigh speed . . . . 1,200-3,600 0.075-1.5 Smaller vehiclesMedium speed. . 500-1,200 0.5-10 Marine, railLow speed . . . . . 120-160 2-30 Marine propul-

sion and indus-trial use

SOURCES: Office of Technology Assessment from Peter G. Bos and James H

Williams, ‘T)ogeneration’s Future in the Chemical Process Industries(CPI),” Chemica/ Engineering, Feb. 26, 1979, pp. 104-110; “ElectricPower Generation,” McGraw-H/l/ Yearbook of Science andTechno/ogy(New York: McGraw-Hill Book Co., 1980); Joel Fagenbaum,“Cogeneration: An Energy Saver,” IEEE Spectrum, August 1980, pp30-34; and Alan J. Streb, “Cogeneration-What’s Ahead?” EnergyEng/neerlng, April/May 1980, pp. 11.23.

132 “ Industrial and Commercial Cogeneration

Figure 26.—Diesel Engine Cogenerator

Heat recovery boiler

SOURCE: Resource Planning Associates, Cogeneration: Technical Concepts, Trends, Prospects (Washington, D. C.: U.S. Department of Energy, DOE-FFU-1703, September1978).

capability. Two-stroke low-speed diesels also canburn untreated low grade residual oil (58). Re-search is underway on the use of coal-based fuelsin large (low-speed) diesels, including processedsolid or liquid coal-derived fuels, or direct coalfiring with either a coal/oil or coal/water slurrymedium or a dry powdered coal. Slurry-fired die-sels may become operational in 5 to 6 years andcommercially available in 8 to 10 years. However,additional equipment may be required to con-trol the increased particulate and sulfur dioxideemissions resulting from burning coal or coal-derived fuels. Whether coal burning diesels willbe economically competitive is yet unknown.

R&D on diesels also is directed toward increas-ing the temperature of the cooling water so thatsteam can be generated, and toward higher su-percharge capability and higher charge air cool-ing. Such advances could result in a 50-percentincrease in power output per cylinder (23). Ad-vanced diesels will be ready for wide-scale cogen-eration application between 1985 or 1990. “Adia-batic” (or very low heat loss) diesels, which useceramic parts, also are under development. Theprincipal advantage of the adiabatic diesel wouldbe that all the waste heat would be in the exhauststream and would be available at high tempera-ture (as with combustion turbines). This technol-ogy could significantly improve the versatility ofthe diesel as well as lead to greater overall fuel

use efficiency (61 ), but is not expected to be com-mercially available until after 1990.

Installation Ieadtimes for presently availablediesel cogenerators range from 9 months forsmaller high-speed systems to 2.5 years for largerlow-speed units. Maintenance is performed ontypical low- and medium-speed diesels every1,500 hours, and more frequently on high-speeddiesels. Average annual availability ranges from80 to 90 percent. Expected service lifetimes varyfrom 15 to 25 years depending on unit size, fuelburned, and quality of maintenance.

E/S ratios for diesels are high–from 350 to 700kWh/MMBtu. Low-speed diesels typically are de-signed for peak efficiency at 75 percent of fullload. Part-load performance for current and ad-vanced technology high-speed diesels is excel-lent. Medium-speed diesels, whose rated capac-ities overlap high-speed diesels at the small scaleand low-speed diesels at the large scale (see table24) follow the same trends.

Total installed costs for current and advanceddiesel prime movers are given in figure 27. Costsrange from $350 to $800/kW for current units,with large advanced systems being slightly higherand smaller ones significantly higher.

Estimates for O&M costs for current and ad-vanced diesels vary significantly depending on


Figure 27.— Diesel Cogenerator Total Installed Costsfor Current and ‘Advanced Prime Movers

800

700

600

400

\ \ A d v a n c e d.

0 3 6 9 12 15 18 21 24 27 30

Electric power outlet (MW)


the fuel, the unit’s size, and the level of emissioncontrol. Fixed O&M costs vary from $6.0 to $8.0/kW annually. Estimates for variable O&M costsrange from 1.5 miIls/kWh for large low-speedunits to 16 mills/kWh for small high-speed units,

with 5.0 to 10.0 mills/kWh being a commonrange.

Rankine Cycle Bottoming

All bottoming cogeneration systems are basedon the conventional Rankine cycle (which is thesame cycle used in steam turbine topping sys-tems), and are classified according to whetherthey use steam or organic working fluids. Thesteam cycle (see fig. 28) uses steam produced ina heat recovery boiler to drive a steam turbinethat generates electricity and high- and low-tem-perature waste heat. This, of course, is just thelow-temperature end of the combined-cycle sys-tems discussed before. The high-temperature heatis condensed and either used in process applica-tions or fed back into the boiler through a closedloop. Low-temperature waste heat is lost to thesurrounding environment. An organic Rankinecycle (see fig. 29) converts heat energy intomechanical energy by alternately evaporating anorganic working fluid (such as toluene) at highpressure and using this vapor to produce shaftpower by expanding it through a turbine. The va-por is then recondensed for either process useor reinfection into the heat recovery boiler.Organic working fluids are used when only lowertemperature heat sources (200° to 600° F) areavailable because these fluids vaporize at verylow temperatures.

Figure 28.—Steam Rankine Bottoming Cycle

SOURCE: Thermo Electron Corp., Venture Analysis Case Study—Steam Rankine Recovery Cycle Producing Electric PowerFrom Waste Heat (Waltham, Mass.: Thermo Electron Crop,, TE4231-1 17-78, December 1978).


Figure 29.-Organic Rankine Bottoming Cycle

Exhaust

Vapor generator

Regenerator

SOURCE: Reeource Planning Aesociates, Cogeneration: Technical Concepts Trends, Prospects (Waehlngton, D. C.: U.S. Department of Energy, DOE-FFU-1703, September1978).

Rankine cycle engines have several characteris-tics that make them particularly appealing to dis-persed electricity generating systems. They areone of the few engines that can effectively utilizeheat at temperatures in the 200° to 600° F range.This allows the engines to use a variety of heatsources including solar energy, industrial wasteheat streams, geothermal energy, and hot engineexhausts. Rankine engines also can be designedfor use over a wide range of capacity levels, fromas low as 2 kW for onsite solar applications upto 10 MW for waste heat applications.

The installation time required for organic andsteam bottoming cycles generally depends on thesize of the plant. For steam Rankine engines, in-stallation times will be similar to those for com-parably sized steam turbine topping cycles. Verysmall organic Rankine units (less than 50 kW),particularly those in commercial applications, willrequire minimal installation time (4 to 8 months)(2), while larger units are expected to take 1 to2 years.

Maintenance requirements and reliability forthe steam Rankine bottoming cycle also shouldbe comparable to those of steam turbine toppingsystems (i.e., average annual availability of about90 percent). Organic Rankine bottoming cyclesare a relatively new technology, and informationon maintenance schedules and system reliabilityis not readily available for these systems, but de-velopers of this technology expect availability tobe from 80 to 90 percent. Expected service life-time for both types of bottoming cycles is around20 years.

Figure 30 shows organic Rankine cycle efficien-cy as a function of boiler outlet temperature. Notethat operation for inlet temperatures below 150°F (about 75o C) is possible. Depending on theseparameters, cycle efficiency will range from 5 to30 percent, with 10 to 20 percent being repre-sentative of actual operating conditions. How-ever, because these organic Rankine cycle sys-tems are bottoming systems that operate on thewaste heat these efficiencies are not significant


Figure 30.—Organic Rankine Bottoming Cycle Efficiency—VariationWith Peak Cycle Temperature

0.4

0.3

0.2

0.1

0100 200 300 400 500 600 700 600

Boiler outlet temperature (“F)SOURCE: Resource Planning Associates, Cogeneratlorr: Tecfrn/ca/ Concepts, Trends, Prospects (Wash-

ington, D. C.: U.S. Department of Energy, DOEIFFU-1703, September 1978).

as far as total fuel use is concerned, because theaddition of an organic Rankine bottoming cyclewill increase the power output of the system with-out any increase in fuel consumption.

Figure 31 .—Typical Energy Balances

An analogous situation holds true for steamRankine bottoming cycles. Figure 31 indicatestypical energy balances for both condensing andnoncondensing steam Rankine systems. Although

for Steam Rankine Bottoming Systems

E/S Ratio: 25.1 kWh/10 BtuSOURCE: Thermo Electron Corp., Venture Analysis Case Study—Steam Rankhre Recovery Cycle Produchrg Electrlc Power

From Waste Heat (Waltham, Maas.: Thermo Electron Corp., TE4231-117-78, December 1978).

figure 31 shows an electric generating efficiencyof only 6 percent for the condensing configura-tion and 14. s percent for the noncondensing, itmust be remembered that additional electricityis being generated from heat that normally wouldhave been wasted. Therefore, both configurationswill result in substantial fuel savings. Because thenoncondensing system produces steam as wellas electricity, and hence has a higher overall fuelutilization efficiency, it saves about 150 percentmore fuel than the condensing system. The non-condensing system would be used, therefore,when heat requirements and fuel saving consider-ations override the need for increased electric-ity production.

Figures 32 and 33 present estimated installedcosts for condensing and noncondensing steamRankine bottoming systems and for organic sys-tems. The costs of the steam systems are roughlycomparable to steam topping cycle cogeneratorsbecause most of the components are the samefor both types of systems. Installed costs fororganic Rankine cycles are more uncertain be-

Figure 32.—Estimated installed Costs forCondensing and Noncondensing Steam

Rankine Bottoming Systems

0 1 2 3 4 5 6 7 8 9 10

Electric power output (MW)SOURCE: Office of Technology Assessment.

Figure 33.—Estimated Installed Costs for OraganicRankine Bottoming System -

1,600

1,400

600

0 0.2 0.4 0.6 0.8 1.0 1.2 1.4 1.6 1.8 2.0Electric power output (MW)


cause mass production of the units has not yetbegun. However, available estimates suggest thatthe organic Rankine cycles will have a higher in-stalled cost than steam cycles, primarily due tothe special materials (e.g., stainless steel) neededto prevent corrosion of system components andthe precautions that must be taken against leaksof the organic working fluid.

Estimates of variable O&M costs for condens-ing and noncondensing steam bottoming systemsup to 3 MW are presented in table 25. For largerunits, variable O&M costs are estimated to be be-

Table 25.-Estimates of Steam Bottoming CycleOperation and Maintenance Costs

Condensing NoncondensingMW Mills/kWh MW Mills/kWh0.5 6.86 0.5 6.171.0 4.57 1.0 5.031.5 4.17 1.5 4.172.0 3.87 2.0 3.713.0 3.71 3.0 3.71

SOURCE: Therrno Electron Corp., Venture Analysis Case Study-Stearrr RankineRecovery Cycle Producing E/ectr/c Power From Waate Heat (Waltham,Mass.: Thermo Electron Corp., TE4231-117-78, December 1978).


tween 3 and 5 percent of the installed cost. An-nual fixed O&M costs are approximately $1 .60/kw of installed capacity.

Fuel Cells

A fuel cell is an electrochemical device thatconverts the chemical energy of a fuel into elec-tricity with no intermediate combustion cycle (seefig. 34). Hydrogen and oxygen react to producewater in the presence of an electrolyte and, indoing so, generate an electrochemical potentialthat drives a current through an external circuit.In addition, the reaction produces waste heat.The hydrogen required for the ceil is obtainedfrom fossil fuels, usually methane, CH4. Becausemethane occurs naturally only in natural gas, fuelconversion is necessary if coal or biomass are theultimate sources of the hydrogen. Fuel cells maybe attractive for industrial and commercial cogen-eration or for utility peaking applications becauseof their modular construction, good electric loadfollowing capabilities without a loss in efficiency,automatic startup and shutdown, low pollutantemissions, and quiet operation. An individual fuelcell has an electric potential of slightly less than1 volt (determined by the electrochemical poten-tial of the hydrogen and oxygen reaction), butsingle cells can be assembled in series to generate

practically any desired voltage, and these assem-blies, in turn, can be connected in parallel to pro-vide a variety of power levels (e.g., 40 kW to 25MW). A fuel cell powerplant (see fig. 35) includesthe cell stack, an inverter (to convert direct cur-rent to alternating current), and a fuel processor(to remove impurities from the hydrocarbon fueland convert it to pure hydrogen). The recoveredthermal energy in a fuel cell cogenerator can beeither all hot water, or part steam and part hotwater depending on the pressure.

The only fuel cell technology currently operat-ing commercially is based on a phosphoric acidelectrolyte operating at 350° F. In general, acidsystems are favored because they do not reactwith carbon dioxide and may thus use air as thesource of oxygen. Phosphoric acid cells are pre-ferred because water removal is relatively easyto control in these systems. However, phosphoricacid fuel cells depend on platinum catalysts. Thepresent demonstration fuel cell powerplants re-quire a platinum catalyst loading of approximately6.2 grams per kilowatt of electric power output(27), which, at today’s prices, adds $65 to $75/kWto the cost of the fuel cell. A production level of750 to 1,000 MW of phosphoric acid fuel cellsper year (the level one developer suggests willbe achieved in the next 10 to 15 years) would


Figure 35.—Schematic of a Fuel Cell Powerplant

SOURCE: United Technologies Corp., Cogeneratlon Technology Alternatlve Study (CTAS) – Volumes I-VI (Cleveland, Ohio:National Aeronautics and Space Admlnlstratlon, Lewis Research Center, and Washlngton, D. C.: U.S. Departmentof Energy, DOE/NASA/OO~OH-6, January 1980).

correspond to approximately 4.7 to 9.3 tonnesof platinum annually, or around 35 to 70 percentof domestic platinum production (including recy-cling) in 1979, and 3.5 to 7.5 percent of total U.S.consumption in 1979 (9). Because of the smallamount of domestic platinum reserves, and lim-ited U.S. refinery and recycling capacity, it is like-ly that a significant increase in platinum demandfor fuel cells would be supplied from foreignsources—primarily South Africa and the U.S.S.R.—and could lead to increases in the price of plat-inum. R&D efforts are underway to reduce theplatinum loading needed for fuel cells (developersestimate future requirements to be about 1.9grams per kilowatt), to synthesize catalysts thatdo not depend on platinum, and to develop ad-vanced cells based on molten salt electrolytes (9).

A second limitation of phosphoric acid fuel cellsis that hydrogen is the only fuel that can be oxi-dized at acceptable power levels in the cell, anda clean fuel (e.g., methane or naphtha—a lightpetroleum distillate) is required to generate thehydrogen. Advanced phosphoric acid cells maybe able to use desulfurized No. 2 fuel oil as thesource of hydrogen. Second generation moltencarbonate electrolyte fuel cells, using advancedfuel conversion technology, would make lessstringent demands for a clean fuel, and possiblycould be integrated with coal gasifiers.

Developers of fuel cells estimate an installationIeadtime of 1 to 2 years for cogenerators basedon either the phosphoric acid or molten carbon-ate cells (assuming mass production). useful serv-ice lives are projected to be 10 to 15 years. Main-tenance requirements are uncertain due to thelimited experience with demonstration plants, butaverage annual availability is expected to bearound 90 percent.

The overall chemical reaction in a fuel cell de-fines the maximum electric energy that it can pro-duce. Because no thermomechanical work is in-volved, the energy conversion efficiency is notlimited by the Carnot cycle. However, voltagelosses are associated with internal resistance,mass transport limitations, and the kinetics of theelectrode reactions. Electric generating efficiencyranges from 30 to 40 percent, depending on oper-ating temperature and fuel quality (see fig. 36).At half-load operation, electric generating effi-ciency equals or even exceeds the efficiency atfull load. Thus, fuel cells could be installed forload following duty without a loss in efficiencyin order to enable other types of generators tooperate at their most efficient rates. E/S ratios forfuel cells are relatively high–from 240 to 300kWh/MMBtu.

The installed costs for fuel cell powerplants arecurrently too high to compete with other elec-


Figure 36.-Representative Performance of Fuel Cell Powerplants

Low- High- High-temperature temperature temperaturecoal-derived coal-derived coal

distillate distillateSOURCE: United Technologies Corp., Cogeneratlon Technology A/ternat/ve Study (CTAS)– Volumes I-VI (Cleveland,

Ohio: National Aeronautics and Space Administration, Lewis Research Center, and Washington, D. C.: U.S.Department of Energy, DOE/NASA/0030-80H% January 1930).

tric power generating systems (e.g., a 4.8-MWdemonstration plant, being built in New YorkCity, will cost $60 million, or an equivalent of$12,500/kW).” Fuel cell developers project thattotal installed costs should range from $520 to$840/kW of electrical capacity once the technol-ogy is being produced on a large scale (see fig.37). It is likely that between 500 and 1,500 MWof fuel cells will have to be produced before the“learning curve” price reaches a target level of$350/kW for the fuel cell prime mover alone. Asshown in figure 37, the cost of a fuel cell primemover is not affected significantly by the capac-ity rating. However, substantial economies ofscale are observed with the balance-of-plant costsper kilowatt, including fuel handling costs andelectric and control system costs.

Estimates of variable O&M costs for both typesof fuel cells fall within the range of 1.0 to 3.0mills/kWh. Fixed annual O&M expenses mayrange from $0.26 to $3.3/kW installed capacity,

Stirling Engines

Stirling engines are a potentially advantageousalternative to diesel, combustion turbine, andsteam turbine cogenerators due to their poten-tially higher thermal efficiency, greater fuel flex-ibility, good part-load characteristics, low emis-sions, and low noise and vibrations. Figure 38shows a schematic of a Stirling cycle engine. Gas(e.g., hydrogen, helium) entrapped by a pistonalternately is compressed and expanded to turna crankshaft. Because the pressure during the hotexpansion step is significantly greater than dur-ing the cool compression step, there is a net workoutput from the engine.

Historically, Stirling engines have been investi-gated for their potential use in automobiles, sodevelopmental work has been directed towardsmaller engines, which currently are available ina size range of 3 to 100 kw. A 350-kW Stirling

engine is under design, and developers expect


Figure 37.– Future Estimates of Total InstalledCosts for Fuel Cell Powerplant Systems

900 f

750

600

300

150

I

“ o 5 10 15 20Electric power output (MW)


capacities up to 1 to 1.5 MW, with servicetimes of 20 years to be available by 1990.

25

life-Al-

though installation Ieadtimes are hard to predictat present, they could range from 2 to 5 yearsif and when Stirling cycle cogeneration systemsbecome commercial.

Because Stirling engines are still in the develop-ment stage, information about their maintenanceand reliability is not readily available, but devel-opers project maintenance requirements (andthus average annual availability) to be compar-able to diesels and combustion turbines. Due tothe external combustion, closed-cycle configura-tion of Stirling engines, its moving parts are notexposed to the products of combustion, and thewear and tear on the engine should be minimal.However, Stirling engines do require a complexsystem of piston rod seals and surface barriers tocontain the high-pressure hydrogen and preventoil from leaking into the working gas space. Thedurability of the piston seals, which are exposedto a pressure differential of several thousandpounds per square inch, is a recognized reliability

Figure 38.-Schematic of a StirlingCycle Engine

or

SOURCE: Application of Solar Technology to Today’s Energy Needs,Volurnes / and// (Washington, D. C.: U.S. Congress, Office ofTechnology Assessment, 1978).

issue, and the seal systems must be improvedbefore Stirling engines can be used widely.

A major advantage of the Stirling engine is thatits external combustion system enables it to usea wide variety of fuels, including coal, coal-derived gases and liquids, municipal solid wastes,and possibly biomass-derived fuels such as woodchips and biogas. In addition, Stirling engines canchange fuels without adjustment to the engine,interruption of its operation, or loss of either pow-er or efficiency. This flexibility will allow Stirlingengines to be used as components of solar energysystems, as adjuncts to fluidized bed combustorsand nuclear reactor systems, etc.

A second advantage of Stirling engines, relativeto available cogenerators, is their greater efficien-cy. The Stirling cycle is much closer to the Car-not cycle than are the Rankine or combustion tur-bine cycles, and Stirling engines have one of thelowest percentages of waste heat, and thus oneof the highest overall fuel use fractions of any heatengine. Figure 39 shows how waste heat availablefrom Stirling engines compares with waste heatfrom other engine types. The overall efficiencyof Stirling engines is relatively independent ofsystem size; electric generating efficiency and


Figure 39.—Waste Heat Availability From Different Engines

Stirling engine Diesel engine(regenerative)

SOURCE: T, J. Marcinfak, et al,, An Assessment of Stirling Engine Potential in Total and Integrated Energy Systems(Argonne, Ill.: Argonne National Laboratory, ANUEN-76, February 1979).

energy losses remain constant—all that changesis the composition of the waste heat (hot waterand steam percentages) (55). Present full-loadelectric generating efficiency is similar to that ofdiesel cogenerators (35 to 40 percent). However,as development efforts increase the heat inputtemperature of Stirling cycles (e.g., through im-proved metals or ceramic coatings in the heaterheads), efficiencies approaching so percent maybe obtained over a wide output range (a few kilo-watts to several megawatts). Part-load perform-ance of current Stirling engines is equivalent tofull-load efficiency, and thus is superior to thatof available prime movers. E/S ratios also are veryhigh–from 340 to 500 kWh/MMBtu.

It is difficult to give precise cost estimates forStirling engines because they are not yet availablecommercially. Current installed cost estimates forlarge industrial Stirling engines are approximately20 percent higher in cost than comparably sizeddiesel engines (from $420 to $960/kW; see fig.40). As with fuel cells, successful developmentwork and mass production would be required to

Figure 40.-Future Installed Costs for StirlingEngine Cogenerator Powerplants

(extrapolated to 30-MW scale)

“O 3 6 9 12 15 18 21 24 27 30




realize these costs. Thus, Stirling cycles could be Due to the limited operating experience withcompetitive with other cogenerators if their en- Stirling engines, no O&M cost data are available.gine efficiency reaches the target of 40 to 45 per- A preliminary estimate of variable O&M costs iscent. Otherwise, installed costs would have to 8.0 mills/kWh (higher than for most prime mov-be reduced even further before Stirlings could be ers) (2), while annual fixed O&M costs areconsidered competitive. estimated to be $5.O/kW.

USE OF ALTERNATIVE FUELS IN COGENERATIONCogeneration’s ability to reduce the use of pre-

mium fuels (oil and natural gas) depends on itsfuel use flexibility. If cogenerators use nonpremi-um fuels (e.g., coal, synthesis gas, biomass, indus-trial or municipal waste) at the outset, or havethe capability to switch readily to such fuels, theirviability obviously will be enhanced. However,of the available cogeneration technologies de-scribed in this chapter, only steam turbines canburn nonpremium fuels directly. Although R&Defforts are underway to improve the fuel flexibilityof other available cogenerators (e.g., advancedcombustion turbines and diesels), these improve-ments may not become commercial until the late1980’s or early 1990’s. Similarly, advanced primemovers (such as Stirling engines) that can usealternative fuels are not likely to be widely avail-able for 5 to 10 years. As a result, many poten-tial cogenerators are looking to alternative fuelcombustion or conversion systems that can beused in conjunction with current cogenerationtechnologies to increase fuel flexibility. Two typesof such systems—fluidized bed combustors andgasifiers–are discussed below. The use of thesesystems in industrial, commercial, and rural co-generation applications is discussed in chapter 5.

Fluidized Bed Combustion Systems*

In fluidized bed combustion, coarse particlesof fuel (about 1/4 inch in diameter) are burned ina bed of limestone or dolomite at temperaturesof 1,500° to 1,750° F. The fuel and limestone (orother material) are injected into the bed through

*Unless otherwise noted, the material in this section is from ICF,Inc. (26).

pipes that are arranged to distribute the fuel even-ly throughout the bed area. Feeding is continuousto ensure steady combustion conditions. The fuelparticles are kept in suspension and in turbulentmotion by the upward flow of air, which is in-jected from the bed bottom and passed througha grid plate designed to distribute the air uniform-ly across the bed. During combustion, the systemresembles a violently burning liquid and the bedof particles is considered to be “fluidized. ” Thisfluidized state of the burning fuel produces ex-tremely good heat transfer characteristics bothamong the agitated particles and in the heat trans-fer surfaces immersed in the bed. Residual materi-als are drained from the bed continually to allowfor steady operating levels.

There are two major types of fluidized bedcombustors. In atmospheric fluidized beds(AFBs), fuel combustion occurs at atmosphericpressures. In pressurized fluidized bed (PFB)systems, a pressurizing gas turbine elevates pres-sures in the combustion chamber to 10 to 15 at-mospheres. The pressurized system allows a morecompact boiler design and should produce feweremissions than AFBs. However, development ofthe PFB is behind that of the AFB, and its avail-ability will follow AFBs by several years.

AFBs are commercially available in sizes thatproduce from 50,000 to 550,000 lb of steam perhour, which corresponds to 5- to 55-MW electric-ity generating capacity (7). A 200-MW demonstra-tion plant currently is under construction by theTennessee Valley Authority (TVA), and is ex-pected to come on-line by 1987. TVA estimatesthat a 800-to 1,000-MW plant could be built and


in operation by 1991. Because of the lack of con-struction and operating experience with fluidizedbeds beyond a 10-MW capacity, however, poten-tial users currently are reluctant to install largersystems.

Only 10 PFB systems are either planned or inoperation around the world, the largest being a30-MW unit currently operating in Great Britain.No commercial vendor of pressurized systemshas been identified, and, as mentioned previous-ly, the availability of pressurized systems is ex-pected to be several years behind that of atmos-pheric systems (7).

The space requirements for atmospheric andpressurized fluidized beds are drastically different.The pressurized combustion process allows fora more compact boiler design, which significantlyreduces its space requirements. The area requiredfor a PFB system is approximately one-fifth thatof an AFB of equal thermal output capacity (23,55). The smaller area occupied by PFBs will beparticularly important for applications wherespace is limited or very expensive (e.g., in cities).

Fluidized beds can burn coal, wood, lignite,municipal solid waste, or biomass. The primaryfuel used to generate electricity with fluidizedbeds is coal, and all fluidized bed pIants currentlyin operation use coal as their fuel source. Large(800-Mw) fluidized bed plants are now being de-signed to use Illinois No. 6 coal, which has a rel-atively high sulfur content (around 4 percent).Fluidized bed boilers can burn such high sulfurcoal without flue gas desulfurization because alarge percentage of the sulfur (up to 90 percent)is trapped by the limestone particles within thefluidized bed. Flue gas from the fluidized bedsflows through cyclone separators that remove 95percent of the solid matter in the gas streams.Electrostatic precipitators remove the remainingash to the level required by emission standards.

The ability to burn high sulfur coal economical-ly represents an important advantage of fluidizedbed boilers over the conventional coal combus-tion systems. However, fuel handling require-ments for fluidized beds are more complex thanthey are for conventional coal boilers. Both thecoal (or other fuel) and the limestone with whichit burns must be pulverized to a size that can be

fluidized easily. Moreover, present fluidized bedsdesigned for a particular fuel will require substan-tial modification of the fuel handling and injec-tion equipment to convert to another fuel. Ad-vanced fluidized bed boilers may be designed sothat they can accommodate different fuel typesmore easily.

Due to the lack of experience in the operationof fluidized bed boilers, information on theirmaintenance and reliability is limited. Developersexpect the reliability of both fluidized bed typesto be similar to that of a coal-fired boiler. How-ever, as experience with fluidized bed technol-ogy increases, its maintenance requirements maybecome less stringent than those for current tech-nologies.

R&D for fluidized bed boilers is directed to-wards overcoming the basic market barriers totheir use. Current R&D focuses on: 1) installinglarger demonstration plants; 2) determining thereliability, economic, and environmental charac-teristics of fluidized bed technology; and 3) dem-onstrating satisfactory erosion and corrosion be-havior in the bed.

Gasification

Gasifiers convert solid fuels into a fuel gas, com-monly known as synthesis gas, whose fuel com-ponents are principally carbon dioxide and hy-drogen, with smaller quantities of various othersubstances. * The gasification process consists ofheating or partially burning the solid fuel and, insome cases, reacting the gas or solid with steam.The resultant gas is a low- or medium-energy gasthat contains less than about 500 Btu per stand-ard cubic foot (SCF). This gas is not suitable forblending with natural gas (1,000 Btu/SCF), but itcan be transported economically over relativelyshort distances (usually less than 100 miles) inregional pipelines and used for most of the appli-cations for which natural gas is used (e.g., as aboiler fuel, for process heat, for cooking, forspace and hot water heating, or as a combustionturbine fuel).

*The gas from air-blown gasifiers also contains considerableamounts of nitrogen from the air used in the process.


This section analyzes the gasification of threesolid fuels—coal, wood, and municipal solidwaste—to produce a fuel for open-cycle combus-tion turbine and reciprocating internal combus-tion engine cogenerators. These solid fuels areanalyzed because they are relatively abundantand are suitable for gasification. Combustion tur-bines and internal combustion engines are dis-cussed because, of the commercially availablecogeneration technologies, these currently havethe least fuel flexibility, and because they requirea relatively small investment for equipment (animportant consideration for small, dispersed co-generators). However, gasifiers also could beused in conjunction with larger systems such assteam turbines or combined cycles (see discus-sion of industrial cogeneration applications in ch.5). Differences in the gases from each solid fuelare described first, followed by a considerationof the implications of these differences for com-bustion turbine and internal combustion enginecogeneration systems.

Coal

Coal can be partially burned with air to pro-duce a low-energy gas (50 to 150 Btu/SCF) or withoxygen and steam to produce higher energy syn-thesis gas (300 to 400 Btu/SCF). As described be-low, the low-energy fuel gas is considerably lessefficient as a gas turbine fuel than the synthesisgas, and it may be unsuitable as a fuel for inter-nal combustion engines. However, a coal gasifierthat produces synthesis gas requires an oxygengenerator, which increases the system cost. Fur-thermore, both low- and medium-Btu gas fromcoal contains sulfur (hydrogen sulfide), ash, andother impurities that may have to be cleaned fromthe gas before it is used. Commercially availablelow-temperature gasifiers also produce a gas thatcontains some aromatic compounds and otherrelatively large compounds that can result in par-ticulate when the gas is burned. High-tempera-ture gasifiers are being demonstrated, and thetechnological obstacles to their production do notappear to be severe.

Wood

Wood has a relatively high oxygen content andcan be gasified completely to synthesis gas (300

to 400 Btu/SCF) by heating it (pyrolysis) withoutthe need for an oxygen plant. Pyrolysis usuallyrequires a longer residence time in the gasifierthan air-blown gasification, which increases py-rolysis equipment costs, but probably not enoughto offset the savings from eliminating the oxygenplant. More rapid pyrolysis gasification is possi-ble, but can result in the formation of consider-able quantities of relatively large organic com-pounds in the gas that would tend to form partic-ulate when burned. Wood gasification also canbe accomplished with air being used to partiallyburn the wood. If properly controlled and de-signed, air-blown wood gasification can producea fuel gas containing over 200 Btu/SCF.

Because wood contains sodium and potassiumsalts, the resultant fuel gas often contains theseelements as impurities, which can damage or re-duce the life of certain turbine blades. Thus, aswith coal gas, wood gas may have to be cleanedbefore it is used.

Municipal Solid Waste

Municipai solid waste (MSW) contains largeamounts of paper, plastic, metals, and other ma-terials. The heavier materials can be separatedeconomically from the paper in MSW, but mostplastics cannot. Thus, for practical fuel purposes,MSW is a mixture of paper and plastic.

Like wood, MSW can be pyrolyzed to synthesisgas or partially burned to a lower energy gas inan air-blown gasifier. However, because muchof the plastic in MSW contains chlorine (e.g.,polychlorinated biphenyl plastics) the resultantfuel gas will contain hydrogen chloride (in aque-ous form, muriatic or hydrochloric acid), whichis extremely corrosive. Consequently, gasifiersand other equipment in contact with the gas mustbe constructed of expensive, acid resistant steel.Ceramic-coated metals that can be used in MSWgasifiers are under development. As a result ofthe problems introduced by plastics, MSW fuelgas currently is not economical. Furthermore, be-cause paper is the only part of MSW that servesas a good gasifier feedstock, MSW gasificationonly partially solves waste disposal problems.


Combustion Turbines

As discussed in the previous section, reliableand efficient operation of open-cycle combustionturbines requires a high quality fuel that is rela-tively free of particulate and metallic impurities.None of the fuel gases described above fully sat-isfies these criteria. Coal gas contains sulfur andsome heavy metal impurities, and low-tempera-ture gasification of coal can produce a gas thatis high in particulate when burned. Wood gascontains sodium and potassium and, in somecases, may produce particulate when burned.MSW has a much lower sodium and potassiumcontent, but contains corrosive hydrogen chlor-ide. If untreated, all of these fuels can damagecommercially available turbines and reduce theiruseful life. Consequently, extra equipment isneeded to purify these gases. The technical prob-lems of turbine lifetime probably can be solvedif ceramic coatings for turbine blades are success-fully developed. However, environmental con-trols still would be required to prevent the releaseof heavy metals (from coal) and particulate (fromall fuel types).

The energy content of the gas also can poseproblems for combustion turbines. Low-energygas (perhaps less than 150 to 200 Btu/SCF) canlower the efficiency of combustion turbines.Thus, wood and MSW gasifiers must be properlydesigned and operated to ensure that the energycontent of the gas is greater than 200 Btu/SCF,while coal gasifiers will require oxygen plants toachieve a satisfactory energy content. Combustordesign for medium-Btu gas (250 to 500 Btu/SCF)is well developed and use of this gas with gas tur-bines presents no efficiency problems (47,48).

Although fuel quality must be high in order toprevent damage to turbine blades in open-cyclecombustion turbine operation, the use of solidfuels is not necessarily precluded. It is unlikelythat coal will be able to be used in this way butrecent developments indicate that pulverizedwood can be made acceptable. The AerospaceResearch Corp. in Roanoke, Va., is designing andbuilding a 3-MW combined-cycle system usingan open-cycle gas turbine fueled by pulverizedwood (62). The wood is dried to a 25-percentmoisture content, and the combustion gases arecleaned using hot gas cleanup technology devel-

oped in the British pressurized fluidized bed com-bustion program. Using these steps, it appearsthat unacceptable damage to the turbine bladescan be avoided. A 17-MW system (also designedby Aerospace Research Corp.) operates at an in-let temperature of 980° C and an exhaust temper-ature of 510“ C.

While this system shows promise, its accept-ance will depend on demonstrated reliability overan extended period. If it is necessary to removethe blades and repair or replace them more oftenthan currently anticipated, the O&M costs couldnegate the potential economic benefits of usingwood directly. Reliability also will depend ondurable operation of the hot gas cleanup technol-ogy and the burner assembly, which requires ascreen to filter out the larger wood particles.These issues should be resolved by the demon-stration unit under construction in Virginia.

Reciprocating Internal Combustion Engines

Reciprocating internal combustion engines suf-fer from some of the same problems regardingfuel gas quality as combustion turbines, butmetallic contamination and particulate are morea pollution problem than a technical problem inoperating these engines. As mentioned above,hydrogen chloride from MSW plastics can posea corrosion problem if it is not removed from thefuel gas.

For proper operation of an internal combus-tion engine, the fuel gas must be cooled to avoiddetonation of the fuel. This reduces the energycontent of the fuel and thereby increases costs.For wood and MSW, the loss is about 50 percent,but may be lower for medium-energy gas fromcoal and higher for low-energy gas from coal. !fthe waste heat from cooling the gas can be usedonsite, this reduction in energy content does notreduce the engine’s overall fuel efficiency, butwill reduce the electric generating efficiency.

Fuel gas that contains heavy organic com-pounds can produce gums that increase themaintenance requirements for reciprocating in-ternal combustion engines. The formation of suchgums is the most common operating problemwith using fuel gas from relatively primitive woodgasifiers in these engines, and the second most


common problem with MSW gas (after hydrogen burn gas from moderate- to high-temperaturechloride formation). With wood gas, internal coal gasifiers are more likely to have maintenancecombustion engines that operate continuously requirements similar to those of engines that burnmay require overhauling every 6 to 12 weeks premium fuels (discussed in the previous section).(1,000 to 2,000 hours of operation). Engines that

INTERCONNECTION

The analysis in this report assumes that the co-generation technologies just described are inter-connected with the centralized electric grid, sothat the cogenerator may supply power to thegrid and use backup power from the grid. How-ever, interconnection with the grid may createproblems for the utility system’s operations or forthe cogeneration equipment itself. As discussedin chapter 3, many State public utility commis-sions already have jurisdiction over utility connec-tions with customers. In most States, this includesregulation of voltage levels and safety standards.However, in the past the utilities and State com-missions have had to be concerned only with reg-ulating power flow in one direction—from utilityequipment to the customer. Because intercon-nected cogeneration will involve power flows inboth directions, utilities’ and regulatory commis-sions’ tasks in these areas will be more compli-cated.

If cogenerated power is of a different qualityfrom that distributed on the grid, it may affect theutility’s ability to regulate power supply and mayresult in damage to both the utility’s and its cus-tomers’ equipment. Moreover, large numbers ofutility-dispatched dispersed generators couldmake central load dispatching more difficult. Util-ities also are concerned about properly meteringthe power consumption and production charac-teristics of grid-connected cogeneration systems,and about the effects of such systems on the safe-ty of utility workers. Finally, all of the above con-cerns raise questions about liability for employeeaccidents or equipment damage that may resultfrom improper interconnection.

The Public Utility Regulatory Policies Act of1978 (PURPA) authorizes the Federal Energy Reg-ulatory Commission (FERC) to issue orders underthe Federal Power Act requiring the physical con-nection of a qualifying cogenerator (or other small

power producer) with electric utility transmissionfacilities and any action necessary to make thatconnection effective (e.g., increasing the existingtransmission capacity or improving maintenanceand reliability) (see ch. 3). Under the FERC rulesimplementing PURPA, utility rates for purchasesof power from and sales of power to cogeneratorsmust take into account the net increased costsof interconnection (i.e., compared to those coststhe electric utility would have incurred had itgenerated the power itself or purchased it fromthe grid), including the reasonable costs of con-nection, switching, metering, transmission, dis-tribution, and safety provisions, as well as admin-istrative costs incurred by the utility. Each qualify-ing cogenerator must reimburse the utility forthese interconnection costs. The State regulatorycommissions are responsible for ensuring that in-terconnection costs and requirements are reason-able and nondiscriminatory, and for approvingreimbursement plans (e.g., amortizing the costsover several years versus requiring one lump-sumpayment).

This section discusses the nature of potentialinterconnection problems for cogeneration, de-scribes some of the technologies that can be usedto resolve them, and reviews estimates of the costof meeting interconnection requirements. Wheredata specific to cogeneration are not available,analogies are drawn from the relevant literatureon wind or photovoltaic systems.

Power Quality

Utility customers expect electric power to meetcertain tolerances so that appliances, lights, andmotors will function efficiently and not be dam-aged under normal operating conditions. Powersupplied to the grid by an interconnected cogen-erator also is expected to be within certain toler-


ances, so that the overall power quality of theutility system remains satisfactory. Electric utilitiesare concerned about three types of power qual-ity: correcting the power factor to keep the volt-age and current in phase, maintaining strict volt-age levels, and minimizing harmonic distortion.

Power Factor Correction

Current and voltage are said to be “in phase”if they have the same frequency and if their waveforms coincide in time. The capacitive and induc-tive properties of electrical circuits can cause thevoltage and current to be out of phase at particu-lar places and particular times. Phase shifts areexpressed as the cosine of the fraction (in degrees)of the full 360° cycle of the difference betweenthe voltage and current maximums, called powerfactor. A power factor of 1.00 means that the cur-rent and voltage signals are in phase. A powerfactor different from 1.00 means that the voltageand current are out of phase, and can be either“leading” if the voltage maximum occurs beforethe current maximum, or “lagging” if it occursafter. Because the most useful power is deliveredwhen voltage and current are in phase, it is im-portant that the power factor be as close to 1.00as possible.

Phase shifts are one consideration in setting thedemand component of rate structures (see ch.3). Thus, utilities typically will have one rate forpower with a power factor of 1.00 sold to otherutilities, another rate for power sold to industrialcustomers which may have power factors muchless than 1.00 and that require the utility to in-stall special monitoring devices, and another ratefor power sold to residential customers, wherepower factor is not measured individually (l).

Utilities (and cogenerators) supply power withtwo basic types of alternating current (AC) gener-ators—induction generators and synchronousgenerators (64). An AC generator produces elec-tric power by the action of a rotating magneticfield that induces a voltage in the windings of thestationary part of the generator. The rotation iscaused by mechanical means (steam or combus-tion turbine, diesel engine, etc.) and the magneticfield is created by a current flowing in windingson the rotor. For an induction generator, this cur-rent is supplied by an external AC source, such

as the electric power grid. For a synchronous gen-erator the rotor current comes from a separatedirect current source on the generator itself. Asa result, a synchronous generator can operate in-dependently of the electric grid or any other ACpower source whereas induction generators can-not. When a cogenerator feeds into a power grid,induction generators can be advantageous be-cause they are less expensive than synchronousgenerators (22). There are other characteristicsof the two types of generators, however, whichcan negate this cost advantage.

First, synchronous generators have power fac-tors of approximately 1.00 but can be adjustedto slightly leading or slightly lagging, while induc-tion generators always have lagging power fac-tors because they have more inductive than ca-pacitive elements (15,35,64). Second, synchro-nous generators are more efficient than induc-tion generators. These two points can cause syn-chronous generators to be preferred for unitsabove a certain power level (about 500 kW), al-though the precise value depends on the situa-tion (22). Third, care must be taken if there areseveral cogeneration units on a circuit, as wouldalmost certainly be the case for a utility buyingcogenerated power. When a synchronous gener-ator is connected to other generators (either syn-chronous or induction), separate equipment isneeded to synchronize each additional generatorwith the others. Such equipment is standard butdoes add to the total system cost.

Most cogenerators that have been installed todate have been larger synchronous machines be-cause they can be used if the grid is disconnectedand they offer redundant capacity for those (usu-ally higher demand) customers who need securepower sources, such as hospitals and computercenters (15). However, PURPA provides incen-tives for all sizes of cogenerators, and thus thosecustomers that can use smaller generators anddo not need redundant capacity will have an eco-nomic incentive to use an induction generator.As the penetration of these induction cogenera-tors increases, more inductive elements areadded to a particular distribution substation’s cir-cuits, resulting in a more lagging power factor.Unless the utility has a leading power factor, thiscreates three potential problems for the utility:


the capacity of both transformers and switchingequipment in the transmission and distributionsystem may have to be increased to handle theout-of-phase signals; the efficiency of the trans-mission network may decrease;* and equipmentand appliances may overheat and need more fre-quent overhaul (20).

Utilities normally improve lagging power fac-tors by using capacitors, which may be sitedeither at the distribution substation or near thecustomer’s load or generator, depending on thecause of the poor power factor and its magnitude(22). If the poor power factors are caused bysmaller customers’ equipment, utilities usuallypay for the correcting capacitors, while larger cus-tomers often are required to pay for their ownpower factor correction. Most utilities have guide-lines that state the minimum power factor al-lowed, usually 0.85 lagging (46). If a customerfails to maintain this minimum, utilities may askthe customer to install and pay for the necessarycorrective capacitors. * * Traditionally, few utilitieshave leading power factors, because most util-ity circuits (and most appliances and motors) havemore inductive elements than capacitive ele-ments.

Similar policies will apply to cogenerators.Thus, many utilities are supplying capacitors (outof the overall transmission and distribution sys-tem) for smaller cogenerators, while requiringlarger ones to pay for their own capacitors underthe theory that there will be fewer substationswith a significant cogeneration penetration. Thus,the avoided substation capacity becomes part ofthe utilities’ avoided cost under PURPA and iscredited to the cogenerator (see ch. 3).

*Other sources have indicated that the increase in utility transmis-sion and distribution efficiency compensates for the decrease inpower factor from induction generators (40). Efficiency is increasedbecause more power is produced onsite and therefore less poweris transmitted and less power is lost due to inefficiencies in the trans-mission and distribution system.

**Salt River Project has monitored an interconnected photovoltaicarray for an entire year and calculates that its average lagging powerfactor is about 0.50 (10). However, the array produces direct cur-rent (DC) power and uses an inverter to convert the DC power intoAC. Since cogenerators produce AC power, no inverter is necessary.Inverters have a poorer power factor than most induction gener-ators.

Southern California Edison’s guidelines are typi-cal of those utilities that have set guidelines:

Installations over 200 [kW] capacity will likelyrequire capacitors to be installed to limit the ad-verse effects of reactive power flow on Edison’ssystem voltage regulation. Such capacitors willbe at the expense of the [co]generating facility(49).

This expense can be important for smaller cogen-eration systems: for example, the cost of capaci-tors to increase the power factor of a 300-kWgenerator from 0.70 to 1.00 can range from 1 to4 percent of the capital cost of the cogenerator. *

However, just the installation of capacitors maynot be sufficient. If the capacitors are located nearinduction generators, the generators may “selfexcite; “ in other words, they may continue tooperate even when they are disconnected fromthe utility power source. This could be a prob-lem for utility lineworkers because the cogenera-tor could start supplying power and endanger theworkers. This is discussed in more detail in thesection on safety, below.

Voltage Regulation

In addition to potential problems with main-taining appropriate power factors, utilities also areconcerned with regulating voltage. Utilities havemany concerns about variations in voltage cyclefrom the standard cycle, both over long and shorttime intervals. While some customers can toleratevoltage levels outside of a specified range for verybrief intervals (less than a second), any longerterm variation will cause motors to overheat andwill increase maintenance costs. * * Voltage cycle

*This range assumes that capacitors may cost anywhere from $9to $40/kVAR (kilovolt-am peres-reactive, a measure of current andvoltage handling capability), with the low end of the range represent-ing the cost for capacitors used in the large bulk transmission sys-tems, such as those maintained by American Electric Power; andthe high end of the range representing the cost for capacitors usedin smaller distribution system applications, such as single-family res-idence interconnections (29,43). The amount of capacitance neededto correct a power factor of 0.70 to 1.00 is 1.02 kVAR/kW (63).Capital costs are assumed to be $1 ,000/kW for a 300 kW generator(6,61). Thus, the range of costs are 40 X 1,02 = $41/kW to 9 X

1.02 = $9/kW, or approximately between 1 and 4 percent of thecapital cost.

**The American Public Power Association’s guidelines cite a tablefrom the Estimator’s Guide that give recommended voltage rangesover a given day, hour, minute, and second (l).


variations are minimized through the proper de-sign and operation of generators. However, gen-erators do not always function perfectly, and pro-tective “over/under voltage” relays generally arenecessary to disconnect the generator if its volt-age falls outside of a certain range. These relaysusually cost under $1,000, including installation(15,22).

The State regulatory commissions normally re-quire a steady supply of 120 (or 240) volts (+/-5percent) for residential customers (1). Large com-mercial and industrial customers often receivetheir voltage directly from substations or distribu-tion lines, with much higher voltages and differenttolerances (see the discussion of transmission anddistribution in ch. 3).

Two major analyses are available of potentialvoltage regulation problems caused by improper-ly interconnected dispersed generators. Onestudy considers a sample utility with sO percentof its customers generating power with wind ma-chines (14). This study might be considered a“worst case” analogy for cogeneration becausethe output from the wind machines will changemore often than the output of typical (either in-duction or synchronous) cogenerators. Even withthis 50 percent penetration, the study indicatesthat substation voltage levels would remain within5 percent of standard levels because:

. . . [the] addition of small wind systems to a [dis-tribution] feeder will not occur suddenly; ratherwind-turbine generators will be installed in smallcapacities throughout the utility’s system and if,by chance, many are added to a particular feed-er, the voltage profile will change gradually.[Also] utilities adjust voltage regulation equip-ment for normal load growth and wind-turbinegenerators added to a feeder will influence thisnormal adjustment procedure only slightly (13).

In the second study, the Salt River Project (SRP)installed a transformer on its 37.5-kVA distribu-tion circuits and connected it to two residences(both unoccupied), one of which uses a photo-voltaic array, in order to test the effect of thephotovoltaic system on other residences con-nected to the same distribution transformer (12).That study also concluded that voltages wouldremain within 5 percent of standard (10).

Both of these studies indicate that cogenera-tion should not present any longer term (i.e., last-ing longer than 1 minute) voltage regulation prob-lems for utilities. However, sudden and morebrief changes in power system voltages can alsooccur in utility systems—especially when largepower consuming equipment is turned on andoff (such as the cycling of air-conditioner com-pressors and refrigerators). These changes arecaused by the large amount of current that isneeded to startup these motors, thereby remov-ing some power normally used for the remain-ing load on the circuit. Because these large surgesof power can temporarily dim lights, thesechanges are called “voltage flicker. ”

Utilities usually confine voltage flicker problemsto the customer’s own system by requiring somelarge commercial and industrial customers to usea “dedicated” distribution transformer that con-nects the customer’s load directly to a higher volt-age distribution line, substation, or, in somecases, the higher voltage transmission network. *Because of this policy, voltage flicker and regula-tion effects of cogenerators are extremely site-and circuit-specific and it is difficult to make anygeneral statements except that most of the com-mercial and industrial facilities that are potentialcogenerators probably already have a dedicatedtransformer (15). Therefore there would be noadditional cost for voltage regulation if thesecustomers were to install cogenerators. One wayfor cogenerators to get around this problem is toinstall synchronous generators, which already in-clude voltage regulators.

However, if a potential cogeneration facilitydoes not have a dedicated transformer and usesan induction generator (e.g., smaller commercialand residential customers), the cost involved ininstalling a transformer could be equal to all otherinterconnection equipment costs combined, andtherefore could be a major disincentive to cogen-eration. In general, however:

dedicated transformers are not a valid issuefor any but the smallest cogenerators or small

*The connection depends on the size of the customer’s load

(usually, the larger the customer, the higher the voltage connec-tion), the density of the surrounding area (transformers would beneeded in rural areas with spotty concentrations of loads, and invery high density urban areas), and on other site- and distribution-circuit-specific conditions.


power producers (less than about 20 kw) and,of those, only the ones installed in high densityareas where non-dedicated transformers are theusual method of service. where a dedicatedtransformer is needed, the issue usually is] set-tled through negotiations between the utility andthe customer with the requirement for a dedi-cated transformer being waived if it would be im-practical (15).

Even though dedicated transformers may notbean issue for many cogenerators, most utilitiesprotect themselves by including a clause in theirinterconnection agreement that says:

[f high or low voltage complaints or flickercomplaints result from operation of the custom-er’s [co]generation, such generating equipmentshall be disconnected until the problem is re-solved (49).

The interim guidelines published by the RuralElectrification Administration state that “no in-duction generators larger than 10 kW should bepermitted on single phase secondary services . . .due to possible phase unbalances and voltageflicker” without the electric cooperative firststudying the situation to ensure that adequate andreliable service to all members will be maintained(52).

Harmonic Distortion

A third utility concern related to power qualityis harmonic distortion. Occasionally, other fre-quencies besides the standard 60 cycles per sec-ond are transmitted over the power system, usu-ally due to the use of an inverter that convertsDC power into AC power. The distortions arecalled harmonics because they have frequenciesthat are multiples of 60. These distortions maybe made up of several harmonic frequencies ora single strong frequency. A 60 cycle-per-secondpower signal accompanied with many other har-monic signals may cause several problems for theutility:

Excessive harmonic voltages [and currents]may cause increased heating in motors, trans-former relays, switchgear*/fuses, and circuitbreaker ratings, with an accompanying reduction

*Switchgear (used in this citation and throughout this report) refersto all of the necessary relays, wiring, and switches that are usedin interconnection equipment.

in service life, or distortion and jitter in TV pic-tures, or telephone interferences. Also, excessharmonics may produce malfunction in systemsusing digital and communications equipment(20).

Other possible problems caused by excessive har-monics are the overloading of capacitors, mal-functioning of computers, and errors in measur-ing power at the customer’s kilowatthour meter(12,25).

What constitutes “excessive” harmonics is notwell defined. There is no agreement on the ex-act ratio of distorted signals to the standard signal,and a great deal of research is underway to deter-mine this ratio precisely. SRP has collected dataon the operation of an interconnected photovol-taic array for over a year:

But, SRP feels further study is needed on thelevel of harmonics that occurs naturally on a util-ty system, the limits that must be placed on har-monics required to prevent adverse effects onequipment and appliances, and on whether cer-tain harmonic frequencies are more harmful [tothe utility system] than others (4 I).

While further research is underway, both theElectric Power Research Institute (EPRI) and theAmerican Public Power Association (APPA) haverecommended maximum percentage limits fortotal systemwide harmonic distortions for bothcurrent and voltage signals (as well as limits forany one single source and single voltage or cur-rent frequency). EPRI (20) suggests 5 percent forcurrent harmonics, and 2 percent for voltage,while APPA (1) suggests 10 percent for currentand 2 percent for voltage. *

In the past, most of the major problems of har-monics have occurred with the normal operationof inverters, rather than any malfunctioning ofconventional induction or synchronous genera-tors (15). Since inverters have a high capital cost,they rarely are used and their present impact onutility systems is small in most cases. Becausecogenerators produce AC power at the standardpower system frequencies and, therefore, do notuse inverters, and because these generators arenot normally a significant harmonic source, most

*Several municipal utilities already have adopted APPA’s recom-mendations for harmonics, such as the Salt River Project in Phoenix.


utility engineers feel that harmonic distortions willnot increase when cogenerators are intercon-nected to utility systems (43).

Summary of Power Regulation Problems

Smaller cogenerators (under 20 kW) may notbe able to afford the necessary power regulationequipment in connecting to the centralized grid,including capacitors to correct power factor (ifrequired) and dedicated transformers to regulatevoltage (if not already in use). However, thesesmaller units may have little or no adverse effecton overall system power quality, according to onestudy looking at wind machine penetration. Thus,a utility, when considering each particular caseof a smaller cogenerator, may be able to exemptthe cogenerator from the requirements for expen-sive interconnection equipment. Larger grid-connected cogenerators might need to installcapacitors to correct for power factor—if they useinduction generators— but probably will have adedicated transformer already.

Even though all of the power quality effects ofinterconnected cogeneration are very site-specif-ic, most of the evidence gathered so far indicatesthat neither excessive harmonic distortion nor ob-jectionable voltage flicker will be caused by add-ing any size of cogenerator to the centralizedsystem.

Metering

Three types of metering configurations can beused to measure the amount of energy consumedand produced by dispersed generators. The firstuses the simple watthour meter that is commonlyfound outside of most homes today and that costsapproximately $30* (1,29). When a cogeneratoris producing power that is sold back to the util-ity, the watthour meter simply runs backward(even though the meter running backwards canbe off as much as 2 percent in measuring power)(l). As a result, the meter will measure only netpower use, thus assuming that there is no differ-

*More complicated (and more expensive) three-phase watthourmeters may be used where three-phase power, which consists ofthree (current and voltage) single-phase signals, each out of phasewith the others by 120°, is supplied to larger commercial and indus-trial customers.

ence between the utility’s rates for purchasingcogenerated power and its retail rates. If theserates are different (as they are likely to be withmost utility systems) then two watthour meterscan be used, one that runs in the reverse direc-tion of the other, with the first meter to measurepower produced by the cogenerator and the sec-ond (equipped with a simple detente or rachetthat prevents the reverse rotation of its inductiondisk) to measure the customer’s power consump-tion. This configuration is recommended by theNational Rural Electric Cooperative Associationinterim guidelines, unless the individual electriccooperative prefers a different metering system(52).

The third configuration uses more advancedmeters to measure a combination of parameters,including power factor correction, energy, andtime-of-use. * Some utilities are asking customersto install these advanced meters in order to un-derstand the relationship between the cogenera-tor and the central power system better, and tocollect the best data possible to help determinefuture interconnection requirements (such as in-formation on power factor requirements andpeak demands) and to decide how to price buy-back and backup power. These more sophisti-cated meters can cost $300 or more each (29).In some cases, such as with Georgia Power, theutility is supplying the advanced meters and pay-ing for the collection and analysis of data (30).In others, such as with SRP (46) and SouthernCalifornia Edison, ** the customer may be askedto pay for the meters (either as a one-time chargeor in several types of monthly installment plans).

Controlling Utility System Operations

Most utility systems have a control center tocoordinate the supply of power with changes indemands. Such coordination involves both day-

*Theordore Barry & Associates (52) provides many examples ofthese more advanced configurations, and includes the cost (exclud-ing instrument transformers) for different combinations of single-phase meters.

* *southern California Edison already bi Ils its larger customers

(either those installations with greater than 200 kW of generationor those with less than 200 kW generation with greater than 500kW of load) using time-of-day meters. Customers that becomecogenerators who do not have time-of-day meters already will notbe required to install them by Edison (15).

152 ● lndustrial and Commercial Cogeneration

to-day operations, including dispatching genera-tors and monitoring load frequency and powerflows over the transmission and distribution net-work, and longer term tasks needed to scheduleunit commitments and maintenance (25). If loadchanges are not anticipated correctly by systemcontrollers, transformers may become over-loaded and circuit breakers may open the line,possibly causing power reductions or interrup-tions for customers that are connected to thattransformer. Cogenerators have the potential toaffect two types of system operations: generationdispatch and system stability.

Generation Dispatch

Many utilities are concerned that large numbersof cogenerators will overload system dispatch ca-pabilities, including the ability to anticipatetransformer overload conditions (43). If the util-ity feels the cogenerated electricity needs to bedispatched centrally, it could require a connec-tion via telemetry equipment between the cogen-erator and the control center, so that the systemcontrollers can turn cogenerators on and off ac-cording to the overall needs of the utility system(36). This telemetry equipment is costly, andprobably would be used only with very largecogenerators.

One study has looked at potential dispatch andcontrol problems for a large penetration of windgenerators and has concluded that with approxi-mately half of the load using grid-connected windturbines, the dispatch and control errors of thesystem controllers would not increase significant-ly (14). Because wind machines would havegreater fluctuations of power output than cogen-erators, large numbers of cogenerators shouldpose even fewer control problems.

For smaller cogenerators, it is unlikely that theutility would require any dispatch control. Rather,these smaller units can be treated as “negativeloads,” in which case the controller would sub-tract the power produced by the dispersedsources from his overall demand and dispatch theutility’s central station generation to meet the re-duced demand. Negative load treatment prob-ably will be more advantageous to the utility sys-

tem than dispatch telemetry because the overallimpact of smaller cogenerators on system loadingand voltage conditions may be quite limited (44).

Negative load scheduling works well for thoseutilities that already have a few cogenerators on-line, and some utility transmission planners be-lieve that even much larger numbers would notcause problems for the utility. That is, as morecogenerators are added to a particular distribu-tion substation, the utility would continue to usenegative load scheduling. (The utility would needto increase the capacity of the transmission anddistribution lines–equivalent to upgrading thecapacity of its lines as a developer adds morehomes to a subdivision.) Because conditions areso site-specific, it is difficult to generalize and putforth guidelines, and each utility’s situation mustbe considered individually to determine the ap-propriate requirements (44).

System Stability

Stability refers to the ability of all generatorssupplying power to stay synchronized after anydisturbance (such as after a fault on part of thepower system) (25). At its most extreme, a disturb-ance may cause a loss of synchronization for theentire power system (resulting in a possible sys-temwide blackout), or may alter the flow ofpower within the system and cause selectedblackouts.

Not much is known about the effects of a sig-nificant number of cogenerators on a system’sstability. Utilities are concerned that large pene-trations of small, dispersed sources of powercould contribute to unstable conditions. Someanalysts (25) cite a 5 to 10 percent penetrationof the service area (with photovoltaic systems) asthe definition of “large penetration,” while otherscite much higher figures. One study by MichiganState University (cited in 25) shows that wind tur-bines cause fewer stability problems for the over-all utility system than variations in weather (suchas the movement of storm fronts). Further re-search on the effects of cogenerators on systemstability is needed before any conclusions can bemade, however.


Safety

A major concern with interconnection of dis-persed generators is the safety of utility employeesworking on transmission and distribution lines.During routine maintenance or repairs to faultylines, lineworkers must disconnect the genera-tion source from the service area, and establisha visibly open circuit. Also, before starting anyrepairs, they must ground the line and test it toensure that there is no power flowing in the line.The Occupational Safety and Health Administra-tion publishes a series of guidelines for utilitieson these procedures (OSHA subpt. V, sees.1926.50 through 1926.60),

Disconnecting and grounding the lines is rela-tively simple when the generation system is cen-tralized and there are few sources of supply.However, with numerous sources of power sup-ply (as with grid-connected cogenerators) the dis-connect procedure becomes more complicatedand extra precautions may be needed: the util-ity must keep careful accounts of what dispersedequipment is connected to the system, where thatequipment is located, what transmission lines anddistribution substations it uses, and where thedisconnecting switches are located. To simplifythese procedures, many utilities have asked co-generators to locate their disconnect switches ina certain place, such as at the top of the pole forthe distribution line going into the customer’sbuilding (30).

Disconnecting and reconnecting a cogeneratoris not so simple as just turning the switch off andon, because the cogenerator must be synchro-nized and brought up to the standard frequencybefore coming back on-line with the centralizedsystem. Without this synchronization, both thecogenerator and the customers’ appliances couldbe damaged.

However, the normal operation of circuitbreakers that have disconnected a line to cleara fault is to reclose automatically after a fractionof a cycIe. * If a problem on the line is still pres-

*One consultant cites the following example:An oil circuit recloser (OCR) responds to a fault, such as a tree limb

against a conductor, by deenergizlng the line for approximately one-quarter to one second, and then recloses to restore service In the eventthe fault was temporary. This operation may be repeated up to three

ent, a cogenerator also will need to be concernedabout this reconnection. Most utilities requireprotective equipment that can disconnect the co-generator from the line before any reclosing canoccur (49).

Another problem with disconnecting cogenera-tion equipment is self-excitation of the generators.When an induction generator is isolated from therest of the grid (because of a downed line or abreaker opening the line), the absence of the grid-produced power signal usually will shut down thegenerators. However, if there is sufficient capac-itance in the nearby circuits to which the genera-tor is connected (e.g., power factor correctingcapacitors), the induction generator may con-tinue to operate independently of any power sup-plied to the grid. * The power signal producedby the isolated self-excited induction generatorwill not be regulated by the grid’s power signaland the customer’s electricity-using equipmentmay be damaged. More importantly, an isolatedinduction or synchronous cogenerator that re-energize on the customer’s side of a downedtransmission or distribution line, could endangerutility workers. Self-excitation is less of a prob-lem with synchronous generators (which will con-tinue to operate independently of the grid).

There are two ways to prevent self-excitationproblems. First, the utility can put the correctivecapacitors in a central location, in which casedisconnecting a cogenerator also will disconnectthe capacitors and reduce the possibility of self-excitation. Southern California Edison recom-mends this method for smaller (less than 200 kW)cogenerators (49). Alternatively, voltage and fre-quency relays and automatic disconnect circuitbreakers can be used to protect both the cus-tomer’s equipment and utility workers.

In summary, while extra precautions must betaken to ensure the safety of utility crews, noneof these precautions is difficult to implement and,

times, depending on the recloser setting, before the OCR [leaves] theline deenergized (52).

Such alternate connecting and disconnecting can damage thecogenerator.

*One consultant calculated that this self-excitation is possible withwind turbines (1 4). A 100-kW machine capable of supplying halfof the customer’s load, connected to the capacitors needed to cor-rect a 0.75 power factor to 1.00, will self-excite and supply 30 voltsto that load—25 percent of the standard 120 volts.


when properly carried out, will minimize the po-tential for danger to utility personnel.

Liability

Despite the protective relays and automatic dis-connect switchgear that may be installed, thisequipment may not always function properly andthe cogenerator could damage the utility’s equip-ment or other customers’ appliances. UnderPURPA, the net increased interconnection costsmay include the cost of insurance against liabil-ity for such damage, or liability may be assignedto the cogenerator in the purchase power con-tract. Liability issues also have been raised regard-ing wheeling, but in that case no special insur-ance policy is needed, and all the ratepayersshare any liability for damage due to wheeledpower (6).

At the present time, few guidelines exist for util-ities concerning the liability of the cogenerator.A set of guidelines being prepared by EPRI recom-mends that the cogenerator be responsible fordamages caused by the cogeneration system, upto and including the connection to the customer’sside of the meter (20). A second approach hasbeen adopted by Southern California Edison,whose interconnection contract provides that:

Customer is solely responsible for providingprotection for customer’s facilities operating inparallel with Edison’s system and shall releaseEdison from any liability for damages or injuryto customer’s facilities arising out of such paralleloperation, unless caused solely by Edison’s negli-gence . . . Customers shall be required to main-tain an in-force liability insurance in an amountsufficient to satisfy reasonably forseeable indem-nity obligations and shall name Edison as an addi-tional insured under said insurance policy (49).

A precise definition of “reasonably foreseeableindemnity obligations” is not yet clear. Few util-ities will put an exact figure in writing and leaveeach case to be determined on an individual ba-sis. Many have argued against some of these lia-bility requirements that place an excessive costburden on owners of cogenerators and smallpower producers. A staff report to the CaliforniaPublic Utilities Commission (CPUC) recom-mended that utilities be allowed to include only

standard “boilerplate” liability and indemnityprovisions, and not to require a cogenerator “toassume a greater responsibility for losses resultingfrom its acts or equipment failure than it wouldhave under common law principles” (8). The staffalso has tried to eliminate the dual cost burdenof insurance and dedicated transformers, and hasrecommended that cogenerators and small pow-er producers with capacity under 20 kW thathave installed dedicated transformers be excusedfrom providing proof of liability insurance. In an-other case, the New York Public Service Commis-sion ruled that the utility could not require acogenerator to assume the utility’s broadlysweeping liability clauses, but rather the utilitycould require a cogenerator to be responsibleonly for negligent installation and operation ofhis equipment (3).

Summary of Requirements

Cogenerators may need several types of equip-ment for proper interconnection with centralizedutility grids: corrective capacitors to meet powerfactor requirements, relays and filters to protectthe circuits of other customers, special meters tomeasure cogeneration energy profiles, and dedi-cated transformers and increased transmissionand distribution line capacity to ensure reliableservice. Moreover, cogenerators may be requiredto carry special liability insurance to limit theresponsibility of the utility or its noncogeneratingcustomers. These requirements are displayedgraphically in figure 41.

While utilities and cogenerators agree thatinterconnection may pose all of the problems dis-cussed above, there is still much to be decidedabout the frequency and severity of these prob-lems for particular cogeneration systems. Evenwhen utilities and cogenerators agree about thenature of potential interconnection problems,they may disagree about the type or quality ofequipment necessary to resolve them.

Quality of Interconnection Equipment

One of the critical questions concerns the qual-ity of the equipment used in the interconnection.There are two basic levels of quality: “industrial”


Figure 41 .—Possible Power System Additional Equipment Requirements to Serve Qualifying Facilities

II

II

SOURCE: Blair A. Ross, “Cogeneration and Small Power Production Facility Effects on the Electric Power System,” paper presented at Federal Energy RegulatoryCommission conference on Cogeneration and SmalL Power Production RuLes, June 1980.

and “utility” grades. Utility grade equipment gen-erally is more reliable and responsive, but it alsocosts more than industrial grade (40). Althoughrequirements have varied in the past, a generalconsensus is emerging that industrial grade equip-ment is adequate for smaller (under 300 kW) co-generators while larger cogenerators should usethe more costly utility grade. This distinction isbased not only on the safety implications of asystem failure but also on the cost of replacingdamaged equipment. For smaller cogenerationsystems, the maintenance or replacement cost ofutility grade equipment could be several timeshigher than the cogenerator’s monthly electricitybill.

However, utility grade equipment may be nec-essary under certain circumstances. For example,Southern California Edison requires “utility qual-ity” protective relays if a cogenerator is largeenough (more than 1 -MW installed capacity) thatthe opening and closing of utility relays must besynchronized (49). While many utility engineersagree with this distinction, they also may disagreeabout the size of equipment that requires indus-trial or utility grade. One source suggests that in-

dustrial grade equipment should be used by co-generators smaller than 200 kW, while others sug-gest 1 MW as the cutoff point (34).

Guidelines for Interconnection

Utilities differ widely in their general specifica-tion of interconnection requirements. Some util-ities have adopted guidelines, while others revieweach interconnection design to ensure that itmeets their standards. Although case-by-case re-view can result in costly delays for a cogenerator,utilities and interconnection experts agree thatseparate reviews are necessary until industrywidestandards have been developed for the intercon-nection of onsite generating equipment (4). Atthis time, each cogenerator has virtually custom-designed configurations of interconnectionequipment because the circumstances underwhich connections are made vary widely, andso few cogenerators have been installed by eachengineer that it is difficult to generalize and userules-of-thumb (57).

Research is underway to provide the neededinformation for future guidelines, and several sub-


committees of the Institute of Electrical and Elec-tronics Engineers’ (IEEE) Power System RelayingCommittee* are working together on a manualof accepted interconnection standards, with spe-cific engineering guidelines for a wide range ofequipment types and conditions. EPRI also is as-sembling its own guidelines, although for a moregeneral audience, and researchers at the Jet Pro-pulsion Laboratory (JPL) have made many recom-mendations on guidelines to the Department ofEnergy’s (DOE) Electrical Energy Systems Division(25). Several staff members at IEEE, EPRI, DOE,and JPL are delegates to a committee that willrecommend changes in the National ElectricalCode related to interconnection equipment bylate 1983 (24). Finally, several utilities are install-ing instruments on their own initiative to measurepower factor, voltage variation, frequency, andother aspects of cogenerated power, with thehope that this better instrumentation will lead toa better understanding of interconnection per-formance, costs, and benefits (37).

This research points out the need for perform-ance-based guidelines—allowing cogenerators tomeet general functional criteria—rather than tech-nology-specific guidelines that might require par-ticular technologies that could become out-moded or more costly in the future. The CPUCstaff (8) recommended that utilities should useperformance-based guidelines (that specify suchfunctions as reacting properly to utility systemoutages, assisting the utility in maintaining systemintegrity and reliability, protecting the safety ofthe public and of utility personnel), rather thanspecifying a list of equipment that could restrictcogeneration unnecessarily (8).

Southern California Edison complied with theCPUC staff recommendation by issuing a com-plete set of equipment performance specificationsas its guidelines. The guidelines provide all re-quirements for design, installation, and operationof interconnecting equipment in clear, easy-to-read language, and include examples of wiringdiagrams and metering configurations that meetits performance specifications for three types ofcogenerators: those over 200 kW with the inter-

*Hassan and Klein (25) give a good list of the various groups withinIEEE, as well as other organizations, that are working on these issues.

connection equipment owned by the customer,those over 200 kW with the equipment ownedby the utility, and those under 200 kW (49). Otherconsultants have also suggested that different pol-icies be used with different sizes of generators,with one policy covering units under 5 kW, an-other for units between 5 and 40 kW, and a thirdfor units over 40 kW (40).

Southern California Edison requires all intercon-nection equipment (that eventually will be ownedby the utility) for cogenerators larger than 200 kWto have four functions:

(i) A set of utility-owned circuit breakers in addi-tion to any circuit breakers that the customermay have installed,

(ii) synchronizing relays,(iii) meters for kW and kWh produced and de-

manded, kVARh demanded, and (for cogen-erators larger than 1 MW) telemetry and tele-phone communication lines, and

(iv) protective relays for short circuits, isolation (toseparate the cogenerator from other custom-ers on its line), over/under frequency and volt-age, and circuit-breaker closing/reclosing (toprevent the re-energizing of an open line) (49).

For installations over 200 kw with customer-owned interconnections, the Southern CaliforniaEdison requirements state: “The customer shallprovide adequate protective devices to detectand clear . . . short circuits, . . . detect voltageand frequency changes, . . . and prevent reparal-Ieling the customer[’s] generation.” There aresimilar, although less stringent, requirements forunder 200 kW equipment (49).

Southern California Edison also gives the cogen-erators three different options for paying for allrequired interconnection equipment: (i) the utilitysupplies and owns the interconnection equip-ment and the cogenerator pays a standardmonthly charge, currently 1.7 percent of the totalcosts of the facilities; (ii) the cogenerator installsthe equipment to utility specifications and trans-fers ownership to the utility at which time the util-ity assesses a one-time engineering charge for ap-proving the design, and the utility charges month-ly operation and maintenance fees for the equip-ment (currently 0.75 percent of the total costs ofthe facilities), or (iii) the utility builds the equip-ment, with an advance payment from the cogen-


erator, and the cogenerator pays the monthlyoperation and maintenance charge once con-struction is completed (49). Most utilities just of-fer the last option, with monthly charges greaterthan $1,000 for large installations of several mega-watts capacity, and much less for smaller facilities(46).

Costs for Interconnection

Interconnection costs can vary widely depend-ing on the size of the cogeneration system andon the requirements of the utility or State regula-tory commission. Two published studies on co-generation allow for a detailed comparison ofcosts for a variety of assumptions. One set of sam-ple costs includes schemes for a variety of gener-ators and is shown in table 26. These schemeshave used similar assumptions in assembling theinterconnection costs, and so are useful for com-parison purposes and relating the economies ofscale of interconnection.

As can be seen in table 26, the interconnec-tion requirements for the larger units cost less perkilowatt to construct and maintain; and as the sizeof the cogenerator decreases, the cost per kilo-watt increases rapidly, from $35/kW for the 20-MW generator up to $1,328/kW for the 2-kw

generator. Because cogenerators in this rangetypically cost about $1 ,000/kW, the total costsfor interconnection of these smaller generatorscan exceed the capital costs of the generators.

Some utility personnel feel these costs are high-er than their experience would indicate (35,43).Some of these costs may be unnecessary or elsemight be paid by the utility instead of by thecogenerator (6,8). For instance, dedicated trans-formers may be installed already, thereby reduc-ing the total interconnection cost substantially—insome cases by more than 30 percent.

These costs also depend heavily on whetherexisting switchgear is adequate or whethermodifications will be necessary to accommodatethe cogeneration equipment. For example, twodifferent 900-kW installations might vary in costbetween $150,000 (or $167/kW) and $250,000(or $278/kW)–with the difference resulting fromthe number of modifications needed in existingdistribution cables and switchgear (57).

Based on the published information, OTA hasassembled cost information for three differentsized systems, using two series of assumptions forinterconnection requirements for two of thesmaller generators and one set of assumptions forthe larger generator (22).

Table 26.—Cogeneration Interconnection Sample Costsa

Costs (dollars)Equipment (kW) Engineering Total cost

Schemeb Generator size Transformer size Switchgear Transformer Relay labor Total ($/kW)

Larger generators:A 20,000B 5,000c 4,200D 1,000E 200Smaller generators:F 100G’ 50H 50I 20J d e 5Kd 2

20,00010,00010,0002,500

750

111112112302510

$296,000150,000129,00056,00027,000

$4,7004,3401,5702,590

4961,035

$314,000160,000160,00031,00016,000

$2,2501,5301,530

640130350

$51,00043,00018,00011,0007,000

$2,0652,1251,325

360360320

$30,00030,00026,00012,00010,000

$1,9001,5501,5001,450

950950

$691,000339,000319,000104,00060,000

$10,9159,5455,9255,0401,9352,655

$356876

104300

$109191119252387

1,328aAll costs include new (either shared or dedicated) transformers, but do not include: watthour meters, annual maintenance requirements for all interconnection equip-

ment, and site preparation and cabling costs,b industrial-grade relays are used in all schemes.cScheme G uses more expensive circuit breakers than the other small generator schemes.dschemes A through I use synchronous generators, all others use induction generators..escheme J uses a shared transformer, all others use dedicated ones.

SOURCES: Office of Technology Assessment, from James Patton, Survey of Uti/ity Cogeneraflon hterconnection Practices and Cost—Flna/ Report (Washington, D. C.:U.S. Department of Energy, DOE/RA/29349-Ol, June 1980); James Patton and S. Iqbal, Small Power Producer Irrterconnectlon Issues and Costs (Argonne,Ill.: Argonne National Latmratory, February 1981).


Because the range of conditions and the useand cost of interconnection equipment may varywidely with smaller cogenerators, two sets of as-sumptions were used; a “best case” that assumesthat power factor correcting capacitors, a dedi-cated transformer, and protective relays wouldnot be needed; and a “worst case” that assumesthat this equipment (along with more expensivemeters and equipment transformers for these me-ters and relays) would be needed. Both 50-kWsystems use induction generators, while both5oo-kW and 5-MW systems use synchronous gen-erators.

All of the equipment meets industrial gradespecifications and operates at 480 volts on athree-phase circuit (these are common conditionsfor medium-sized equipment). All of the costscited include installation, except for the protec-tive relays which cost $250 to install (22). Table27 displays the various cost components of theinterconnection for the three generators.

The cost to interconnect the smallest generator(50 kW) varies between $52 and $260/kW, or arange of 5 to 26 percent of the capital cost of thegenerator (assuming $1 ,000/kW capital cost). Thecost for the 500-kW generator varies between $22and $66/kW, or 2 to 7 percent of the capital cost,while the cost for the largest generator (5 MW)is $12/kW, or 1 percent of the capital cost.

From table 27, two important results are ob-served: First, most of the variations in cost result

from the addition of a dedicated transformer tothe interconnection requirements, as well as theuse of more expensive relays and other protec-tive devices. Second, the cost per kilowatt ofcapacity decreases quickly as the size of the gen-erator increases, primarily due to the economiesof scale for circuit breakers, transformers, and in-stallation costs, and because most of the cost ofthe relays is independent of the size of the gener-ator they protect. For example, even though thecapacity of the !@O-kW generator is ten times thatof the 50 kw, the circuit breaker costs only eighttimes as much and the dedicated transformeronly three times as much.

From these studies, it is concluded that thereis a great deal of variation in the cost of intercon-nection equipment per kilowatt of cogenerationcapacity. The costs will depend on the size of thecogenerator and the amount of transmission anddistribution equipment already in place. Costs perkilowatt will increase as the size of the generatordecreases and as the amount of new transmis-sion and distribution equipment increases.

Summary

Interconnecting cogeneration could createproblems for utilities, especially with respect toproviding satisfactory power quality, controllingsystem operation, and minimizing utility liabilityand safety problems. While many of these prob-lems may require special dedicated facilities or

Table 27.—interconnection Costs for Three Typical Systems

50 kW 500 kW 5 M WEquipment Best Worst Best Worst Average

Capacitors for power factor . . . . . . . . . . . . — $1,000 $5,000 – “Voltage/frequency relays . . . . . . . . . . . . . . . $1,000 1,000 $1,000 1,000 $1,000Dedicated transformer. . . . . . . . . . . . . . . . . — 3,900 – 12,500 40,000Meter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 80 1,000 80 1,000 1,000Ground fault overvoltage relay . . . . . . . . . . 600 600 600 600 600Manual disconnect switch . . . . . . . . . . . . . 300 300 1,400 1,400 3,000Circuit breakers . . . . . . . . . . . . . . . . . . . . . . 620 620 4,200 4,200 5,000Automatic synchronizers. . . . . . . . . . . . . . . — — 2,600 2,600 2,600Equipment transformers . . . . . . . . . . . . . . . 600 1,100 600 1,100 1,100Other protective relays . . . . . . . . . . . . . . . . — 3,500 – 3,500 3,500

Total costs ($) . . . . . . . . . . . . . . . . . . . . . . $2,600 $13,020 $11,080 $32,900 $57,800Total costs ($/kW). . . . . . . . . . . . . . . . . . . 52 260 22 66 12

NOTE: “-” means an optional piece of Interconnection equipment that was not Included in the requirements and costcalculations.

SOURCE: Off Ice of Technology Assessment calculations based on data derived from Howard S. Geller, The Interconnectionof Cogenerators arrd Small Power Producers to a Utility System (Washington, D. C.: Office of the People’s Counsel,February 1982),


operating and administrative techniques, noneare insurmountable and most have been resolvedin the past (44). One executive remarks that theutility industry has not yet identified any prob-lems with distributed generation which cannotbe solved technically (43). The real problem iswhether the cost involved will be prohibitive.

However, in order to determine costs, moreanalysis and better data are needed. Results ob-

tained to date through simulation and analysismust be verified in the field (25). In addition, Statecommissions need to encourage those utilitiesthat have not yet done so to prepare guidelinesfor interconnection requirements, and to updatethose guidelines as the results of new researchbeing conducted by EPRI, DOE, APPA, IEEE, andindividual utilities are made available, and as ex-perience is gained.

THERMAL AND ELECTRIC STORAGE

The analysis in chapter 5 shows that the greatestopportunity for cogeneration occurs when on-site thermal demands closely match regional elec-tric demands. To some extent, a cogenerator ora utility could mitigate a mismatch between thesetwo demand curves through the use of devicesthat store either the thermal or electrical energyfor release when it is needed. Thermal and elec-tric storage techniques are described brieflybelow. *

Thermal Storage

The thermal demand of an industry or buildingis rarely constant; rather, it varies with the day(e.g., weekday v. weekend day) and time of dayas well as with the season. As a result, an in-dustrial or commercial cogenerator may producemore thermal energy than can be used immedi-ately onsite. Similarly, if a cogenerator is supply-ing electricity to the utility grid, a mismatch be-tween the timing and/or magnitude of the onsitethermal needs and the utility’s electric demandscould result in temporary excess thermal energyproduction. In such circumstances, it maybe ad-vantageous to store this excess thermal energyfor subsequent use during periods when the co-generator is producing less than is needed on-site. Thermal energy storage also can be used toreduce peakloads on utility powerplants, to im-prove the efficiency of heating or cooling devicesby reducing cyclic losses, and to make it prac-tical to utilize periodic renewable energy sources

*More detailed information on both types of storage maybe found

[n reference 38.

(e.g., excess solar energy collected during the daycan be stored for heating during the night).

There are three basic approaches for storingthermal energy. In sensible-heat storage, engineor exhaust heat is used to elevate the temperatureof a liquid or solid that does not melt or other-wise change state for the temperature range inquestion. Water is the most widely used materialfor sensible-heat storage. It is relatively easy andinexpensive to store at temperatures below itsboiling point, but can be stored at temperaturesup to 300° to 400° F if pressurized tanks are used.At higher temperatures, the pressure required tomaintain water in its liquid form would greatlyincrease the cost and danger of operating thesystem. Even at lower temperatures, it can be dif-ficult to maintain constant output temperatureswhen the stored energy is tapped. Rocks also canbe used in sensible-heat storage by heating themand keeping them in insulated containers. How-ever, the heat storage capabilities of rocks arepoorer than those of water,

Latent-heat storage occurs when a materialundergoes a phase change (e.g., melting, vaporiz-ing) when heated. This approach supplies energyat a relatively constant temperature and usuallyallows for greater amounts of energy to be storedin a given volume or weight of material, as com-pared to the sensible heat approach. More than500 phase change materials have been reportedas potential thermal energy storage candidates,but three basic categories are used in low-temp-erature applications: 1 ) inorganic salt com-pounds, 2) complex organic chemicals such asparaffins, and 3) solutions of salts and acids. The


disadvantages of latent-heat storage include thehigh cost of the phase change materials and thedifficulty involved with transmitting thermalenergy in and out of the storage medium.

Chemical storage techniques use heat to pro-duce a chemical reaction, and then release theheat when the reaction reverses. The most prom-ising materials for the chemical storage of ther-mal energy are metal hydrides (compounds of themetal and hydrogen) because their reactions canbe reversed easily. Moreover, hydrides have rel-atively high heats of formation, while the reac-tion products can be stored at ambient temper-atures and the heat recovered as needed andstored indefinitely with no need for insulation.Chemical storage techniques may be applied ata wide variety of temperatures, and transportingthe chemical energy is convenient. However,chemical storage is likely to be less attractive thanother methods because the catalysts required tofacilitate the chemical reaction are expensive, asis the storage of gaseous chemicals in pressurizedtanks, and the metal hydrides may be highly toxicand pose a dangerous fire risk.

The size of a thermal storage unit will dependon the onsite energy needs (e.g., a single resi-dence, a large building or industrial plant, a utilitypowerplant). However, most of the experienceto date is in the design, construction, and opera-tion of smaller thermal energy storage systemscapable of storing heat from electric generatingplants with less than 500-kW capacity. Table 28indicates possible required storage capacity as afunction of typical industrial plant sizes.

Reliable data on costs, maintenance, and per-formance for thermal energy storage systems arenot yet available. Most systems are still in R&Dstages. Thermal energy storage using water inabove ground or underground tanks has been

Table 28.–Thermal Energy Storage (TES)Capacity Range v. Plant Size

Characteristic size (MW) TES capacity range (107 Btu)2 4 to 6

20 40 to 60100 200 to 300

SOURCE: Roger L. Cole, et al,, Oesign and Installation Manual for Thermal EnergyStorage (Argonne, Ill.: Argonne National Laboratory, AN L-79-15, 2d cd.,January 1960)

studied the most and is closest to being ready forcommercial use, although even these systems re-quire more research and design work.

The component costs of a thermal energy stor-age system will include the cost of the storagemedium itself, the containment facility thathouses the medium, and the maintenance re-quired to keep the storage system in workingorder. Other costs that accrue to sensible-heatsystems using water include the cost of additivesto inhibit corrosion or prevent freezing, whichcan be significant. Although costs are uncertain,developers have estimated storage costs as a func-tion of storage capacity for several low- and high-temperature thermal storage systems (see figs. 42and 43).

Figure 42.— Low-Temperature Thermal StorageCost per KWht v. Storage Capacity

50

20

10

NOTE: The storage units would lose only about 5 percent of the energy storedin the interval indicated. This cost is based on precast concrete andcoated steel, and excludes 25 percent O&P.

SOURCE: Application of Solar Technology to Today’s Energy Needs, Volumes Iand II (Washington, DC.: U.S. Congress, Office of TechnologyAssessment, 1976).


Figure 43.—High.Temperature Thermal StorageCost per kWht v. Storage Capacity

200

100

50

1.00

Storage capacity (kWh t)

NOTE The storage units would lose only about 5 percent of the energy storedin the interval indicated

SOURCE. App//cat/on of Solar Techrrology to Today’s Energy Needs, Volumes 1and // (Washington, D C.: U.S Congress, Office of TechnologyAssessment, 1978)

Some general factors affecting efficiency, orthe percentage of thermal energy recovered fromstorage, are the supply temperature range (theratio of the input temperature to the storagematerial temperature), the specific heat of thestorage medium, and the insulating properties ofthe storage container. In general, the overall ef-ficiency (energy in/energy out) declines as the in-

put temperature increases.

Little special maintenance should be requiredfor thermal storage tanks because they containno moving parts. However, it is necessary tocheck the tanks periodically for corrosion, andthe effects of normal weathering may necessitaterepainting or repair of the tank,

Electric Storage

Storage of electricity is an alternative means ofmatching generating capacity output with userdemand. It may be particularly advantageous inconjunction with intermittent sources of electrici-ty, including wind and solar generators as wellas some cogenerators.

The primary methods of storing electric energyare:

●

●

●

●

●

pumped storage, in which electricity is usedto pump water to a higher elevation duringperiods of low electricity demand, and thenthe water is released to the lower elevationto drive a turbine during times of peakdemand;compressed air storage, in which electricityis used to compress air during low demandperiods, and then the air is heated and ex-panded through a combustion turbine togenerate electricity at peak demand;electrochemical storage, which (as withchemical thermal energy storage) uses re-versible electrochemical reactions to storeelectric energy (e.g., in batteries);mechanical energy storage, which uses fly-wheels brought up to speed by electricmotors to store kinetic energy for subsequentcontrolled release to generate electricity; andthermal storage, in which electricity is con-verted to heat and stored in hot solid, liquid,or gaseous materials (as described above) forsubsequent controlled release to generateelect ricity.

The most common form of electric energy stor-age for dispersed energy systems (such as cogen-erators) would be battery storage. * However, theelectric energy must be introduced and with-drawn from batteries as direct current, and thusinverters must be included in any battery systemthat receives and produces alternating current.Within large bounds, the cost of batteries per unitof storage capacity is independent of the size ofthe system because most batteries consist of a

*Battery storage of electricity IS discussed in detail In increasedAutomobile Fuel Efficiency and Synthetic Fuels: Alternatives forReducing Oil Imports (OTA-E-185, September 1982).


large number of individual reacting cells. Largersystems may benefit from some economies ofscale because of savings due to more efficientpacking, lower building costs, and possibly lowercosts of power conditioning (see discussion of in-terconnection), but a separate analysis on thispoint must be performed for each type of bat-tery. It is likely that there will bean optimum sizefor each device.

Lead-acid batteries are the only devices current-ly mass produced for storing large amounts ofelectric energy using electrochemical reactions.Systems as large as 5,000 kWh currently are usedin diesel submarines. However, contemporarylead-acid battery designs have a relatively lowstorage capacity per unit weight (due largely tothe amount of lead used), and batteries now onthe market that can be discharged deeply often

enough for onsite or utility storage applicationsare too expensive for economic use in electrici-ty generation. Extensive work is being done todetermine whether it is possible to develop bat-teries suitable for use in utility systems, includingwork on advanced lead-acid battery designs andon several types of advanced batteries that maybe less expensive than lead-acid batteries in thelong term.

Advanced battery types include nickel-iron,nickel-zinc, zinc-chlorine, sodium-sulfur, andlithium-metal sulfides. Operating and cost char-acteristics as well as expected availability data aregiven in table 29 for several battery types. A com-parison of technical and cost characteristics forseveral electric storage systems, including ther-mally based electric storage is given in table 30.

Table 29.-Cost and Performance Characteristics of Advanced Batteries

Estimated availabilityOperating Energy density Power density Estimated cost (year) (prototypes

temperature (watthours (watts per Estimated (dollars per or earlyBattery type (degrees Celsius) per kilogram) kilogram) cycle life kilowatthour) commercial models)

Lead-acidUtility design . . . . . . Ambient — — 2,000 80 1984Vehicle design

(improved). . . . . . . Ambient 40 70 > 1 ,000” 70 1982Nickel-iron . . . . . . . . . . Ambient 55 100 >2,000 (?) 100 1983Nickel-zinc . . . . . . . . . . Ambient 75 120 800 (?) 100 1982Zinc-chlorine

Utility design . . . . . . 30-50 — 2,000 (?) 50 1984Vehicle design . . . . . 30-50 90 90 > 1,000 (?) 75 1985

Sodium-suifurUtility design . . . . . . 300-350 — — > 2,000 50 1986Vehicle design . . . . . 300-350 90 100 > 1,000 1985

Lithium-iron sulfide. . . 400-450 100 >100 1,000 (?) 80 1985NOTE: Variety of advanced types of batteries are currently under development for electric-utlllty storage systems and electric vehicles because the lead-acid battery

probably cannot be Improved much further. The table lists the properties of batteries that may prove superior. The most important criterion for storage in electric-power systems is long life: the ability to undergo from 2,000 to 3,000 cycles of charge and discharge over a 10- to 15-year period. For electric vehicles the chiefcriteria are high energy content and high power for a given weight and volume. (The dashes indicate that these criteria do not apply to electric utilities.) Boththe utillties and vehicles wIII require batteries that are low in cost (preferably less than $50/kWh of storage capacity), safe, and efficient.

SOURCE: F. R. Kalhammer, “Energy-Storage Systems,” 241 Scientific American 5665, December 1979.


Table 30.—Expected Technical and Cost Characteristics of Selected Electrical Energy Storage Systems

Hydro pumped Thermal Lead-acidCharacteristics storage Compressed air Steam Oil batteries Advanced batteries

Commercial availability . . . Present Present Before 1985 Before 1985 Before 1985 1985-2000Economic plant size

(MWh or MW) . . . . . . . . . . 200-2,000 200-2,000 50-200 50-200 20-50 20-50M W M W M W Mw MWh MWh

Power related costsa ($/kW) 90-160 100-210 150-250 152-250 70-80 60-70Storage related costsa

($/kWh) . . . . . . . . . . . . . . . 2-12 4-30 30-70 10-15 65-110 20-60Expected life (years) . . . . . . 50 20-25 25-30 25-30 5-10 10-20Efficiency b (percent) . . . . . . 70-75 —c 65-75 65-75 60-75 70-80Construction Ieadtime

(years) . . . . . . . . . . . . . . . . 8-12 3-12 5-12d 5-12 d 2-3 2-3

aConstant 1975 dollars, does not include cost of money during construction.bElectric energy out to electric energy in, In percentcHeat rate of 4,200 t. 5,5oo Btu/kWh and compressed air pumping requirements from 0.58-0.80 kwh (out)dLong Ieadtime includes construction of main PowerPlant.

SOURCE’ Decision Focus, Inc., Integrated Analysis of Load Shapes and Energy Storage (Palo Alto, Calif.: Electric Power Research Institute, EPRI EA-970, March 1979)

COGENERATION AND DISTRICT HEATINGDistrict heating is the use of one or more cen-

tralized sources of heat to supply thermal energyto a group of buildings through a piping network.A district heating system could provide spaceheating and domestic water heating, and in somecases space cooling, to residential and commer-cial customers, or it could provide thermal energyfor industrial processes. A district heating systemis not limited to any particular type of heat source,but could use conventional boilers, cogenerators,industrial or utility waste heat, or municipal incin-erators with heat recovery equipment. Districtheating systems generally are thought of as largecitywide systems—and thus, in a sense, central-ized power production—but they also can besmaller systems suitable for industrial or commer-cial parks, college campuses, and military bases.This section will summarize the advantages anddisadvantages of district heating based on cogen-erators; a more complete discussion of districtheating can be found in the OTA assessment, TheEnvgy Efficiency of Buildings in Cities.

A district heating system comprises three majorcomponents, as shown in figure 44: the thermalproduction plants that provide heat to the system;the underground transmission/distribution sys-tem, which conveys thermal energy (in the formof hot water or steam) from the thermal produc-tion plants to customers; and the in-buildingequipment—typically a heat exchanger that formsthe connection between the system distributionnetwork and the remainder of each in-buildingheating and cooling system.

Proponents of district heating systems for theUnited States cite several potential advantages ofsuch systems, including the improved fuel utiliza-tion efficiency of cogeneration compared to con-ventional steam-electric generating stations (asdescribed above); reduced heating costs (throughthe use of currently discarded heat and increasedequipment efficiency) relative to conventionalheating systems; increased certainty of fuel sup-ply, through reduced consumption of oil and


Figure 44.—European Cogeneration District Heating System

SOURCE: Bruce W. Wilkinson and Richard W. Barnes (eds.), Cogeneratlon of Electricity and Useful Heat (Boca Raton, Fla.:CRC Press, Inc., 1980).

natural gas for space heating, and/or a switch tocoal or waste fuels; reduced fire hazards in build-ings, through the substitution of a heat exchangerfor a furnace, a boiler, or electric resistanceheaters; reduced land requirements for sanitarylandfills if resource recovery facilities, such as heatrecovery incinerators, are used in district heatingsystems; and increased employment and revitali-zation of urban areas.

However, district heating also may have anumber of disadvantages. These include a veryhigh capital cost, due mainly to the transmission/distribution piping. Financing is crucial to the eco-nomic viability of district heating systems. If thedistrict heating system burns a high-grade fossilfuel (natural gas or oil), the increase in fuel useefficiency and the cost advantage to the consum-er (compared to individual heating units) arediminished by the high capital costs and thermallosses in piping. Thus, a district heating systemwill have a clear benefit only if it can utilize lowerprice, relatively abundant fuels such as coal andmunicipal solid waste that cannot be burned di-rectly in individual heating units. In addition, theinstallation and maintenance of district heating

systems, including the time required for the pip-ing, can be drawn out and disruptive. Duringconstruction, commercial establishments maylose business and traffic may have to be rerouted.Furthermore, system maintenance sometimes willrequire reexcavation of the pipes, but cannotalways be performed during periods of low heatdemand (summer), since a break in the systemduring the winter could prevent heat from reach-ing customers who do not have backup heatingsystems. Finally, district heating systems havelimited applicability, and some very specific con-ditions must be met for viability, including a highconnection rate and careful design and siting.These latter points are discussed more completelyin The Energy Efficiency of Buildings in Cities.

District heating is not a new idea, but a tech-nically proven concept with no breakthroughs ordiscoveries needed for implementation. Over 40utility-run steam district heating systems in theUnited States go back as many as 80 years, whilemany smaller steam systems serve university cam-puses, shopping centers, industrial parks, militarybases, or industrial plants located adjacent topower stations. A high proportion of the heat in


Northern Europe is supplied by hot water districtheating. However, U.S. city-scale district heatingsystems owned by utilities have, up until now,enjoyed little success when compared to Euro-pean systems, primarily because European sys-tems use hot water instead of steam. Steamdistrict heating systems are only justified for smallareas with very high thermal load densities, pref-erably with connections to industrial users. Hotwater systems are preferred for commercial/resi-dential space and water heating because thermalextraction from steam turbine cogenerators (themost common type used in district heating sys-tems) should be done at relatively low tempera-tures to reduce losses in electric generatingcapacity (see discussion of steam turbine efficien-cy, above) and heat losses during transmissionand distribution.

The potential contribution of cogeneration dis-trict heating could be significant, but its actual

CHAPTER 4

1. American Public Power Association, Cogenerationand Small Power Production, Guidelines (Wash-ington, D. C.: American Public Power Association,November 1980).

2. Arthur D. Little, Inc., Distributed Energy Systems:A Review of Related Technologies (Washington,D. C.: U.S. Department of Energy, DOE/PE03871-01, November 1979).

3. Bawn, William E., Jr., and Guerrero, J. V., UtilityConcerns About Interconnected Small Energy Sys-tems, Technical Memorandum (Golden, Colo.:Rocky Flats Wind Systems Program, Rockwell in-ternational Corp., November 1980).

4. Blenkle, Gerard L., Consolidated Edison Co. ofNew York, testimony before New York State Pub-lic Service Commission, case No. 27574.

5. Bos, Peter G., and Williams, James H. “Cogen-eration’s Future in the Chemical Process Industries(CPI),” Chemical Engineering, Feb. 26, 1979, pp.104-110.

6. Bullard, Clark, University of Illinois, private com-munication to OTA, October and November1981.

7. California Energy Commission, CommercialStatus: Electrical Generation and Nongeneration

use will be strongly influenced by a variety oftechnical, institutional, and economic factors. Itsfeasibility is extremely site- and region-specific.Such factors as climate, energy density, fuel type,fuel availability, present and future fuel cost, ageand type of heating equipment in existing build-ings, and type of existing electric generatingcapacity can influence the viability of districtheating. In addition, analyses of district heatingsystems are extremely sensitive to interest rates,tax provisions, utility rate structures, environmen-tal regulations, local building and electrical codes,and labor regulations. Promotion of district heat-ing may require streamlining of permit proce-dures, additional tax credits, low cost loans, reso-lution of conflicts with environmental regulations,and favorable treatment with respect to fuel allo-cations and curtailments.

8.

9.

10.

11.

12.

Technologies (Sacramento, Calif.: CaliforniaEnergy Commission, P102-8O-OO4, April 1980).California Public Utilities Commission, “Standardsfor Operating Reliability,” ch. 14 in Final StaffReport on Cogeneration and Small Power Produc-tion Pricing Standards, Order Instituting Rulemak-ing No. 2 (San Francisco: California Public UtilitiesCommission, January 1981).Cantus, H. Hollister, United Technologies Corp.,personal communication to OTA, Dec. 2, 1980.Chalmers, Steve, “Solar Rankine Cooling andCogeneration Installations and Solar PhotovoltaicCogeneration System,” paper presented at Amer-ican Public Power Association Engineering andOperations Workshop in New Orleans, La., Mar.19, 1981,Cole, Roger L., et al., Design and InstallationManual for Thermal Energy Storage (Argonne, Ill.:Argonne National Laboratory, ANL-79-15, 2d cd.,January 1980).Cummings, A. B., and Morris, J. A., Technical Sup-plement to the American Public Power Associa-tion Report on Cogeneration and Small Power Pro-duction (Phoenix, Ariz.: Salt River Project, March1981 ).


13. Curtice, David, et al., Study of Dispersed SmallWind Systems /interconnected With a Utility Dis-tribution System, Interim Report (Palo Alto, Calif.:Systems Control, Inc., RFP-3093/94445/3533/80/7UC-60, March 1980).

14. Curtice, David, and Patton, James, Operation ofSmall Wind Turbines on a Distribution System,Final Report (Palo Alto, Calif.: Systems Control,Inc., RFP-31 77-2 UC-60, March 1981).

15. Dawson, Douglas, Southern California Edison Co.,private communication to OTA, November 1981.

16. Decision Focus, Inc., Integrated Analysis of LoadShapes and Energy Storage (Palo Alto, Cal if.: Elec-tric Power Research Institute, EPRI EA-970, March1979).

17. DOW Chemical Co., et al., Energy Industrial Cen-ter Study (Washington, D. C.: National ScienceFoundation, June, 1975).

18. Edison Electric Institute, Cogeneration—Conceptsand Systems (Washington, D. C.: Edison ElectricInstitute, 07-80-06, 1980).

19. “Electric Power Generation,” McGraw-Hi// Year-book of Science and Technology (New York:McGraw-Hill Book Co., 1980).

20. Electric Power Research Institute and Jet Propul-sion Laboratory, Interim Working Guidelines and

21.

22.

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24.

25.

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27.

Discussion Concerning the Interface of Small Dis-persed Photovoltaic Power Producers With Elec-tric Utility Systems (Palo Alto, Calif.: Electric PowerResearch Institute and Jet Propulsion Laboratory,draft, August 1981).Fagenbaum, Joel, “Cogeneration: An EnergySaver,” IEEE Spectrum, August 1980, pp. 30-34.Geller, Howard S., The /interconnection of Cogen-erators and Small Power Producers to a Utility Sys-tem (Washington, D. C.: Office of the People’sCounsel, February 1982).General Electric Co., Cogeneration TechnologyAlternatives Study (CTAS)– Volumes I-VI (Cleve-land, Ohio: National Aeronautics and Space Ad-ministration, Lewis Research Center, and Wash-ington, D. C.: U.S. Department of Energy, DOE/NASA/0031-80/l-6, May 1980).Griffin, Clayton, Georgia Power Corp., privatecommunication to OTA, September 1981.Hassan, M., and Klein, J., Distributed PhotovoltaicSystems: Utility Interface Issues and Their PresentStatus (Washington, D. C.: U.S. Department ofEnergy, DOE/ET-20356-3, September 1981).ICF, Inc., A Technical and Economic Evaluationof Dispersed Electric Generation Technologies,contractor report to OTA, October 1980.Institute of Gas Technology, “Phosphoric AcidFuel Cells,” ch. 3 in Handbook of Fuel Cc// Per-

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45

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Production Facility Effects on the Electric PowerSystem,” paper presented at Federal Energy Regu-latory Commission conference on Cogenerationand Small Power Production Rules, June 1980.Ross, Marc H., and Williams, Robert H., “Industri-al Cogeneration: Making Electricity With Half theFuel,” ch. 10 in Our Energy: Regaining Control(New York: McGraw-Hill Book Co., 1981).Salt River Project, Management Proposal Regard-ing Small Power Production and CogenerationFacilities (Phoenix, Ariz.: Salt River Project, De-cember 1980).Solar Turbines, International., Alternate Fuels forGas Turbines (San Diego: Solar Turbines Interna-tional, 79 177A, 1979).Solar Turbines International, TurbomachinerySystems for Low Heating Value Gas Fuels (SanDiego: Solar Turbines International, 80197, 1980).

49. Southern California Edison Co., Guidelines for

50

51

Operating, Metering, Protective Relaying for Co-generators and Small Power Producers (Rose-mead, Cal if.: Southern California Edison Co., June1981 ).Stambler, Irwin, “New Breed of Combined CyclePlants—4 to 11 Megawatts,” Gas Turbine World,JULY 1980.Streb, Alan J., “Cogeneration-What's Ahead?”Energy Engineering, -April/May 1980, pp. 11-23.

52, Theodore Barry & Associates, Guidelines To Assist

53

Rural Electric ‘Cooperatives Fulfill the Require-ments of Sections 201 and210 of PURPA for Co-generation and Small Power Production (Wash-ington, D. C.: National Rural Electric CooperativeAssociation, March 1981).Thermo Electron Corp., Analysis of CogenerationSystems Applicable to the State of New jersey(Waltham, Mass.: Thermo Electron Corp., TE5486-103-80, December 1979).

54,

55.

56.

57.

58.

59.

60.

61.

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64.

Thermo Electron Corp., Venture Analysis caseStudy–Steam Rankine Recovery Cycle ProducingElectric Power From Waste Heat (Waltham, Mass.:Thermo Electron Corp., TE4231 -117-78, Decem-ber 1978).United Technologies Corp., Cogenerat ionTechnology Alternative Study (CTAS)– Volumes/-V/ (Cleveland, Ohio: National Aeronautics andSpace Administration, Lewis Research Center, andWashington, D. C.: U.S. Department of Energy,DOE/NASA/0030-80/l-6, January 1980),U.S. Bureau of the Census, Statistic/ Abstract ofthe United States 1981 (Washington, D. C.: U.S.Government Printing Office, 1981).Whittaker, George, Russell Electric, private com-munication to OTA, September 1981.Widmer, Thomas F., Thermo Electron Corp.,private communication to OTA, September 1981.Wilkinson, Bruce W., and Barnes, Richard W.,(eds.), Cogeneration of Electricity and Useful Heat(Boca Raton, Fla.: CRC Press, Inc., 1980).Williams, Robert H., “Industrial Cogeneration, ”3 Annual Review of Energy 313-356 (Palo Alto,Calif.: Annual Reviews, Inc., 1978).Williams, Robert H., Princeton University, privatecommunication to OTA, October 1981.Williams, Robert H., Princeton University, “Bio-mass Cogeneration as a Major Option in theSwedish Context,” draft report, October 1982.Wilraker, V. F., et al., Photovoltaic Utility/Cus-tomer Interface Study (Albuquerque, N. Mex.:Sandia National Laboratory, SAND-80-7061, De-cember 1980),Zastrow, Orville, Report on Study of ProblemsAssociated With Interconnection of Wind Gener-ators With Rural Electric Distribution Lines (Wash-ington, D. C.: National Rural Electric CooperativeAssociation, 1980).

Chapter 5

Industrial, Commercial, andRural Cogeneration Opportunities

Page

Industrial Cogeneration . . . . . . . . . . . . . . . . . . . 171Industrial Cogeneration Technologies and

Applications . . . . . . . . . . . . . . . . . . . . . . . . 171Potential for Industrial Cogeneration . . . . . . 178Market Penetration Estimates . . . . . . . . . . . . 184

Commercial Cogeneration . . . . . . . . . . . . . . . . 189Previous Studies of Commercial

Cogeneration. . . . . . . . . . . . . . . . . . . . . . . . 189Critical Assumptions and Limits of the

DELTA Model . . . . . . . . . . . . . . . . . . . . . . . 191Commercial Cogeneration Opportunities . . . 198

Rural Cogeneration . . . . . . . . . . . . . . . . . . . . . . 210Potential Applications . . . . . . . . . . . . . . . . . . 211Fuel Savings . . . . . . . . . . . . . . . . . . . . . . . . . . 213Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 215

Chapter 5 References . . . . . . . . . . . . . . . . . . . . 216

Tables

Table No. Page

31.Fuel Utilization Characteristics of

3233

3435

Cogeneration Systems . . . . . . . . . . . . . . . . . 172Cogeneration Projects by Region . . . . . . . . 179Existing Industrial Cogeneration bySIC Code . . . . . . . . . . . . . . . . . . . . . . . . . . . 179Sample Industrial Electric Rates by State.. 182Early Estimates of the Potential forindustrial Cogeneration. . . . . . . . . . . . . . . . 185

36. Range of Utility Buyback Rates Analyzedby RPA. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 187

37. Typical Days Used in the DELTA Model . . 19238. Fuel Prices . . . . . . . . . . . . . . . . . . . . . . . . . . 19639. Technology Characteristics . . . . . . . . . . . . . 19740. Sample Utility Configurations . . . . . . . . . . . 19841. Description of Scenarios Used . . . . . . . . . . 19942. New Capacity installed for Coal-Limited

Scenarios . . . . . . . . . . . . . . . . . . . . . . . . . . . 20143. Capacity Factors for Baseload and

Cogeneration Plants . . . . . . . . . . . . . . . . . . 202

44,

45.

46.

47.

Page

Base-Case Standard Scenario Fuel Use,by Generation Type and Year . . . . . . . . . . 206Comparison of Fuel Use for Coal-LimitedScenarios . . . . . . . . . . . . . . . . . . . . . . . . . . . 209Distribution of Waste Heat From aSupercharged Diesel Engine . . . . . . . . . . . . 210Model Community Gasification/DieselElectric Generation Energy CostEstimate . . . . . . . . . . . . . . . . . . . . . . . . . . . . 214

Figures

Figure No. Page

45.

46.

47.

48.

49.

50.

51.

52.

53.54.55.56.

57.58.

59.

60.

Potlatch Corp. –Schematic of theCogeneration System . . . . . . . . . . . . . . . . . 173Celanese Chemical Co./SouthwesternPublic Service Co.—Schematic of theCogeneration System . . . . . . . . . . . . . . . . . 173Gulf States Utility Co.-Schematic of theCogeneration System . . . . . . . . . . . . . . . . . 174Union Carbide Corp.—Schematic of theCogeneration System . . . . . . . . . . . . . . . . . 174Holly Sugar Corp. –Schematic of theCogeneration System . . . . . . . . . . . . . . . . . 175Riverside Cement Co.–Schematic of theCogeneration System . . . . . . . . . . . . . . . . . 175Cogeneration Potential at CaliforniaState Facilities . . . . . . . . . . . . . . . . . . . . . . . 191Comparison of EIectric Demand forThree Types of Days.... . . . . . . . . . . . . . . 1931990 Heating Demands for Scenario 1 .. 1941990 Cooling Demands . . . . . . . . . . . . . . . 195Electrical Capacity Additions 1990-2000 . . 200Thermal Supply and Demand for WinterPeak Day . . . . . . . . . . . . . . . . . . . . . . . . . . . 203Electricity Supply for Winter Peak Day . . . 203Fuel Used in 1990 and 2000 forCoal-Limited Scenarios . . . . . . . . . . . . . . . . 208EthanoI Cogeneration With Diesel EngineWaste Heat Recovery . . . . . . . . . . . . . . . . . 212Anaerobic Digester Svstem. . . . . . . . . . . . . 215

“ ,

Chapter 5

Industrial, Commercial, andRural Cogeneration Opportunities

INDUSTRIAL COGENERATION

Large amounts of fuel are used to produce ther-mal energy for U.S. industries and this energyrepresents a potential for fuel savings throughcogeneration. Industrial cogeneration is firmlyestablished as an energy supply option in theUnited States, with a total installed capacity ofabout 9,000 to 15,000 megawatts (MW), or about3 percent of the total U.S. electricity generatingcapacity (1 2). Industrial cogeneration currentlysaves at least 0.5 Quad of fuel each year.

The onsite production of electricity in industry(not necessarily cogeneration) has declinedsteadily throughout the 20th century. This declinewas the result of a number of economic and in-stitutional considerations that made it more ad-vantageous for industries to buy electricity fromutilities than to generate it themselves. At thesame time, however, the technical potential forcogeneration (the number of industrial siteswhere the demand for thermal energy is sufficientto justify a cogeneration system) has been grow-ing, and today may be as high as 200 gigawatts(GW) of capacity (equal to about 33 percent oftotal U.S. electricity generating capacity; seebelow). But, just as economic and institutionalissues were responsible for the decline of onsitegeneration during the 20th century, these issues,rather than technical constraints, mean that themarket potential (the number of sites at whichinvestment in cogeneration will be sufficiently at-tractive) is much lower than the technical poten-tial–perhaps 40 to 100 GW by 2000.

Industrial cogeneration systems may use anyof the possible technology and fuel combinationsdescribed in chapter 4. These systems generallyare smaller than baseload utility powerplants, butstill vary considerably in size. Examples of pro-posed cogeneration units now under considera-tion illustrate this range: A 125-kW wood-firedunit being built in Pennsylvania to burn the scrapsfrom a furniture company plant; a 5.8-MW com-bustion turbine system being built to serve a box-

board company on the west coast; a 60-MW bio-mass- and coal-fired system proposed for a puIpand paper mill in northern Mississippi; and a140-MW coal-burning unit proposed by a majoroil company to serve a complex of refineries andchemical plants on the gulf coast of Louisiana.This section will describe the industrial cogenera-tion technologies and applications, discuss thecriteria for implementing an industrial cogenera-tion system, and review estimates of the marketpotential for industrial cogeneration.

Industrial Cogeneration Technologiesand Applications

The cogeneration systems in place today pri-marily use steam turbine technology in a toppingcycle. Steam is raised in a high-pressure boilerand then piped through a turbine to generateelectricity before heat is extracted for the in-dustrial process (see ch. 4). The thermal outputof the turbine generally ranges from less than 50to over 1,000 psig, which is appropriate for manytypes of industrial steam processes. The steam tur-bine topping cycle is extremely versatile, in thatit can use any fuel that can be burned in a boiler;oil, gas, coal, and biomass are routinely used. Butwhen the steam turbine technology is used forcogeneration, only 5 to 15 percent of the fuel isturned into electricity. Thus, these cogeneratorsusually are sized to fit an industry’s steam load,and they produce less electricity than other co-generation technologies.

The measure of the ability of cogeneration tech-nologies to produce electricity is the ratio of elec-trical output (measured in kWh) to steam output(measured in million Btu), or the electricity-to-steam (E/S) ratio. A steam turbine cogenerator willproduce 30 to 75 kWh/MMBtu, For some indus-tries, this is only enough electricity to satisfy on-site needs, but, in others a modest amount maybe available for export offsite as well. Higher E/S

171


ratio technologies that have been proven in in-dustrial uses are combustion turbines, diesels,and combined cycles. The combustion turbinecan generate two to seven times as much elec-tricity with a given quantity of fuel as the steamturbine, and the diesel five to twenty times asmuch. Combined-cycle systems perform in arange between combustion turbines and diesels.Typical E/S ratios for these technologies are givenin table 31 (see also ch. 4). Shifts in future co-generation projects to these higher E/S systemswould increase the amount of electricity thatcould be provided to the grid, and would savemore fuel than with the use of lower E/S tech-nologies.

Fuel savings is one important advantage ofcogeneration. All of the proven cogenerationtechnologies use about 50 to 60 percent as muchfuel to generate a kilowatt-hour of electricity(beyond the fuel otherwise needed to produceprocess steam) as is required by a conventionalsteam generating station. Whereas a central sta-tion powerplant requires 10,000 to 11,000 Btu/kwh, the proven cogeneration systems requireonly about 4,500 to 7,500 Btu/kWh (see table 31).There is no particular fuel savings in the steamproduction part of the cogeneration process; rais-ing steam by cogeneration usually is allocated thesame amount of fuel as required by a conven-tional boiler. Therefore, overall fuel savings areroughly proportional to the total electricity pro-duction achievable with each technology.

However, while the higher E/S technologiesproduce more electricity and save more fuel thanthe standard steam turbines, their fuel versatili-ty is more limited. Higher E/S systems can only

Table 31.—Fuel Utilization Characteristics ofCogeneration Systems

Heat ratea Second law E/S ratio(Btu/kWh) efflciencyb (kWh/MhfBtu)

Steam turbine . . . . . . . . . 4,500-6,0(N) 0.40 (0.32) 30-75Combustion turbine . . . . 5,500-6,5fxl 0.47 (0.34) 140-225Combined cycle . . . . . . . 5,000-6,000 0.49 (0.35) 175-320Diesel . . . . . . . . . . . . . . . . 6,000-7,500 0.46 (0.35) 350-700

The fuel required to generate elactrklty, In excess of that required for processsteam production alone, assuming a boiler efficiency of 88 percent for processsteam production.

%he second law efficiency for separate process steam and central station elec-tricity generation Is shown In parentheses (see ch. 4).


use liquid or gaseous fuels of uniform composi-tion and high purity, or turbine parts or engineparts may be corroded or eroded. Although thereis some experimental work with coal and coal-derived fuels for use in high E/S cogenerationtechnologies, the only proven cogeneration tech-nology using coal today is the steam turbine.Some of the technologies under developmentthat could use coal in industrial applications arediscussed below.

Systems Design

The characteristics of presently employed sys-tems vary enormously. Rather than try to gener-alize the system configurations that might be usedin different industries, six examples of successfullyoperating cogeneration plants are described brief-ly below.

A pulp and paper industry cogenerationsystem at the Potlatch Corp. plant in Lewiston,Idaho, burns various woodwastes and the “blackliquor” from the first stage of the pulping opera-tion, plus natural gas. This plant began to cogen-erate in 1951, when the company installed a10-MW steam turbine, which was supplementedby another 10 MW of capacity in 1971. The co-generation system produces steam at both 170and 70 psig, plus 23 percent of the plant’s elec-trical needs. The system generates less than’ theelectric load needed onsite because of the ex-tremely low retail electricity rates and purchasepower rates in the region (see tables 19 and 34),but will be upgraded in the 1980’s with an addi-tional 30 MW of capacity, at a cost of $89 million(1980 dollars), to supply almost all the onsite de-mand. The system is extremely reliable, operating24 hours per day 360 days per year, giving a sys-tem availability of over 90 percent. Electrical ef-ficiency (fraction of fuel Btu converted to elec-tricity) is 64 percent, and the maintenance costis 3 to 4 milIs/kWh (29). A schematic of the co-generation system is shown in figure 45.

An example of a chemicai industry cogenera-tion system, that is sized to export electricity tothe grid, is the system installed by the CelaneseChemical Co. at its Pampa, Tex., plant in 1979.The system burns pulverized low-sulfur Wyomingcoal in two large high-pressure boilers, each

Ch. 5—industrial, Commercial, and Rural Cogeneration Opportunities ● 173

Figure 46.— Celanese Chemical Co./SouthwesternPublic Service Co.—Schematic of the

Cogeneration System

To feed water heating

Pulverized*

— *coal

SOURCE: Synergic Resources Corp., /rrdustr/a/ Cogenerator Case Stud/es(Palo Alto, Cahf : Electric Power Research Institute, EPRI EM.1531,1980).

refinery, as well as a chemical manufacturer thatproduces ethyl lead for increasing gasoline oc-tane. The system (Louisiana Station #l at BatonRouge, La.) was built by the Gulf States UtilityCo. in 193o and upgraded several times over thedecades to a present capacity of 129 MW of elec-tricity and 3.6 million lb/hr of steam. It has nowbeen- cogenerating successfully for almost half acentury with only one unscheduled outage (dur-ing an electrical storm in 1960) (29).

This cogeneration plant uses natural gas andrefinery waste gas as fuel for its boilers, whichproduce both 600 and 135 psig steam for sale bythe company to its industrial customers. The over-all efficiency of the system is 73 percent, and theindustrial customers consider the system extreme-ly reliable. Exxon, the refinery owner, has a 7-yearcontract for steam supply. The utility sells boththe electricity and steam from the station (saleof the steam is unregulated), and the industrialusers provide most of the fuel and pay the oper-ating costs (29). Figure 47 presents a diagram ofthe Gulf States system.

Due to natural gas price increases, LouisianaStation #1 may be phased out soon. Until 1979,Gulf States had long-term gas contracts for $0.30/MMBtu, and when these contracts expired theprice rose to $2.60/MMBtu. At the same time thattheir fuel prices were increasing, energy conser-vation by their industrial customers substantial-ly reduced the demand for steam, which now


Figure 47.—Gulf States Utility Co.—Schematic ofthe Cogeneration System

Natural gas, refinery gas

SOURCE: Synergic Resources Corp., Indusfrial Cogeneration Case Studies(Palo Alto, Callf Electrlc Power Research Institute, EPRI EM-1531,1980)

stands at one-half or two-thirds of the level thatprevailed 2 to 3 years ago, according to GulfStates (29).

Gulf States reports that it is not in a positionto raise the capital for a new system easily (themost recently added increment of capacity is now27 years old), so the present system may beretired and a new one built by Exxon. Exxon isplanning a 150- to 180-MW coal-fired cogener-ator nearby. The proposed new cogenerationplant would produce 6 million to 8 million lb/hrof process steam and potentially could supplymore industrial customers than the existingsystem.

Another cogeneration system associated witha chemical company in the southern part of thecountry is the Texas City, Tex., plant of the UnionCarbide Corp. The Texas City cogeneration sys-tem is owned by the chemical company, whichproduces a wide variety of products from alcoholsto plastics, and uses natural gas for fuel. Thesystem is a complex network of both steam andcombustion turbines that was started in 1941. Itproduces up to 70 MW of electricity, but histor-ically has not sold any for use offsite due toregulatory restrictions, The peak demand for theplant is 40 MW. Union Carbide reports that it issatisfied with its return on investment, but thatrising natural gas prices make future cogenera-tion questionable, especially with combustion

turbines, Union Carbide is now concentrating onconservation through heat recovery applicationsand waste heat utilization, rather than cogenera-tion (29). This system is sketched in figure 48.

The operating patterns of food plants are con-siderably different from those of chemical or pulpplants. An example of a food plant that only op-erates 4 months per year is the Holly Sugar Corp.plant at Brawley, Cal if. The plant’s 7.5-MW steamturbine system provides all the steam and elec-tricity needed onsite. The company reports thatit installed the cogeneration system for economicsand reliability—there had been interruptions inpower when it drew electricity from the localgrid. Now the system is isolated from the grid andoperates to provide the electrical load requiredfor the plant. Holly Sugar reports that reliabilityis very high (99,9 percent) for the 120 days peryear that the plant operates. The reported annualcapacity factor is expectedly low for such a plantschedule—25 percent. This may be too low foreconomic cogeneration under most circum-stances, but the alternative is charges for utility-generated power during the summer months,which would be seasonably high—a factor thatimproves cogeneration economics (29). A sche-matic for the system is shown in figure 49.

Figure 48.—Union Carbide Corp.—Schematicof the Cogeneration System

Natural gas

1 J1,000 psig/600°F

oI

u I

SOURCE: Synergic Resources Corp., Industrial Cogeneration Case Studies(Palo Alto, Calif,: Electric Power Research Institute, EPRI EM.1531,1980)

Ch. 5—industrial, Commercial, and Rural Cogeneration Opportunities 175

Figure 49.—Holly Sugar Corp.—Schematic of theCogeneration System

Boilers

An example of a bottoming-cycle cogeneratoris the system at the Riverside Cement Co. plantat Oro Grande, Calif. The plant has five wasteheat boilers to recover energy from its cementkiln exhaust gases. These produce 100,000 lb/hrof steam for cogeneration via steam turbines.Because the production of steam in the wasteheat boilers varies with the production rate of thecement kilns, the system also has two oil-firedboilers for use when the output of the waste heatboilers diminishes. At present, oil provides 21 per-cent of the energy for cogeneration. In order toreduce its oil consumption (the cement kilns op-erate on coal and natural gas), the company plansto add two additional waste heat boilers. Thecompany reports that the system (see fig. 50) nor-mally operates 24 hours per day, 365 days peryear, and that there have been only two briefunscheduled outages since 1954. Because 80 per-cent of the energy that is used for cogenerationwould otherwise be wasted, system efficiency cal-culations are not significant in this situation (seediscussion of bottoming cycles in ch. 4). The co-generation capacity available to the local utilityis 15 MW (29).

Advanced Systems

Most of the existing cogeneration systems de-scribed above are limited to the use of cleanpremium fuels such as natural gas and distillatefuel oil, which are much more expensive thanalternative solid fuels, and which may be in short

Figure 50.— Riverside Cement Co.—Schematicof the Cogeneration System

supply in the coming decades. The only proventechnology appropriate for a wide range of in-dustrial sites that can use solid fuels (e.g., coal,biomass, urban refuse) is the steam turbine top-ping cycle, which has limited electrical produc-tion for a given amount of steam. However, anumber of technologies now under developmentoffer more fuel flexibility for cogeneration thanthe steam topping turbine with a conventionalboiler.

The primary problem with these emerging tech-nologies is the difficulty in handling and storingthe solid fuel and disposing of its ash. Comparedwith the ease of handling traditional liquid andgaseous fuels, solid fuels—particularly coal—arecost intensive and complex to use. Small, medi-um-sized, and perhaps even large industrialplants would prefer to avoid the investment andoperating costs associated with burning coal.These factors are likely to limit conventional coalcogeneration systems to units 30 to 40 MW orlarger, according to sources surveyed by OTA.

CENTRAL GASIFIER, REMOTEGENERATION SYSTEMS

An alternate system now under intensive development would eliminate the need for in-dustrial firms to handle coal on their plant sites.Utilizing a central gasifier to serve a region, it


would be possible to provide medium-Btu gas- premium synthetic natural gas. Onsite, the in-eous fuel to 50 to 100 industrial plants. Medium- dustrial plants associated with such centralBtu gas has an energy content between that of gasifiers would only have relatively compactlow-Btu power gas and synthetic natural gas (see cogeneration systems that would entail no morech. 4). It can be transported economically over accessory buildings and equipment than presenta reasonable distance, and is cheaper than oil or gas fueled cogeneration systems. A central

Photo credit: Department of Energy, Schneider

A prototype downdraft, airblown gasifier using wood chips as the fuel


gasifier that produced medium-Btu gas (about 300Btu per standard cubic foot) could serve a regionup to about 100 miles in radius—the distance overwhich medium-Btu gas can be transported eco-nomically.

An example of the central gasifier/remote gen-eration concept is the system proposed for cen-tral and southern Arkansas to serve as many as35 industrial sites from a central coal gasificationfacility located at the Arkansas Power& Light Co.(AP&L) White Bluff coal-fired generating station.The initial central gasifier module would burnpetroleum coke or Illinois #6 coal to produce ap-proximately 120 billion Btu of gas per day. Theas-spent cost of this module, for a design and con-struction time of 76 months, and with commer-cial operation beginning in mid-1988, is estimatedat $1.8 billion. This initial module could supplyfuel for combined-cycle cogenerators that wouldproduce 400 to 475 MW of electricity and 1.6million to 2 million lb/hr of steam, depending onthe conditions at each industrial site. Four centralgasifier modules of this size–producing 460billion to 480 billion Btu per day of medium-Btugas–would be required to supply the 35 indus-trial steam users identified by AP&L as the primarycogeneration candidates in its service area. Withthe central gasifier concept, these 35 cogener-ators would use 6 million lb/hr of process steamand produce up to 1,700 MW of cogeneratedelectricity. The synthetic gas would be piped asfar as 100 miles to user sites with combined-cyclecogeneration systems (14).

The medium-Btu gas for the system would beproduced in a gasifier fed by streams of air oroxygen and coal/water slurry, both pumped intothe system at controlled rates under pressure.Both streams enter a reactor vessel where par-tial oxidation of the fuel occurs, The product gasleaves the vessel at very high temperature, thenpasses through a series of heat exchangers thatcool the gas to 400° F. Ash from the burning fuelis separated at the exit of the gasifier and directedinto a water-quench that produces a glassy wasteproduct that can be used as an asphalt filler.Because the gasifier operates above the meltingtemperature of the ash, the quenched ash is inertand the plant does not require scrubbers.

A 150-ton-per-day Texaco entrained-processgasifier (similar to that proposed by AP&L) hasbeen operating for more than 2 years, produc-ing synthesis gas for the Ruhr Chimie chemicalplant near Oberhausen, Germany. In addition,the Tennessee Valley Authority is building a200-ton-per-day Texaco gasifier at Muscle Shoals,Ala., and the Electric Power Research Institute–inconjunction with Southern California EdisonCo.–is in the final stages of planning a 1,OOO-ton-per-day gasifier (the Coolwater project) that willbe used to produce 100 MW of power. None ofthese projects is intended to cogenerate, but thetechnology could be used to do so (4).

FLUIDIZED BED SYSTEMS

Another advanced coal technology is thefluidized bed combustor, which can be used toburn coal or other solid fuels, including urbanrefuse, in a more compact system than a conven-tional coal boiler. The fluidized bed combustorcan burn coal of any quality, including that witha high ash content, and it can operate at a tem-perature (1 ,500° F) only about half as high as aconventional pulverized coal boiler. At theselower temperatures, the sulfur dioxide formedduring combustion can be removed easily byadding limestone to the bed, and the combus-tion gases may be suitable for driving a combus-tion turbine with minimal erosion damage, be-cause the coal ash is softer at lower temperatures.Two types of fluidized beds currently are beingdeveloped–those that work at atmospheric pres-sure and those that work at considerably higherpressures (see ch. 4).

At present, fluidized bed systems are used tofire boilers, and thus can be readily used forcogeneration with conventional steam turbines.Fluidized bed systems incorporating combustionturbines, which have higher E/S ratios, are in anearlier stage of development and are just ap-proaching commercial status. But, combustionturbines require a high-temperature gas at apressure considerably above atmospheric pres-sure, so the output of an atmospheric fluidizedbed combustor cannot be used as the input tothe turbine. Instead, the fluidized bed output canbe used in conjunction with air heater tubes for


heat recovery in the fluidized bed, and the air,delivered from the turbine compressor to beheated in these tubes, can be used to indirectlyfire a combustion turbine (either open or closedcycle).

The Curtiss-Wright Corp. in Woodbridge,N. J., is offering a prototype indirectly fired systemon a semicommercial basis, sized to produce 2to 10 MW of electricity and 25,000 to 150,000lb/hr of steam. A spokesman for the companysays that 20 MW is probably the maximum feasi-ble size for such a system using an atmosphericbed combustor, the bed size being the limitingfactor. Pressurized bed systems could be larger,however. The crucial factor in this technology,according to Curtiss-Wright, is the choice of alloyfor the heater tubes. These tubes pass throughthe bed itself, operate at temperatures up to2,000° F, and can be subject to corrosion, ox-idation, and sulfurization. After “working thebugs out” of the first few demonstration units,Curtiss-Wright plans to offer the system on a com-mercial basis (4).

Pressurized fluidized bed combustors have out-put gases that exit at high enough pressures thatthese gases may be used directly to drive a tur-bine. These systems are also just approachingcommercial status. The German Babcock Co. isplanning a demonstration of a medium-sizedsystem of this type in Great Britain. The majordifficulty in the successful demonstration of suchsystems is perfecting the technology for cleaningthe fluidized bed output gas so that it does noterode the turbine blades and shorten the lifetimeof the system (4).

Shell Oil Co. recently decided to build a coal-fired fluidized bed cogeneration system near Rot-terdam, Netherlands, a relatively small unit thatwill produce 110,000 lb/hr of steam. A con-siderably larger fluidized bed project is beingundertaken by the American Electric Power Co.(AEP) at Brilliant, Ohio. The AEP system, beingbuilt in conjunction with Babcock& Wilcox, Ltd.of Great Britain and Stal-Laval Turbin AB ofSweden, uses a pressurized fluidized bed tooperate a combustion turbine topping cycle inconjunction with an existing steam turbine. Thecapacity of the combined system (which will not

cogenerate in this instance but which would beappropriate for cogeneration applications) will be170 MW (4).

Other technologies also are receiving attentionfor use with coal. The Thermo Electron Corp. hastested the performance of a two-cycle marinediesel engine fired with a coal/water slurry. Theengine, which is a low-speed tanker motor (seech. 4), could achieve in principle 40 percent ef-ficiency in generating electricity. Coal also canbe used to fuel externally fired engines such asthe Stirling-cycle engine. N.V. Philips, of Ein-hoven, Netherlands, has initiated work in apply-ing fluidized bed coal systems to use with Stir-ling engines.

Potential for Industrial Cogeneration

Cogeneration’s market potential depends ona wide range of technical, economic, and institu-tional considerations, including a plant’s steamdemand and electric needs, the relative cost ofcogenerated power, the fuel used and its cost,tax treatment, rates for utility purchases of co-generated electricity, and perceived risks such asregulatory uncertainty. The criteria for investmentin an industrial cogeneration system is discussedbelow, including a description of the industrialsectors where cogeneration is likely to be attrac-tive, and a brief review of the industrial cogenera-tion projections in the literature.

Appropriate Industries

A summary of cogeneration projects by regionin the United States is given in table 32. The 371projects in this table are those that are positivelyidentified as cogeneration systems in a recent De-partment of Energy (DOE) survey (12). A break-down by industry type is given in table 33. Anadditional 98 projects-representing at least 3,300MW of capacity–have been proposed, are underconstruction, or are being added to existingcogeneration units.

The pulp and paper industry has, for sometime, been a leader in cogeneration due to thelarge amounts of burnable process wastes thatcan supply energy needed for plant requirements.Integrated pulp and paper plants find cogenera-


Table 32—Cogeneration Projects by Region

Capacityb

Regiona Number of plants (MW)

New York , . . . . . . . . . . . . . . 27 913New York/New Jersey . . . . 23 498Mid-Atlantic . . . . . . . . . . . . . 39 1,512South Atlantic . . . . . . . . . . . 62 2,200Midwest . . . . . . . . . . . . . . . . 89 3,176Southwest . . . . . . . . . . . . . . 57 4,812Central . . . . . . . . . . . . . . . . . 14 259North Central. . . . . . . . . . . . 14 413West . . . . . . . . . . . . . . . . . . . 25 629Northwest . . . . . . . . . . . . . . 21 445

Total . . . . . . . . . . . . . . . . . 371 14,858aStandard EIA/DOE regions.bTotal may not agree due to rounding.

SOURCE: General Energy Associates, Industrial Cogeneration Potential.’ Target-ing of Opportunltles at the Plant Site (Washington, DC.: U.S. Depart-ment of Energy, 1982).

tion particularly attractive. These plants disposeof woodwastes (e. g., bark, scraps, forestry resi-dues unsuitable for pulp) and processing fluids(“black liquor”), and recover process chemicalsin furnaces that can supply about half of a plant’senergy needs. For at least two decades, the in-dustry has considered power production an in-tegral part of the manufacturing process, and newpulp and paper plants are likely candidates forcogeneration.

The chemical industry is another major steam-using industry that has great cogeneration poten-tial. It uses about as much steam per year as thepulp and paper industry (1.4 Quads in 1976) andhistorically has ranked third in installed cogenera-tion capacity. The steel industry is also a majorcogenerator, because the off-gases from theopen-hearth steel making process provide a readysource of fuel, which is burned in boilers to makesteam for blast furnace air compressors and formiscellaneous uses in the rest of the plant. Al-though the steel industry has been a major co-generator in the past, most analysts project thatit will not build more integrated stand-aloneplants. Instead it is expected to build minimillsthat run with electric arcs and have little or nopotential for cogeneration unless a market canbe found for the thermal energy. Thus, new steelmills probably have considerably less cogenera-tion potential than the chemical industry. How-ever, on the gulf coast substantial cogenerationcapacity has been proposed for existing primarymetals facilities (34)0

petroleum refining also is an industry that is,in many ways, ideal for cogeneration. Existingrefineries could be upgraded over the next

Table 33.—Existing Industrial Cogeneration by SIC Code

Percent Capacity PercentSIC code Number of total (MW) of total20—Food . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4221 —Tobacco products . . . . . . . . . . . . . . . . . . . . . . .22—Textile mill products. . . . . . . . . . . . . . . . . . . . . 923—Apparel . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 024—Lumber and wood products. . . . . . . . . . . . . . . 1925—Furniture and fixtures. . . . . . . . . . . . . . . . . . . . 126—Paper . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13627—Printing and publishing . . . . . . . . . . . . . . . . . . 128—Chemicals. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6229—Petroleum and coal products . . . . . . . . . . . . . 2430—Rubber, miscellaneous plastic products . . . . 331—Leather . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . —32—Stone, clay, and glass products . . . . . . . . . . . 633—Primary metals. . . . . . . . . . . . . . . . . . . . . . . . . . 3934-Fabricated metal products. . . . . . . . . . . . . . . . 1035—Machinery, except electrical . . . . . . . . . . . . . . 1136—Electric and electronic equipment . . . . . . . . . 337—Transportation equipment . . . . . . . . . . . . . . . . 138—instruments and related products . . . . . . . . . 339—Miscellaneous manufacturing . . . . . . . . . . . . . —

Total. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 371

1 1 . 3 %< 1 . 0

2.4

5.1<1.036.7

<1.016.76.5

<1.0—

1.610.5

2.73.0

< 1.0< 1.0< 1 .0

100.0

39833

224

4792

4,246

3,4381,244

76

1153,589

304134

83345137

14,858

2.7<1.0

1.5

3.2<1 .028.6

<1 .023.1

8.4< 1 .0

—< 1 . 0

24.22.01.01.0

<2.3< 1 .0

100.0SOURCE: General Energy Associates, Industrial Cogeneration Potential: Targeting of Opportunities at the Plant Site (Washington,

DC,: U.S. Department of Energy, 1982).

decade to increase gasoline and diesel fuel out-put and decrease residual oil production. Abyproduct of this upgrading would be the pro-duction of low-Btu gas that might be used i ncogeneration systems. One report estimates thatsuch upgrading could produce 0.5 Quad/yr ofgas, to meet about 40 percent of the refineries’1976 process steam demand and provide 9 GWof electricity generating capacity (34). However,new refineries are not likely to be built in the nearfuture except on the Pacific coast in conjunctionwith enhanced oil recovery in the Kern Countyheavy oilfields.

An industry in which cogeneration and con-servation are in head-to-head competition is thecement industry. It has been identified as a can-didate for bottoming-cycle cogeneration, an ap-plication in which the heat of the kiln exhaust

gas is recovered and used to produce steam forelectricity generation. But because the industryis highly energy intensive, it has improved its ef-ficiency substantially in recent years, reducing thetemperature of its exhaust gases from 9000 to1,000° F to 300° to 400° F. One plant hasreported exhaust temperatures as low as 180° F(28). In plants where conservation measures arethat effective, it probably will not be economicto cogenerate.

Criteria for Implementation

A wide range of considerations must be takeninto account in deciding whether to invest in anindustrial cogeneration system. These includeboth internal and exogenous economic factors,fuel cost and availability, ownership and financ-ing, tax incentives, utility capacity expansion

Ch 5—Industrial, Commercial, and Rural Cogeneration Opportunities 181

Photo credit: Department of Energy

Low-Btu gas suitable for fueling cogeneration systems is a byproduct at many petroleum refining facilities

plans and rates for purchases of cogeneratedpower, and a variety of perceived risks in suchan investment.

ECONOMIC CONSIDERATIONS

For any potential cogenerator, the desirabilityof cogenerating depends on the price of powerfrom the utility plus the cost of producing ther-mal energy, versus the cost of cogenerating. His-torically, industrial and commercial users havepaid different amounts for utility-producedpower. Compared to the case for commercial co-generation (see below), industrial facilities typical-ly have lower electric rates, averaging up to about1.5cents/kWh lower than commercial and residen-tial users (see table 34) (9). Nevertheless, in someregions of the country, rates for utility purchasesof cogenerated electricity have reached 8.3cents/kWh (see table 19), higher than the national aver-age for either commercial or industrial retail elec-tricity rates. These areas are prime targets for ex-panded industrial cogeneration (see discussionsof purchase power rates and simultaneous pur-chase and sale, below).

The current costs of cogeneration for industrialusers often are below the rates for utility pur-chases from industrial customers. A study for theFederal Energy Regulatory Commission (FERC)(28) found that the price of cogenerated electricityranged from 4.4 to 5.6cents/kWh (1979 dollars) forvarious regions of the country, assuring the useof steam topping and gas turbine technologies.Diesel cogeneration was found to cost 7.2 to7.6cents/kWh, assuming small, distillate-fired systemsoperating at a relatively low capacity factor.Larger systems using natural gas and operatingat higher capacity factors should be able to com-pete at the busbar with new coal plants in manyinstances (34). While utility rates for purchasesof cogenerated power vary widely by region (seetable 19), the costs of cogeneration vary only 10to 20 percent among the regions of the country,This is a strong indication that the rates for salesof cogenerated electricity will be important indetermining the economic viability of industrialcogeneration over the next few years. More spe-cifically, external economic factors, rather thantechnical breakthroughs that would reduce theintrinsic costs of cogeneration, are likely to be


Table 34.-Sample Industrial Electric Ratesby State (costs per kWh for industries using 1.5 milllon

kWh per year with a peak demand of 5 MW.

. - . . .—Alabama . . . . . . . .....3.60Alaska . . . . . . . . . . . . . .3 .7Ar izona . . . . . . . . . . . . .4 .4Arkansas . ...........2.9California . ..........5.0Colorado . ...........3.4Connecticut . ........5.2Delaware . ...........5.8District of Columbia ..3.9Florida . .............3.1Georgia . . . . . . . . . . . . .3 .7Hawai i . . . . . . . . . . . . . .5 .7Idaho . . . . . . . . . . . . . . .1 .7I l l inois . . . . . . . . . . . . . .4 .0Indiana. . ............3.6I o w a . . . . . . . . . . . . . . . . 3 . 9Kansas. . . . . . . . . . . . . .3 .9Kentucky . ...........3.0Louisiana . ..........2.9Maine. . . . . . . . . . . . . . .3 .6Maryland . ...........2.7Massachusetts. .. ....5.2Michigan . ...........4.6Minnesota. . .........3.0Mississippi . .........3.9Missour i . . . . . . . . . . . .3 .8

Montana . . . . . . .....1.70Nebraska. . . . . . .. ...2.7Nevada . . . . . . . . . . . .4 .7New Hampshire .. ...4.8New Jersey. . .......4.4New Mexico . .......5.5New York .. ........7.6North Carolina .. ....2.9North Dakota . ......3.5Ohio . . . . . . . . . . . . . . .4 .1Oklahoma . .........2.6Oregon. . ...........1.7Pennsylvania . ......5.1Rhode Island . ......5.3South Carolina .. ....3.6South Dakota . ......3.3Tennessee. . ........3.2Texas . . . . . . . . . . . . . .3 .7Utah . . . . . . . . . . . . . . ,3 .1Vermont. . ..........3.3Virginia . ..........,5.2Washington ., .. ...,1.1West Virginia . .....,3.2Wisconsin .. ........3.5Wyoming . ..........1.5

aRates shown are calculated from typical bills for 455 cities with a totai popula-tion of 76.9 million as of Jan. 1, 1980. The State averages are population-basedaverages. The range among regions in the country is from 1.1 to 7.6 cents/kWh,as of Jan. 1, 1960.

SOURCE: Energy Information Administration, Typical Electric Bills, January 7,1980 (Washington, D. C.: Government Printing Office, December 1960).

the dominant factors governing the rate of co-generation implementation in the 1980’s.

In most parts of the country, the rates for pur-chases of cogenerated electricity do not exceedthe 4.5 to 5.5cents/kWh cogeneration cost quotedabove. However, the avoided cost of many util-ities may be higher than industrial electricity rates.The FERC study cited above found that in many(but not all) regions of the country this was thecase. in regions with high avoided costs, it wouldbe advantageous for industrial firms to sell all theircogenerated power to the utilities and buy backas much power as they need at the industrialwholesale price. The conditions for favorableelection of this option, known as simultaneouspurchase and sale (or arbitrage), are discussedfurther below.

FUEL VERSATILITY

The fuel used for cogeneration varies with thetype of technology installed and with the size of

the installation. The predominant fuels are coal,biomass, natural gas, and oil–usually residual(#6) and middle distillate (#2) oil. Oil and naturalgas are the most versatile fuels because they canbe used in all available cogeneration technologiesfrom the lowest E/S systems (steam topping tur-bines) to the highest (combined cycles anddiesels). However, due to the price and supplyuncertainties of oil and natural gas, over the longterm (10 years and beyond) the most attractivecogeneration investments will use solid fuels. Asdiscussed previously, of the available technol-ogies, only steam turbines presently can use suchfuels, but these systems also have relatively lowfuel savings for a given steam load, and a low E/Sratio. With the advanced technologies describedpreviously, solid fuels could be used more widelythan now possible. Both the medium-Btu gasifierand the fluidized bed systems could be used withcombustion turbines or combined cycles, pro-ducing electric power with a high E/S ratio fromcoal or biomass.

OWNERSHIP AND FINANCING

ownership arrangements may be among theprincipal determinants of the rate of developmentof cogeneration. The issue is whether cogenera-tion systems will be owned by the industry thatuses the thermal energy, whether they will beowned by the utilities that would distribute thecogenerated electricity, or whether a third partywould invest in the cogeneration equipment.Joint ventures and multiparty ventures minglingthese various players also are possible (see ch. 3).

Industrial ownership could be attractive if thesurplus electricity were purchased by a utility atrates that reflect the utility’s full avoided costs.Also ownership could assure the cogenerating in-dustry of reliable power, which can be a strongincentive for particular industries in some regions.However, the capital requirements of a cogenera-tion system are large enough that many poten-tial industrial cogenerators would like to havelong-term (i.e., 20-year) contracts for power salesto the grid. Whether this can be reasonably ex-pected under the presently applicable laws is animportant question, one that is addressed inchapter 3 of this study.

Ch. 5—Industrial, Commercial, and Rural Cogeneration Opportunities . 183

Utility ownership has the advantage that utilitiesconsider power production their primary line ofbusiness. Utility-owned cogeneration systemscould be included in the rate base, thus allow-ing the utility to earn a return on the systems.

Ut i l i t y ownersh ip a lso p rov ides a s t ra igh t fo rward

means by which utilities could maintain dispatch-ing control over the electric power entering thegrid, providing them with assurance that this newform of generating capacity would preserve sys-tem stability (see the discussion of interconnec-tion in ch. 4). Furthermore, cogeneration’s rel-atively small unit size can decrease the cost ofcapital for capacity additions and can reduce thedownside risk of unanticipated changes in de-mand growth (see ch. 6). However, as discussedin chapter 7, unregulated utility ownership raisesconcerns about possible anticompetitive effects.

Third-party ownership is most likely to occurin cases where new steam-producing equipmentis badly needed to cut energy costs but the in-dustry in question cannot raise capital for a newsystem. Novel cogeneration financing arrange-ments are emerging slowly and it is risky to makegeneralizations so early in the process. In somecases, the third party may be a separate entityset up by the utility. In other cases, it may be alarge institutional investor wooed by the industry.There appear to be few instances on the industrialscene where—as happened in the developmentof hydro power under the Public Utility Regula-tory Policies Act of 1978 (PURPA)—a small en-trepreneur identified an attractive steam load,proposed building a new plant, served as capitalmatchmaker, and then ran the facility. Third par-ties will want to reduce the risks of ownershipby negotiating long-term purchase power con-tracts with the utilities.

TAX INCENTIVES

Significant Federal tax incentives are availableto cogeneration in recognition of its fuel savingvalue. These include the investment and energytax credits, accelerated depreciation, and safeharbor leasing (see ch. 3). In some cases, co-generation may also qualify for tax-exempt financ-ing. An informal survey by OTA indicates thatthese tax incentives may promote some marginalcogeneration projects from “unattractive” to “at-

tractive,” but tax considerations are not, in mostcases, the overriding economic issue. Industrialpower cost and reliability, PURPA avoided costprices, and restrictions on capital from traditionalsources are still the dominant economic issues.On the other hand, tax considerations can havea very strong influence on ownership and financ-ing decisions for a cogeneration project. A keyissue in cogeneration tax treatment is whether ornot facilities are categorized as “public utilityproperty.” Full utility ownership is generally theleast attractive tax alternative for a cogenerationproject under either the 1978 or 1980 tax bills.

FLEXIBILITY IN LOAD EXPANSION

One of the major reasons that cogenerationwould be attractive to utilities in the short termis its suitability for adding new capacity in smallincrements that are deployable in a relativelyshort time. Cogeneration capacity sizes in in-dustrial settings range from 100 kw, minisculeby utility standards, to over 150 MW, about halfthe size of the smallest unit of baseload capacitya large utility would consider installing. Manyutilities favor 300-MW coal units as small in-cremental additions for central plant capacity.Adding Ieadtime for planning, the total time toput a cogeneration facility in place is 3 to 6years–much less than the 5- to 12-year periodrequired for utility baseload plants. As a result,cogeneration can represent an “insurancepolicy” against unanticipated changes in demandgrowth-a much less costly form of insurancethan overbuilding central station capacity.

The planned cogeneration strategy of AP&L (de-scribed above) illustrates the flexibility in capacitygrowth that can be attained with cogeneration.AP&L’s proposed 1,700-MW remote gasificationsystem (described above) would be based oncombined-cycle units at each plant site (up to 35sites), which would allow the utility to decouplesteam and electricity production. Thus, the utili-ty could build a system to supply the industrialsteam load of its customers, and then turn onelectrical capacity as needed. In this way, AP&Lcould gradually augment its system capacity fromzero to 1,700 MW over several years in a smooth-ly increasing trend (14).


PURCHASE POWER RATES

The critical economic considerations in a deci-sion whether to invest in an industrial cogenera-tion system include the rates and terms for utili-ty purchases of cogenerated power. As discussedbelow, the utility buyback rates are a primarydeterminant not only of the number of cogenera-tion systems installed, but also of the amount ofelectricity they will produce. However, Federaland State policies on this issue are in great fluxjust now, and the regional variability in purchaserates is quite high (see ch. 3). As a result, manypotential cogenerators are caught in a “squeeze”between the regulatory uncertainty surroundingsales of electricity to the grid and the desire toinvest during 1982 before the energy tax creditexpires.

SIMULTANEOUS PURCHASE AND SALE

The regulations implementing PURPA section210 allow industrial cogenerators to simultane-ously buy all their needed power from the utilities(at rates that do not discriminate against themrelative to other industrial customers), while sell-ing all their cogenerated electricity at the utili-ty’s purchase power rate. In effect, this provisiondecouples a cogenerator’s thermal and electricenergy production (see ch. 3). Utilities, which areseeing their load growth diminish drastically asa result of price-induced conservation, may findthis option attractive because it does not reducetheir load base. Moreover, industries generallyare less willing to project their steam or heat loadsas far into the future as utilities. Systems that allowsome decoupling of steam and electric produc-tion thus have potentially greater appeal to in-dustry, under industry ownership. industries mayalso find simultaneous purchase and sale attrac-tive because it does not require them to paystandby charges for electricity they would usewhen the cogeneration system was shut downfor maintenance or unplanned outages.

REGULATORY UNCERTAINTY ANDPERCEIVED RISKS

At present, probably the greatest deterrent toinvestment in cogeneration systems is regulatoryuncertainty. Utility rates for purchases of cogen-erated power under PURPA and the FERC regula-

tions on interconnection of cogenerators with thegrid are uncertain pending a final court ruling onthe existing regulations (see ch. 3). Other regu-latory or legislative items that may affect cogen-eration implementation but are in a state of fluxinclude: the Fuel Use Act regulations on exemp-tions for cogenerators; natural gas prices, theschedule for deregulation, and its effect on in-cremental pricing; and the expiration of theenergy tax credit at the end of 1982.

Industrial companies also are concerned aboutlimited capital resources and high interest rates,and may favor investments in process improve-ments that would contribute to plant efficiencyover investments in new energy systems. Com-panies also are hesitant to invest until the paybackperiods are more firmly established, given uncer-tainties in fuel prices. Some companies also haveexpressed concern about a lack of technical ex-pertise in the use of solid fuels, as well as aboutthe possibility of using up air pollution incrementsthat may be needed for future plant expansions.

Market Penetration Estimates

A number of recent studies have estimated thetechnical and/or market potential for cogenera-tion based either on the Quads of energy thatmight be saved by the substitution of cogen-erators for separate conventional electric andthermal energy systems, or on the Quads of steamand megawatts of installed capacity that couldbe supplied by industrial cogeneration. The rangeof estimates given in these studies is large, extend-ing from 6 to 10 Quads of energy saved annual-ly by 1985, and from 20 to 200 GW of installedgenerating capacity by 2000. Differing assump-tions about energy prices, ownership, and returnon investment, whether the cogeneration facilitieswould export electricity to the utility grid, andthe types of technologies employed account forthe large range. The early projections of thepotential for industrial cogeneration are sum-marized in table 35.

The general methodology in each of these stud-ies was to estimate the industrial steam load andthen quantify what portion of that load would betechnically and economically exploitable forcogeneration. The choice of cogeneration tech-

Ch. 5—industrial, Commercial, and Rural Cogeneration Opportunities . 185

Table 35.—Early Estimates of the Potential for Industrial Cogeneration

Installed capacity Expected annual steamStudy Ownership Cogenerator Off site distribution in 1985 (GW) load growth

DOW Industry Steam turbine No 61 3.5 % (1968-80)4.5% (after 1980)

RPA Industry Steam turbine No 10-16 4.1% (1976-85)Thermo Electron Industry Steam turbine Yes 20-34 a 4.1 % (1975-85)

Combustion turbine 85-128Diesel 107-209

Utility Steam turbine 34-37a

Combustion turbine 131-137Diesel 218-249

Williams Utility Steam turbine 28 (in 2000) 20/0 (1974-2000)Combustion turbine or

combined cycle:Oil-fired 28Coal w/FBC 95

Diesel 57Total 208 (in 2000)

Yes

aThe Thermo Electron estimates assume only one technology Is developed and are thus not additive.

SOURCE: OTA from Robert H. Willlams, “lndustrlal Cogeneration,” 3 Annual Review of Energy 313-3S6 (Palo Alto, CalIf.: Annual Reviews, Inc., 1978).

nologies, among other considerations, thenwould determine the electrical capacity achiev-able with such a steam load. In general, thosestudies that assumed the use of only steam tur-bine topping cycles (sized so there was no off-site export of electricity) arrived at much lowerestimates of cogeneration electric capacity.

A DOW Chemical Co. study (6) projected 61GW of electrical cogeneration capacity in 1985(including existing capacity), corresponding toabout 50 percent of the projected process steamdemand for that year. The DOW study assumedindustrial ownership (with a 20-percent rate ofreturn) of steam turbine topping cycles installedin plants using over 400,000 lb/hr of steam. Thesecogenerators would produce the minimumamount of electricity for a given steam load(about 40 kWh/MMBtu) and would not exportany electricity offsite. Even with this rather con-servative choice of technologies, there were in-stances in which the study found that more elec-tricity would be generated than could be usedonsite, and so the estimated market potential forcogeneration was scaled down accordingly.

A 1977 study by Resource Planning Associates(RPA) for DOE (24) examined the potential forcogeneration development by 1985 in six majorsteam-using industries (pulp and paper, chemi-cals, steel, petroleum refining, food, and textiles).RPA only considered applications larger than

5-MW electrical capacity and assumed that all ofthe cogenerated electricity would be consumedonsite. Furthermore, approximately 70 percentof the total estimated process steam available forcogeneration development in 1985 was elimi-nated as unsuitable for cogeneration, due totechnical or economic constraints, or to conser-vation and process improvements. As a result,RPA found the 1985 potential in the six industriesto be 1.7 Quads of process steam output (10-GWcapacity) without Government action, and 2 to2.6 Quads of process steam (12- to 16-GWcapacity) with Government programs such as theenergy tax credits and the more rapid deprecia-tion now in place, or PURPA-style regulatory andeconomic incentives.

A study by Thermo Electron (30) was based onthree of the most steam-intensive industries—thechemical, pulp and paper, and petroleum refin-ing industries—which were assumed to accountfor approximately 34 percent of the total esti-mated 1985 industrial steam loads. This studyassumed that either industry or utilities might in-vest in high E/S technologies such as combustionturbines and diesels, and found that the max-imum implementation for combustion turbines—137 GW of cogeneration capacity–occurred withutility ownership, an investment tax credit of 25percent (rather than the 10 percent then avail-able), and Government financing for half theproject.

186 Industrial and Commercial Cogeneration

A 1978 study by Williams (33) assumed utilityownership, and a mix of technologies in whichsteam turbine cogenerators met 42 percent of thesteam load and higher E/S technologies the re-mainder. Williams assumed that fuel use forsteam generation in existing industries would in-crease 2 percent annually through 2000, leadingto a process steam demand of 16.1 Quads inthose industries. Williams also assumed thatabout half of the total steam demand would beassociated with cogeneration having an averageE/S ratio of 140 kWh/MMBtu and producing elec-tricity 90 percent of the time that steam is pro-duced. Based on these assumptions, Williams es-timated the total cogeneration potential in 2000to be 208 GW, saving over 2 million barrels ofoil per day.

As noted previously, each of these studiesbegan by estimating the present demand for in-dustrial process steam. These estimates includea 1974 steam load of 7.8 Quads (Williams, basedon an Exxon analysis); a 1976 industrial steam de-mand of 9.7 Quads (RPA); and a 1980 estimateof about 14 Quads (DOW). In 1981, the SolarEnergy Research Institute (SERI) attempted toreconcile the differences among these and otherestimates of industrial steam load, and found thatthe data base (disaggregated by fuel use, boilercapacity, average and peak steam loads per site,steam quality, steam load by industry, steam loadby State) is so inadequate that none of thesepublished estimates could be considered ac-curate. However, SERI was able to reject thehigher steam demand estimates in the literaturebecause they did not account accurately for fueluse in smaller boilers in less energy-intensive in-dustries. By reconciling differences in approachand accounting among the lower published num-bers, SERI arrived at an estimate equivalent to ap-proximately 5.5 Quads/yr during 1976-77 (27).

In addition to overestimating the base industrialdemand for steam, the early studies of industrialcogeneration assumed robust steam growth-onthe order of 4 percent annually. The steady prog-ress that has been made in industrial energy con-servation through the 1970’s—amounting to adecrease in energy use per unit of industrialvalue-added of approximately 2 percent peryear—makes these earlier predictions for steam

load growth highly unlikely. More recent studiesof cogeneration have projected steam growthrates that are either lower or constitute nogrowth. For instance, in 1980 SRI Internationalprojected 1.18 percent per year (28), whileWilliams now estimates zero growth in steam de-mand through 2000 (34), and SERI projected zeroor negative growth (27).

More recent estimates of the potential for in-dustrial cogeneration either have assumed amuch smaller present steam base and lower ther-mal demand growth rates, or have devised amethodology that does not begin with an esti-mate of the current steam load. However, dueto changes in the context for cogeneration sincethe earlier studies were completed, these recentstudies have not necessarily projected a lowermarket potential for industrial cogeneration.These contextual changes include the PURPAeconomic and regulatory incentives for grid-connected cogeneration, substantial increases inoil and electricity prices, special energy taxcredits, and shorter depreciation periods. As aresult of these and other considerations, cogen-eration is considered likely to be economicallyattractive at more industrial sites than in earlierstudies (despite the lower thermal demand pro-jections), and more likely to use technologies withhigher E/S ratios that produce more electricity.

A 1981 study by RPA (23) examined the 1990potential for cogeneration in five industries (thoseanalyzed previously except for textiles), beganwith a 1990 steam demand of 682 million lb/hr(approximately 6 Quads/yr, assuming 1,000Btu/lb and 24-hr operation). Of this base, RPAfound an expected investment in the five in-dustries of 155 million lb/hr (1 .36 Quads) steamproduction, or 20.8 GW of electric capacity,assuming “base case” utility buyback rates (seetable 36). This would increase to 28.7 MW of in-stalled cogeneration capacity if, as a result of utili-ty ownership, 30 percent of the steam turbineswere replaced by combustion turbines and com-bined cycles. The “high buyback rates” casewould lead to an expected investment potentialof as much as 37 GW of instaIled capacity, whilethe “low” case shows 14.2 GW (1.2 Quadssteam). The amount of electric capacity declinesmore than the steam production with lower buy-

Ch. 5—industrial, Commercial, and Rural Cogeneration Opportunities ● 1 8 7

Table 38.-Range of Utility Buyback Rates Analyzed by RPA(1980 dollars In cents/kWh)

Marginal utility Low buyback Base buyback High buybackDOE region fuel rate rate rate

1. New England . . . . . . . . Oil 4.0 5.5 7.02. New York/New Jersey. Oil 4.0 5.5 7.03. Mid-Atlantic . . . . . . . . . Oil 4.0 5.5 7.04. South Atlantic . . . . . . . Oil/coal 2.0 3.5 5.05. Midwest. . . . . . . . . . . . . Coal 2.0 3.0 4.06. Southwest. . . . . . . . . . . Natural gas 2.5 4.0 5.57. Central. . . . . . . . . . . . . . Coal 1.0 2.0 3.08. North Central . . . . . . . . Coal 1.0 1.5 2.59. West. . . . . . . . . . . . . . . . Oil 4.5 6.0 7.5

10. Northwest . . . . . . . . . . . Coal 3.5 4.5 5.5SOURCE: Resource Planning Associates, Inc., The Potential for Industrial Cogeneratlon Development by 1990 (Cambrldge,

Mass.: Resource Plannlng Associates, 1981).

back rates due to the sensitivity of technology E/Sratio to these rates (23).

In an informal update of his earlier work,Williams (34) begun with a much lower steamdemand–4.l Quads in six industries in 1977–but assumed that cogeneration would achieve ahigher degree of penetration of the steam basethan he had assumed earlier. Of these 4.1 Quads,Williams assumed 1.25 Quads would be unsuit-able for cogeneration (due to load fluctuations,low steam demand, low-pressure waste heatstreams, declining demand, etc.), resulting in asix industry market potential of 93 to 142 GWin 2000, depending on the technology mix.Williams estimated an additional potential of upto 32 to 49 GW in other industrial sectors, if theirsteam loads are proportional to those in the sixindustries, but less if their steam loads are smalleror more variable. Finally, Williams estimates thatnew industries (e.g., thermally enhanced oil re-covery) have a potential of 11 to 20 GW of in-stalled capacity. Together, these sources have an“economic potential” of 136 to 211 GW of co-generation capacity in 2000. Williams considersthis economic potential to be the amount avail-able for insuring against underdevelopment ofcentral station generating capacity. The actualamount to be designated as a “prudent planningbase” for such insurance could not be deter-mined without better disaggregated data on thesteam base, but Williams found 100 to 150 GWto be a “conservative estimate” (34).

Williams’ approach to cogeneration as insur-ance against the uncertainty in future electricitydemand growth was included in the 1981 SERI

report on solar/conservation. SERI did notestimate the total potential for industrial cogen-eration because the report’s emphasis on con-servation meant that projected electricity demandgrowth was so low (0.13 percent annually) thatno cogeneration electrical capacity would beneeded unless the conservation targets were notmet. The study concluded that 93 GW of cogen-eration in the six industries would be an adequateinsurance measure, but made no attempt to as-certain how much capacity would be econom-ically attractive (27).

A different methodology was adopted in a 1982analysis for DOE (12). Rather than using a grossestimate of steam demand as the primary meas-ure of potential, this study began by individuallyanalyzing the 10,000 largest U.S. industrial sitesfor their cogeneration potential based on buy-back rates, accelerated depreciation, heat match,and other considerations. This analysis identified3,131 plants in the 19 manufacturing sectors thatwould have a return on investment greater than7 percent and represent the maximum potentialof 42.8 GW of cogeneration capacity (produc-ing 3.3 Quads of steam). Ninety-two percent ofthe electric capacity and 95 percent of the steamgenerated are in the five top steam-using indus-tries. The “best” mix of technologies for thesesites was found to be 70 percent combustion tur-bines and 30 percent steam turbines, resultingin the offsite export of 49 percent of the electricitygenerated. If the return on investment increasedto 20 percent, the maximum potential decreasesto 20 GW. The study also estimated that an ad-ditional 48.5 GW of capacity could be installed

188 . Industrial and Commercial Cogenerafion

at new industrial sites based on U.S. Departmentof Commerce industrial growth figures andassuming that plant expansions and new plantswould have characteristics similar to those in ex-isting plants (12).

The studies reviewed above illustrate two mainpoints:

1.

2.

The technical potential for cogeneration isvery large; even the lowest of these estimatescorresponds to the equivalent of 20 newbaseload central generating plants, while thehighest estimate corresponds to a generatingcapacity capable of producing more thanone-sixth of the electrical power presentlyused in the country.Economic and institutional considerationsare paramount in determining how muchcogeneration will actually be installed, as il-lustrated by the wide sensitivity of these es-timates to variations in utility purchase rates,tax incentives, ownership, fuel prices, etc.The underlying consensus among these stud-ies on all matters except the likely steam loadis in fact remarkable.

While the market for cogeneration is potentiallylarge, the actual rate of cogeneration equipmentinstallation is much lower than expected a fewyears ago. This trend is occurring in spite of higherelectricity prices because of the weakened finan-cial posture of utilities, industries’ difficulty in rais-ing capital for expansion due to unprecedentedlyhigh interest rates, and the unexpectedly rapidrate of energy use reductions in industry. Long-term fuel supply uncertainties also may workagainst cogeneration, or against the more attrac-tive cogeneration options.

The effect of energy conservation in industryis one of the key influences on future cogenera-tion. Whereas substantial steam load growth wasassumed in most cases, the rate of energy use perunit of production has in fact dropped substan-tially in major industries. The industry that hastraditionally been most committed to cogenera-tion as an integral part of its business, the pulp

and paper industry, has reduced its energy con-sumption per ton of production by 26 percentbetween 1972 and 1980. The chemical industryhas reduced its energy use by 22 percent overthe same period, and the petroleum refining in-dustry, 15 percent. Steam production at thelargest operating industrial cogeneration sys-tem–the Gulf States 130-MW complex supply-ing steam to oil refineries and related industriesnear Baton Rouge, La.—has decreased by 30 to50 percent over the past several years, accordingto a spokesman for the utility.

The weakened financial position of some in-dustries is also likely to be a factor in cogenera-tion. Whereas the steel industry is a very heavyenergy user, it has been a declining industry overthe past decade and one unlikely to have the cap-ital for new cogeneration facilities. In most in-dustries, cogeneration faces competition forcapital with expansion of production capacity,and in such a face-off cogeneration investmentsare likely to have a low priority. However, thissituation would be averted under utility owner-ship, or under the leasing provisions of theEconomic Recovery Tax Act of 1981. Althoughutilities face more financial problems than at anytime in decades, smaller investments in cogenera-tion systems can be financed more easily than1,000-MW central powerplants.

If cogeneration is implemented, the amount ofelectrical capacity resulting from a system sizedto fit a given heat or steam load could vary byas much as a factor of 4 depending on the typeof cogeneration equipment that is used. For ex-ample, a large industrial installation that uses 0.5million lb/hr of steam would cogenerate 30 to 40MW of electricity with steam turbines, and 120to 150 MW with gas or oil burning combustionturbines. A major question for industrial usage,therefore, is the extent to which alternate fuelssuch as coal or biomass can be adapted to tur-bine technology, because the traditional fuels (oiland gas) are now the most expensive availableon the U.S. market.


COMMERCIAL COGENERATIONAlthough the opportunities for cogeneration in

industry are numerous and diverse, cogenerationin commercial buildings is likely to have a smallermarket potential. Commercial enterprises typical-ly use thermal energy only for space condition-ing and water heating, and have thermal load fac-tors that are usually much lower than those ofindustrial concerns. As a result, the economicsof cogeneration systems for commercial buildingstraditionally have been much less favorable thanthose of industrial systems. Recently, however,market incentives resulting from PURPA and/orfrom high electricity and fuel prices have changedthe economics of commercial cogeneration. Sev-eral technical and economic factors in particulardetermine the relative attractiveness of commer-cial building cogeneration and purchasing utility-generated electricity, such as the suitability ofelectrical and thermal load profiles, the poten-tial for fuel savings, and the change in relativefuel prices.

This section discusses the results of OTA anal-yses of cogeneration in commercial buildings v.centralized electric utility systems. The sectionbegins with a review of the literature on commer-cial cogeneration, followed by a general introduc-tion to OTA’s analytical methods, a discussionof the major assumptions used in the analyses,and a summary of the results.

Previous Studies ofCommercial Cogeneration

Several existing studies have examined thepotential for commercial cogeneration in par-ticular areas or under certain conditions. Theseinclude a FERC study that estimated the amountof cogeneration that would be stimulated byPURPA (28); a study by the American Gas Asso-ciation (AGA) that compared gas-fired cogenera-tion with two conventional heating systems in ahospital in different climate regions (l); andregional studies by Consolidated Edison (Con Ed)for their service area (1 3,25) and by the State ofCalifornia for State-owned buildings (s).

The FERC study calculates the national and re-gional penetration of cogeneration and small

power production induced by PURPA through1995, and concludes that only in the Mid-Atlanticregion (New York, New Jersey, and Pennsylvania)is commercial building cogeneration likely to beeconomically attractive. FERC projects that 2,500MW of commercial sector capacity could ormight be installed in this region by 1995, produc-ing 10,000 GWh/yr of electricity. In these calcula-tions FERC assumed: first, that the PURPA regula-tions would be the sole incentive for cogenera-tion; second, that cogeneration would only occurin large new buildings (e.g., new apartment build-ings with more than sO units, new hospitals hav-ing more than SO beds); third, that all commer-cial investment would earn a fixed rate of returnof 20 percent; and fourth, that all equipmentwould have a fixed capacity factor of 45 percentand a fixed size of 500 kw. Some of these as-sumptions may be both too kind and too cruelto commercial cogeneration. That is, FERC’S anal-ysis ignores incentives other than PURPA (e.g.,tax benefits, high electricity rates), the possibili-ty of retrofits or eventual use in smaller buildings,and the achievement of higher capacity factors,and thus may understate cogeneration’s poten-tial. At the same time, the analysis uses a veryfavorable rate of return and thus may overstatethe market potential for cogeneration under cur-rent high interest rates.

The AGA study is based on a prototype designfor a 300,000 square foot hospital located in fourdifferent climate regions. AGA assumed two dif-ferent rates for utility purchases of cogeneratedpower to compare the annualized capital, fuel,O&M, and net electricity costs for three differenttypes of heating and cooling systems for the hos-pital: 1) a conventional combination system,using a gas boiler to provide steam for spaceheating plus an electric air-conditioner for spacecooling, and relying on the grid for electricity;2) an all-electric system, using baseboard resist-ance heaters and air-conditioners run with utility-generated electricity; and 3) an all-gas system,using a gas-fired cogenerator to provide electricityand space heating and a waste heat recovery sys-tem to run an absorptive air-conditioner. AGAassumed the cogenerator was sized to match the


thermal load, with any excess electricity beingsold to the electric utility.

The AGA study concluded that the “economicattractiveness (of cogeneration) is heavily depend-ent on the buyback rate for cogenerated electrici-ty.” The study found that, for all four climateregions, the cogeneration system had a lower an-nual cost than the other options when the buy-back rates were set at 8cents/kWh. However, whenthe rate was lowered to 2cents/kWh, cogenerationwas found to be economical only in the Mid-Atlantic region. This is because the higherbuyback rates offset cogeneration’s high capitalcost compared to the capital costs of the com-bination and all-electric systems. But when thebuyback rates were lowered, cogeneration’s cap-ital cost became prohibitive in all but the Mid-Atlantic region, where high fuel costs and elec-tric utilities’ dependence on foreign oil give fuel-efficient cogenerators an economic advantage.

Although the AGA study analyzes the sensitivityof cogeneration economics to factors such as buy-back rate and climate, it is limited to hospitals,a type of commercial building with a relativelyconstant energy demand.

ConEd developed a model of the costs andbenefits of investment in cogeneration based onthe internal rate of return from such investment,and applied the model to load data for their 4,500largest customers, assuming that the investmentwould be made if the rate of return would be atleast 15 percent over 10 years. Depending oncustomers’ loads and other variables, ConEdfound an “expected” cogeneration penetrationof 395 customers with a combined peakload of1,086 MW, with a high range of up to 750 co-generators totaling 1,483 MW peakload. Theanalysis was then repeated using a slightly highercost cogenerator (and thus a lower rate of return),and the market potential dropped substantially—to 27 customers with a combined peakload of 130MW.

These market penetration estimates for cogen-eration depend heavily on how the cogeneratorswill operate. Con Ed assumed that cogeneratorswould only operate when there is sufficient elec-trical demand on the system. Thus, the assumedthermal efficiency is low (52 percent for commer-

cial building systems and 62 percent for residen-tial systems), and the cogenerators are unable toprovide either substantial fuel or cost savings.However, if cogenerators are undersized (relativeto the electrical demand) so that they operate as“baseload” heaters and only supply some of theelectrical needs, they may have lower total costs,and thus, higher penetration rates than the onescalculated by ConEd (3). Therefore, even in theMid-Atlantic region, cogeneration’s market pen-etration may be very sensitive to operating andcost assumptions.

In the fourth study of cogeneration in commer-

cial buildings three State agencies in Californiacalculated the cogeneration potential in State-owned buildings, including hospitals, universities,and State offices. The State identified 188 State-owned facilities that have significant potential forcogeneration, and initiated engineering studiesfor the cost effectiveness of cogeneration. “Theevaluation showed that 150 MW at 24 sites couldbe designed, under construction, or in operationin fiscal year 1981. An additional 97 MW at 31sites could be developed in fiscal year 1982, total-ing 247 MW at 55 sites. It should be clearly un-derstood that these are preliminary estimates ofcost-effective cogeneration capacity. Furtherengineering analyses may result in increased ordecreased capacity.” The study concludes thatthe total potential for cogeneration in State-owned buildings is over 400 MW. The distribu-tion of this capacity among State facilities isshown in figure 51.

Because the literature on commercial cogen-eration is sparse, OTA undertook its own analysisof cogeneration opportunities in the commercialsector. This analysis is concerned with illustratingthose parameters that significantly affect the useof cogeneration in commercial buildings. To dothis, in part, we make use of a computer-basedmodel—the Dispersed Electricity TechnologyAssessment (DELTA) model–that simulates deci-sionmaking by electric utilities in choosing newcapacity. The model can accommodate rangesof values for the technical, operating, and finan-cial characteristics of utilities and cogenerators.There are limitations to its use, however, due tothe number of assumptions that have to be madeand to the gaps in the available data. Consequent-

Ch. 5—industrial, Commercial, and Rural (generation Opportunities ● 191

100

90

80

70

60

50

40

30

20

10

0

Figure 51.— Cogeneration Potential at California State Facilities

Megawatts Total potential = 410 MW

Uc Csuc Hospital Prison Comm New Others

college buildings

Type of State facilitySOURCE: California Energy Commission, Commercial Status: Electrical Generation and Nongeneration Technologies

(Sacramento, Calif.: California Energy Commission, P102-8O4O4, April 1980).

Iy, the DELTA model cannot be used to accurate-ly project levels of cogeneration use in commer-cial buildings over the next several years. in par-ticular, we have not used the model to analyzethe case where natural gas and distillate oil pricesare significantly different from one another, northe case where retrofits of existing buildings areincluded in the demand for thermal energy. Aqualitative discussion of these cases is presented,however. The model does give us, though, in-sight into how cogeneration might compete withnew central station capacity to supply commer-cial electricity demand, and the effect of such fac-tors as thermal load profiles on that competition.Therefore, despite its limitations it is believed thatthe DELTA model–properly clarified–will sub-stantially assist in understanding the conditionsthat affect cogeneration’s future in the commer-cial sector.

Critical Assumptions and Limitsof the DELTA Model

The DELTA model uses a linear program (sim-ilar to those used by utility planners) thatminimizes the total cost of producing electricityand thermal power during the years 1981 to 2000(see app. A for model description). The modelsimulates the addition of grid-connected cogen-eration in three kinds of large new commercialbuildings, with different types of daily load cycles,to supply electricity, space heating, and spacecooling demands. Several scenarios were con-structed to explore the sensitivity of cogenera-tion in these buildings to regional utility andclimate characteristics, future fuel price changes,

and different technological specifications. Thestructure of the model, the assumptions aboutthermal and electricity supply and demand, and


the features of the scenarios constructed are de-scribed below.

Model StructureElectric and Thermal Cost Minimization.—The

DELTA model differs from many existing utilityplanning models in that its objective is the min-imization of total annualized fixed plus operatingcosts for both utilities and their commercialbuilding customers (e.g., for heating and cool-ing). Thus, DELTA goes beyond traditional utili-ty planning, which usually analyzes only thosecosts borne by the power system. The strategyselected through this hybrid cost minimizationmay not exactly match either the strategy chosenby the utility or by the customer acting alone, butwill tend to produce an “average” between bothparties.

Demand Assumptions

Grid-Connected Cogeneration.–The DELTAmodel only examines grid-connected cogenera-tion because the PURPA provisions on purchasesof cogenerated power are intended to benefitcogeneration systems that provide energy and/orcapacity as well as diversity to utilities. Therefore,OTA did not analyze the effects of stand-alonesystems on utility operations.

Three Types of Energy Demands.–The DELTAmodel specifies hourly demands for three typesof energy: space heating, space cooling, and elec-tricity. The analysis begins in 1980 with a specifiedthermal baseline of zero load and zero capaci-ty, and an electrical baseline of 1,000-MW loadand the existing generating capacity mix (nor-malized to the 1,000-MW load) in each sampleregion. The model then determines what capacityadditions will minimize utility and customer costsfor all three types of energy, assuming a rangeof growth rates for energy and peak demands ineach sample region (see table 40, below, for adescription of existing electrical capacity andgrowth rates). New capacity is added at the endof each decade—in 1989 and 1999—and then sys-tem costs are evaluated in 1990 and 2000.

The 1980 electric generating capacity in eachsample region was normalized to 1,000 MW tofacilitate comparisons of capacity additions and

future utility operations among the differentregions. However, in order to compare thermaldemands among the building types and regionsa different approach was necessary. A largeamount of data would be needed for a precisespecification of existing thermal capacity anddemands–unlike electrical demands, there is noaccurate and centralized source of informationon thermal demand and capacity. Thus, in orderto ensure consistent and accurate treatment ofthermal demands, OTA would have had to col-lect individual commercial customer profiles–atime-consuming and expensive process. There-fore, OTA chose another method for the DELTAmodel: to set existing thermal demands andcapacity equal to zero. In effect, this is equivalentto only allowing cogeneration in new buildings,and then comparing the cost of installing cogen-eration with the costs for new centralized capaci-ty and new steam boilers, but not considering thereplacement of any existing steam boilers withnew cogeneration equipment. As was stated,without inclusion of such boiler retrofits, themodel cannot be used to project the cogenera-tion potential in the entire commercial sector.Although we have not attempted to project theretrofit potential in any other way, the factors thatwill influence this potential will be discussed laterin this section.

Eight Typical Days. –OTA chose to specifyeach type of energy demand with a yearly pat-tern of eight different “typical days” in order toobserve more clearly the range and frequencyof utility operating characteristics (see table 37).

Table 37.—Typical Days Used in the DELTA Model

Day type Frequency Per YearWinter:

Peak a. . . . . . . . . . . . . . . . . . . . . . . . . . .Weekday . . . . . . . . . . . . . . . . . . . . . . . .Weekend. . . . . . . . . . . . . . . . . . . . . . . .

Summer:Peak a.. . . . . . . . . . . . . . . . . . . . . . . . . .Weekday . . . . . . . . . . . . . . . . . . . . . . . .Weekend. . . . . . . . . . . . . . . . . . . . . . . .

Fall/spring:Weekday a . . . . . . . . . . . . . . . . . . . . . . .Weekend . . . ... , . . . . . . . . . . . . . . . . .

65926

10844

Total . . . . . . . . . . . . . . . . . . . . . . . . . 365aThe 1990 electrlc bad patterns for region 1 for these 3 days are shown in fig. 52.


Ch. 5—lndustrial, Commercial, and Rural Cogeneration Opportunities 193

Each typical day has a specific load cycle patternfor each region and year. For example, the loadcycle patterns during 1990 for three differenttypical days and for one region (New England)are shown in figure 52. The differences amongthese cycles are caused by the different assump-tions for energy use and demand growth usedin each region.

Three Commercial subsectors.-ln addition tospecifying the annual load patterns for electrici-ty, OTA chose to disaggregate the commercialsector’s thermal heating and cooling demandsinto three parts: hospitals and hotels, multifami-ly buildings, and 9-to-5 office buildings. This wasdone to explore the effects of load diversity oncogeneration operation, and thus to providemore precise information on the opportunitiesfor commercial cogeneration. Other commercialsector building types (such as universities andretail stores) have energy demand profiles thatare combinations of these basic three categories.(The electric demands were not disaggregated inthe DELTA model because the load profiles for

the entire commercial sector were sufficient tocapture the interaction of the cogenerators withthe centralized utility system.)

The three subsectors were chosen for their dif-ferent thermal load patterns; examples of thesepatterns for two typical day types are given infigures 53 and 54 for 1990 New England heatingand cooling demands respectively. For heatingdemands, hospitals and hotels have the lowestenergy demands of all the subsectors, with smallpeaks at 8 a.m. and 9 p.m. Multifamily buildingsuse somewhat more energy and have similarlyoccurring peaks, while 9-to-5 offices use the mostenergy and have the most pronounced peak dur-ing the winter days at 6 a.m. The cooling de-mands of hospitals and hotels and multifamilybuildings are small when compared to officebuildings, the latter having a peak during sum-mer days at 2 p.m.

Supply Assumptions

The energy supply assumptions in the DELTAmodel specify different sets of fuel prices and of

Figure 52.—Comparison of Eiectric Demand for Three Types of Days(for region 1 during 1990)

Fall/spring Summer Winterweekday peak day peak day-. .-. . . . . . . . .

MW electrical demand1,100

1,000

900

800

700

600

500

40012 midnight 4 a.m. 8 a.m. 12 noon 4 p.m. 8 p.m. 12 midnight

Time of day



Figure 53.—1990 Heating Demands for Scenario 1s (for Region 1 during 1990)

Winter peak day

1 0 0

90


Time of day

Summer peak day7

Multifamily 9-to-5 office I

12 midnight 4 a.m. 8 a.m. 12 noon 4 p.m. 8 p.m. 12 midnightTime of dayaScale on two graphs Is different.


technological and operational characteristics in coal (and electricity) and 1.7 percent per year fororder to describe the three different sample utility fuel oil and natural gas for the low price trajec-regions. tory, and 4.7 percent annually for coal (and elec-

Fuel Prices.–OTA specified two different fueltricity) and 4.8 percent per year for fuel oil and

price trajectories, based on the 1980 averagenatural gas for the high price trajectory. * For this

prices in the commercial sector (31) and the rangeanalysis of commercial cogeneration, these as-

of real growth rates (not accounting for inflation)assumed in two previous OTA studies (1 7,20).

*These growth rates are explained in the OTA report, Applica-

These growth rates are: 1.0 percent annually fortion of Solar Technology to Today’s Energy Needs, vol. 11, September1978.

Ch. 5—Industrial, Commercial, and Rural Cogeneration Opportunities ● 195

Figure 54.-1990 Cooling Demandsa (for Region 1 during 1990)

Winter peak day

70

Summer peak day

4 r

(12 midnight 4 a.m. 8 a.m. 12 noon 4 p.m. 8 p.m. 12 midnight

Time of daya Scale on two graphs Is different.


sumptions were modified slightly by setting the Therefore, only the lower price path results wereprice of natural gas equal to fuel oil after 1985. reported. These prices are shown in table 38.

Using two different fuel price trajectories al- our assumption about natural gas prices re-Iowed us to test the sensitivity of our results. quires elaboration. Currently, most natural gasHowever, the results varied by less than 2 per- is used for purposes that require a higher qualitycent between the two different price paths. fuel than coal or residual fuel oil. About 25 to

—.


Table 38.-Fuel Prices(all prices In 1980 dollars per MMBtu)

1980 1990 2000

Coal . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.34 1.95 2.38Residual . . . . . . . . . . . . . . . . . . . . ., . . . 4.05 5.86 7.13Distillate . . . . . . . . . . . . . . . . . . . . . . . . 5.67 8.20 9.98Natural gas . . . . . . . . . . . . . . . . . . . . . . 2.09 8.20 9.98SOURCE: Office of Technology Assessment.

30 percent of current natural gas use is for rais-ing steam, while the remainder goes for spaceheating in buildings, industrial process heat,peakload electricity generation (primarily com-bustion turbines), and chemical feedstocks (7).The future price of natural gas will be determinedby the relative strengths of these demands com-bined with the availability and cost of new do-mestic natural gas.

The conversion of all natural gas-fired boilersto coal would free about 4 trillion to 5 trillioncubic feet (TCF) of natural gas per year at cur-rent consumption rates. If there were no otherchange in natural gas supply and demand, thisnew “supply” would be more than enough toreplace all current distillate fuel oil used for sta-tionary purposes (1.9 MMB/D) (8). If price in-creases resulting from decontrol bring aboutmore conservation, additional natural gas wouldbe freed, which, when combined with the dis-placed boiler fuel, would result in a substantialsurplus of natural gas. The most logical use forthis surplus gas would be to displace residual fueloil used to fire boilers. (Of course, in reality, thegas would only leave the boiler market until itjust displaced all stationary fuel oil). This competi-tion with residual fuel oil would keep the margin-al cost of natural gas about the same as that ofresidual oil.

This scenario, however, assumes that domesticnatural gas supplies do not decline significantlyover the same period, and that the marginal costof the new supplies that offset the decline in pro-duction from existing reserves will be below theprice of distillate fuel oil. It is quite possible–indeed both Exxon and the Energy InformationAdministration have projected as much–thatthere will be a net decline in domestic naturalgas supplies by as much as 3 TCF by 1990 (10).On the other hand, AGA estimates that supplies

could increase substantially over this same period(2). In all cases, however, a significant fractionof new domestic supplies in these projections ismade up of high cost supplemental supplies—unconventional gas, Alaskan gas, and syntheticgas from coal. In fact, the three organizations pro-ject about the same amount of conventional do-mestic natural gas production—about 14 TCF in1990 and 12 TCF in 2000. This is close to thequantity now being consumed by the so-calledhigh priority uses for which only distillate fuel oilor electricity are feasible substitutes (19). There-fore, if the cost of new marginal natural gas sup-plies were equivalent to distillate fuel oil, the priceof all natural gas would approach that of distillateor electricity (whichever is cheaper) as decontroltakes effect and the quantity of old, flowing nat-ural gas under contract vanishes. It is partly thesomewhat optimistic supply assumptions aboutnew, “lower cost” gas that has caused most re-cent price projections to show natural gas pricesbelow those for distillate fuel oil for the remainderof the century (8).

Our price scenarios rest on the assumption that“lower cost” gas supplies will decline as fast orfaster than the rate at which coal displaces naturalgas in boilers. Even in this case, however, naturalgas prices could be lower than distillate oil if elec-tricity prices stay below distillate (on an energy-service basis)—as they currently are in many re-gions of the country. in this case, natural gasprices will likely approach those of electricity(again on an energy service basis). Similar specu-lation has been offered by others (26). BecauseOTA did not run the model with natural gasprices below distillate, the model results pre-sented are confined to what would happen underthe plausible situation that the prices of the twofuels are the same. To partially expand the analy-sis, some calculations of target gas prices are pre-sented for the condition that cogeneration pro-duces power at the cost of electricity determinedby the model. There is evidence, as will be seen,that some cogenerators are proceeding based onthe assumption that natural gas prices will remainbelow distillate prices for the economic life oftheir projects.

Technology Characteristics.–The majortechnologies used in the DELTA model include


three types of central electricity generating plants,several space heating and cooling technologies,and the cogenerators. Table 39 summarizes thecharacteristics for each type.

OTA specified three different types of genericutility generating plants to serve base, intermedi-ate, and peak loads. The baseload type is repre-sented by coal-fired steam powerplants, the inter-mediate-load type by either residual oil-fired ordistillate or gas-fired steam turbines, and the peak-ing technologies by distillate or gas-fired combus-tion turbines.

Space heating and cooling technologies in themodel include ordinary steam boilers used forheating, electric air-conditioners, absorptive air-conditioners using distillate or gas fuel, and ther-mal storage equipment with a capacity of up to24 hours storage. Because of the linear program-ing formulation, the model cannot change thetype of fuel used in either electric generating orthermal equipment from their original specifica-tion in table 39.

Two sets of capital costs for cogeneration ca-pacity were included in the analysis. The highercost cogenerator has a capital cost of $750/kW,while the lower cost system has a capital cost of$575/kW (both in 1980 dollars). These capitalcosts are typical of the range of cogenerationcosts described in chapter 4 (see table 23). We

did not include, explicitly, cogeneration technol-ogies that could use coal by means of syntheticfuel production or advanced combustion tech-nologies (e.g., fluidized beds). If the capital costsof these technologies are similar to those usedin the model, the results would remain un-changed. The only exception would be a re-ported increase in coal use if these technologiesare employed, because the model allowed co-generation technologies to use only oil or naturalgas.

Operational Assumptions.–OTA made threeoperational assumptions that would allow theDELTA model to follow more closely the way ac-tual grid-connected cogeneration systems wouldoperate. First, OTA specified the utility plannedreserve margin to be 20 percent of annual peakdemand. This includes scheduled maintenancefor 10 percent of the year for the base and in-termediate types of plants, and is typical ofreserve margins used in power systems planning,although actual reserve margins may be muchhigher than 20 percent. For the sample utilityregions used in this analysis (see below), all 1980reserve margins were above 20 percent. In ad-dition, the actual 1981 national average reservecapacity was around 33 percent (16).

Second, the model assumes that all cogenera-tion equipment has an E/S ratio of 227 kWh/

Table 39.—Technology Characteristics (all costs are for 1980 In 1980 dollars)

Cap cost Fixed O&M Variable O&M Availabilitya Heat rateb

Technology type ($/kW) ($/kW-yr) ($/kWh) (percent) (Btu/kWh)Base . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,014 14.0 0,001 68 10,300Intermediate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 200 0,0015 88 10,500Peak . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 200 0.3 0.003 93 14,000Cogeneration—high . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 750 0.0 0.008 95 9,751Cogeneration—low . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 575 0.0 0.008 95 9,751Thermal boiler . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 100 0.0 0.0 95 4,266Thermal storage. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2’ 0.0 0.0 — —Electric air-conditioners . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 700 0.0 0.0 95 1,138Absorption air-conditioners . . . . . . . . . . . . . . . . . . . . . . . . . . . 110 0.0 0.0 95 5,251aAvailability is the maximum percent of time that capacity can serve demand—thus 88 percent means the baseload equipment is out of service a total of 12 Percent

of the year.bThe cogeneration heat rate shown is the heat rata for electrical service only: the net heat rate (Including the energy In Steam produced by the cogenerator) is 5,333

Btu/kWh. Both of the heat rates shown for air-conditioners are calculated in Btu/kWh of heat removed from commercial buildings.cCapital cost of thermal storage is expressed in dollars/kWh.

SOURCES: Electric Power Research Institute, The Technical Assessment Guide, Special Report PS 1201 SR, July 1979, specifies capital cost, variable and fixed O&Mcosts, heat rates, and availabilities for coal steam plants with flue-gas desulfurization, for distillate oil-fired steam plants, and for oil- and gas-fired combus-tion turbine plants. OTA multiplied the costs for these plants by the Consumer Price index inflator to bring 1978 costs to 1980 costs, and used the GrossNational Product inflator to bring 1978 dollars to 1980 dollars. Characteristics for the thermal technologies were obtained by averaging the data collectedin ch. 4 for cogeneration equipment, thermal boilers, and storage (see table 23 for these figures). Zero fixed and variable O&M costs are assumed for theconventional space heating and cooling technologies, because these costs are very small when compared to the 8 mills/kWh variable O&M costs of thecogenerators.


MMBtu, with 35 percent of the output used forelectricity, 45 percent to satisfy the thermal load, *and 20 percent exhausted to the outside environ-ment—an overall efficiency of 80 percent. Third,thermal storage is assumed to have an efficien-cy of 90 percent (i.e., 1.0 MWh (thermal) intostorage can supply 0.9 MWh (thermal) out ofstorage). No electrical storage is considered.These values are within the range of actual valuesdescribed in chapter 4 for E/S ratios and efficien-cies for gas turbine or combined-cycle cogenera-tion systems, which are or will be applicable inthe commercial sector (see table 23).

Sample Regions. –OTA chose three sampleutility regions based on the technological andoperational assumptions mentioned above andon data from the regional electric reliability coun-cils. Region 1 is typical of areas with utilities thathave a large percentage of oil-fired steam genera-tion, high reserve margins (over 40 percent), anda relatively moderate annual growth in electric-ity demand of 1 percent (such as the NortheastPower Coordinating Council). The summer andwinter peaks for Region 1 are about equal. Region2 is typical of summer-peaking regions with most-ly nuclear or coal baseload capacity, a higher an-nual load growth than in Region 1 (2 percent),but lower reserve margins (26 percent) (e.g., theMid-America Interpool Network). Region 3 istypical of areas with large reserve margins (over40 percent), relatively high load growth (3 per-cent), and large amounts of gas-fired steam gen-eration (such as the Electric Reliability Councilof Texas). Region 3 is also summer-peaking. (Seefig. 8 for the location of each of these regions ofthe North American Electric Reliability Council.)

● Measured in megawatts, i.e., 1 MW (thermal) = 3.412MMBtu/hr.

Table 40 summarizes the electrical demand andsupply characteristics of each region, normalizedto 1,000 MW.

Scenario DescriptionBased on the above demand and supply as-

sumptions, OTA used nine “standard scenarios”to investigate the effects of cogeneration on thesample utility regions for different cogenerationcosts (see table 41). These standard scenarioswere grouped into three sets to represent thethree utility regions. Each set has three differentscenarios: a base case in which no cogenerationis allowed and only utility powerplants are used,and two cogeneration cases using higher andlower capital costs of the cogenerators. As men-tioned previously, the scenarios also originally in-cluded two sets of fuel prices. However, the re-sults of the analysis varied by less than 2 percentbetween the higher and lower prices, and onlythe results for the lower prices are reported here.

In addition, five special scenarios were for-mulated to investigate the effects of limiting theaddition of baseload capacity and of using a zerocapital cost cogenerator. Not all possible combi-nations of regions and cogeneration capital costswere made for these five special scenarios be-cause OTA was primarily interested in observingthe sensitivity of the standard set of scenario as-sumptions to particular situations, rather thanmaking complete inter-regional comparisons.Table 41 identifies these special scenarios andtheir distinguishing assumptions.

Commercial Cogeneration Opportunities

The DELTA model described above choosesamong the varying technological, financial, andother assumptions to find the minimum total cost

Table 40.-Sample Utility Configurations

Annual 19601960 capacity installed (MW) Electrical peak reserve

Region Base Intermediate Peak Total demand growtha in margin740 150 1,390 1% Summer, winter 39%

2500

1,020 o 237 1,257 2 % Summer 26°A3 265 1,107 5 0 1 , 4 4 2 3%0 Summer 4 4 %

aAnnual growth in both electrical peak demand and total energy demand.



Table 41.—Description of Scenarios Used

Standard scenarios:l-NO COGEN1-HIGH COST COGENl-LOW COST COG EN2-NO COGEN2-HIGH COST COGEN2-LOW COST COG EN3-NO COGEN3-HIGH COST COGEN3-LOW COST COG EN

Special scenariosl-NO COGEN/COAL-LIMITEDl-LOW COST COGEN/COAL-LIMITED2-ZERO COST COGEN3-NO COGENI/OAL-LIMITED3-LOW COST COGEN/COAL-LIMITED

Region 1, base case/no cogeneratlon allowedRegion 1, high capital cost cogenerationRegion 1, low capital cost cogenerationRegion 2, base case/no cogeneration allowedRegion 2, high capital cost cogenerationRegion 2, low capital cost cogenerationRegion 3, base case/no cogeneration allowedRegion 3, high capital cost cogenerationRegion 3, low capital cost cogeneration

Region 1, coal-fired baseload capacity limit, no cogenerationRegion 1, coal-fired baseload capacity limit, low capital cost cogenerationRegion 2, zero capital cost cogenerationRegion 3, coal-fired baseload capacity limit, no cogenerationRegion 3, coal-fired baseload capacity limit, low capital cost cogeneration


of providing electric and thermal energy in eachscenario. The model results are not predictionsabout future utility behavior—rather, they repre-sent what might happen under the conditions andassumptions used to specify the scenario. Byanswering these “what-if” types of questions, themodel can provide valuable insights about theinteraction of cogeneration with the existing cen-tralized utility systems.

Capacity Additions andOperating Characteristics

In order to analyze the addition of cogenera-tion capacity and its effects on utility systemoperations, OTA determined, first, whether aminimum-cost capacity expansion plan would in-clude significant amounts of cogeneration, andsecond, how the cogeneration equipment thatis added is used to supply electric and thermalenergy.

COGENERATION CAPACITY

To see if cogeneration capacity would be eco-nomically attractive compared to central stationgeneration for our set of assumptions, OTA com-pared the electric generating capacity additionsfor the base-case scenarios–in which no cogen-eration is allowed—with the scenarios in whichcogeneration can be added. Figure 55 summa-rizes these capacity addition comparisons for thenine standard scenarios.

The results show that the greatest opportunityfor cogeneration occurs when the match be-tween thermal space heating and electricaldemands is the closest. Thus, the largest propor-tion of cogeneration capacity is added in Region2, which has the highest thermal demand of thethree regions. Region 3, on the other hand, addsmore total capacity (cogeneration and central sta-tion) because it has the largest growth in elec-tricity demand, and because it has a large pro-portion of existing gas-fired capacity that can bereplaced by less expensive coal-fired units. Withour assumptions, therefore, commercial cogen-eration in new buildings is competitive with cen-tral station technologies only when there is asignificant need for space heating and at least amoderate growth in electricity demand. Coal-fired capacity is cheaper than new cogenerationcapacity when electricity is needed but very lit-tle or no heating is required. Coal is cheaper be-cause of the difference in fuel prices, and thatdifference dominates any other cost of installingor operating the technology under our assump-tions.

One way to test this result is to vary the capitalcost of the cogenerator. By going to the extremecase of zero capital cost, the limit of cogenera-tion penetration can be shown under our fuelcost assumptions. * We ran this case for Region

*This analysis also provides a rough approximation of what mighthappen by keeping the capital cost unchanged but lowering naturalgas fuel prices.


Figure 55.–Elactrical Capacity Additions 1990-200@Baseload Peak Cogeneration

I Low

aFor 1990, scenario l–LOW-COST COGEN/COAL-LIMITED.


2 (abbreviated as 2-ZERO COST COGEN), andfound that the cogeneration technology wasmore competitive with the coal baseload capacityand more cogeneration was installed than in theother cogeneration scenarios for Region 2. How-ever, the amount of electricity produced from thecogeneration did not increase significantly (seethe discussion on costs below).

In another set of special cases, the amount ofcoal that could be used for central station capaci-ty was restricted. This constraint had two pur-poses. First, it simulated conditions where coalburning may be prohibited or severely restrictedfor environmental, availability, or other reasons.(This assumption also simulates the case wherenuclear would serve as the baseload and it, too,would be restricted.) The second purpose wasto examine the effect of much higher coal pricesrelative to natural gas and oil. This method(restricting coal use) is not as satisfactory as car-rying out model runs with different fuel price tra-

jectories and ratios, but will serve qualitativelyto show how higher coal prices would benefit oil-or natural gas-fired cogeneration.

In Region 1, no baseload plants were allowedto be added through 2000, while in Region 3,baseload capacity additions through 1990 werelimited to a small percentage of the total existingbaseload capacity, while no limits were placedon additions from 1990 to 2000. Two scenarioswere run for each region: a new base-case inwhich only central station equipment was added(abbreviated l-NO COGEN/COAL-LIMITED and3-NO COGEN/COAL-LIMITED, for Regions 1 and3 respectively) and a cogeneration case (ab-breviated l-LOW COST COGEN/COAL-LIMITEDand 3-LOW COST COGEN/COAL-LIMITED).Table 42 summarizes the capacity additions forthese four scenarios.

Table 42 shows that the limits on baseloadcapacity additions increase the economic attrac-tiveness of cogeneration in both regions. For ex-

Ch. 5—lndustrial, Commercial, and Rural Cogeneration Opportunities ● 201

Table 42.—New Capacity Installed for Coal-Limited Scenarios

Total electrical Proportion of new electricalcapacity installed capacity installed (o/o)

Scenario (MW) Base Peak Cogeneration

l-NO COGEN/COAL-LIMITED 15 — 100 —l-LOW COST COGEN/COAL-LIMITED 62 — o 1003-NO COGEN/COAL-LIMITED 1,192 100 03-LOW COST COGEN/COAL-LIMITED 1,363 63 0 17NOTE: “-” means assumed zero input for this scenario.


ample, 3-LOW COST COGEN/COAL-LIMITED in-stalls 77 percent of its total capacity as cogenera-tion while the standard Region 3 scenarios(3-HIGH COST COGEN, and 3-LOW COSTCOGEN) install at most 4 percent.

These results demonstrate the competition be-tween cogeneration and central station coal-firedcapacity to meet new electricity demand. Bothcapital and operating costs of the system and thethermal demand determine this choice. If newcoal-fired capacity is sufficiently inexpensive,even in the face of the efficiency advantage ofcogeneration, coal will provide electricity andconventional oil- or gas-fired space heaters willprovide thermal energy for these new buildings.Further, if excess electric generating capacity ex-ists, the ability of cogeneration to penetrate thecommercial market may also be limited, even ifcogeneration is less costly than new, coal-firedcentral station generation. Electricity from the ex-isting capacity, because of its sunk capital cost,is usually cheaper than that produced by new,more efficient cogeneration if the latter is con-fined to premium fuels. In some cases, however,economics may still favor cogeneration, particu-larly if the existing central station capacity is oilfired and near retirement. In some markets whereretirement would be desirable in the next fewyears, cogeneration from natural gas-fired unitscould be the only means of replacement capacity,whether coal-fired generation is permitted or not.We will discuss this further below.

COGENERATION OPERATION

The above results on cogeneration capacity areexplained by the details of how the electrical andthermal loads are met. OTA calculated the elec-trical capacity factor (the ratio of time a generator

actually supplies power to the time the plant isavailable for service) for both the cogenerationand the baseload capacity in each of the sce-narios. Table 43 shows the electrical capacity fac-tors calculated by the model for both the stand-ard and coal-limited scenarios. Most of the base-Ioad capacity operates 66 to 70 percent of thetime, while the cogenerators operate less than30 percent of the time. * The low load factor forcogeneration results from its inability to generateelectricity that is competitive with central stationelectricity even though cogeneration is moreenergy efficient. This is a result of our assumedfuel prices. As we shall see, the DELTA modelonly operates cogenerators when the electricityis needed to meet intermediate or peaking de-mands that otherwise would be supplied by oil-fired utility units. The higher fuel prices of theseutility units, combined with the high overall effi-ciency of the cogenerator, allows the latter tocompete economically in the market for in-termediate and peaking power. When coal is pro-hibited, the thermal and electrical capacity fac-tor of the cogenerators increases from 30 percentor less to over 50 percent. In this case, the cogen-erators are also supplying a small amount of base-Ioad electricity. This is because the cogeneratorscan supply power less expensively than othertypes of central station generation when coal-firedadditions are limited.

However, these capacity factors only indicatethe most general performance of each type ofequipment. in order to provide a more completedescription, we need to observe, for each sce-nario, the hour-by-hour dispatching schedule (for

*For the cogenerator, this is also the thermal capacity factor sincethe unit is producing both electricity and thermal energy while itoperates.


Table 43.-Capacity Factors for Baseload and Cogeneration Plants

Baseload plants Cogeneration plants1990 2000 1 9 9 0 2 0 0 0

Standard scenariosl-NO COGEN . . . . . . . . . . . . . . . . . . . . . . . . . . . 69 681-HIGH COST COGEN . . . . . . . . . . . . . . . . . . . . 69 68

—— 27

1-LOW COST COGEN . . . . . . . . . . . . . . . . . . . . 70 69 31 292-NO COGEN . . . . . . . . . . . . . . . . . . . . . . . . . . . 66 67 —2-HIGH COST COGEN . . . . . . . . . . . . . . . . . . . .

—70 10

2-LOW COST COGEN . . . . . . . . . . . . . . . . . . . . 66 68 7 133-NO COGEN . . . . . . . . . . . . . . . . . . . . . . . . . . . 69 683-HIGH COST COGEN . . . . . . . . . . . . . . . . . . . . 70 68 21 203-LOW COST COGEN . . . . . . . . . . . . . . . . . . . . 70 69 21 21Baseload-limlted-scenarlosl-NO COGEN/COAL LIMITED . . . . . . . . . . . . . . 80 80 —l-LOW COST COGEN/COAL-LIMITED . . . . . . . 80 80 58 533-NO COGEN/COAL-LlMlTED. . . . . . . . . . . . . . 80 673-L0W C0ST COGEN/COAL-LlMlTED . . . . . . . 80 69 95 7Note:”—” means no cogeneratlon was Installed by the model, elther due to economics of the model or because of input

es zero for the base-case scenarlos. Capacity factors are calculated for each plant type as follows:

MWh Supplied x 100(MW installed + existing MW) x 8,760 hours


both cogenerators and central station generators)for each of the eight different types of “typical”days used in the analysis. Figures 56 and 57 pre-sent the space heating and electric demands, re-spectively, and show how each technology isdispatched to meet these demands for 1 day(winter peak which occurs six times a year) in1990 for scenario 1-LOW COST COG EN/COAL-LIMITED.

Figure 56 shows that, during the 1990 peakwinter day, the cogenerators provide about 37MW of heat to meet thermal demands that varybetween 30 and 78 MW. During this peak day,the cogenerators operate 95 percent of the time.Thus, seen from the perspective of a commer-cial building owner, cogenerators operate as a“baseload” heating system during winter peakdays.

Figure 57 shows the electrical demands for thesame 1990 winter peak day. Note that the co-generators only contribute to the peak and inter-mediate load. The small numerical value of thesecontributions is partly due to our assumptions ofzero thermal demand and 1,000 MW of electricaldemand for 1980. If a larger thermal demand hadbeen assumed and retrofits considered, the elec-tricity contribution of the cogenerators would

have increased substantially, although it wouldstill be confined to the peak and intermediateload. What is important here, however, is not theabsolute value of the electrical contribution bycogeneration, but rather what portion of the elec-trical demand it can supply economically com-pared with other options.

RETROFIT OPPORTUNITIES

As discussed above, existing buildings (henceexisting thermal demands) were not included inthis analysis. This rules out cogeneration retrofitsand thus the analysis understates cogeneration’scontribution to the total electric load. It is there-fore important to discuss the factors that willinfluence the choice of whether to install a cogen-eration system in an existing building. In addi-tion to the considerations about economic com-petition with new central station electric generat-ing capacity, the major constraints to retrofittingare excess central station capacity, the uncertain-ty about natural gas prices and availability, andthe difficult financial conditions brought aboutby high interest rates and short loan terms.

The first constraint, excess capacity, has the ef-fect of keeping the price of electricity well belowits marginal cost in most regions of the country


Figure 56.—Thermal Supply and Demand for Winter Peak Daya


Time of day

aFor 1990, scenario 1- LOW-COST COGEN/COAL-LIMITED.


Figure 57.–Electricity Supply for Winter Peak Day


Time of day

aFor 1990, scenario 1 - LOW-COST COGEN/COAL-LIMITED.



and thus to force payments for cogeneratedpower under PURPA to be determined by fuelsavings alone (i.e., no capacity credit). Both actas an incentive for building owners to continuepurchasing all their electricity from the utility.New buildings have a similar incentive–as themodel results have demonstrated. In the case ofexisting buildings the incentive is even greater,however, because of the sunk costs of existingheating equipment and interconnection with theutility. Where current prices exceed marginalcost, as would likely be the case if oil is the domi-nant fuel used to generate electricity and the fu-ture capacity would be coal-fired, shortrunPURPA payments based solely on fuel savingscould be high, stimulating cogeneration invest-ment. More will be discussed on this below.

The second constraint, uncertainty about fuelprices and availability, is important because nat-ural gas is the most likely fuel for commercialcogeneration retrofits for the next several years.As discussed earlier, the price of natural gas willincrease, but it could still be low enough to makecogenerated electricity and thermal energy (usinga combustion turbine, diesel, or combined-cyclesystem) cost less than a combination of electricityproduced from central station generators and anindividual heating plant. Gas prices also couldbe much higher, perhaps as high as distillate fueloil, which would make potential retrofits too cost-ly in most cases. In the latter case, the resultswould be similar to those obtained for new con-struction as given by the model. The price atwhich natural gas-fired cogeneration is competi-tive with electricity depends primarily on the sizeof the facility, the credit obtained for displacingnatural gas or oil used for space heating, the fi-nancial conditions available to the prospectiveowner, and the thermal load factor of the build-ing. Capital and O&M costs per unit output in-crease as the facility size decreases, lowering thenatural gas prices required for breakeven withelectricity. The displacement credit depends onthe amount of fuel saved from the displacedspace heating unit, and the cost of hooking upthe cogeneration unit. The thermal load factorwill determine the amount of electricity that canbe produced assuming the cogeneration unit op-erates to supply baseload thermal demand. The

Photo credit: OTA staff

Some older commercial buildings could be retrofitted forcogeneration, but the economics of such retrofit will dependon the price of electricity and the price and availability of

cogeneration fuels—primarily natural gas

analysis of this point is similar to that describedabove for the new buildings.

As an example of these considerations, we ex-amine a combined-cycle cogeneration unit ofabout 10 MW (a size typical for a very largebuilding), operating to supply 50 percent of abuilding’s heat load. Further, if this unit canoperate at a high electric load factor of 85 per-cent or more, this unit could produce electricitythat would compete with central station electric-ity priced at 5cents/kWh if natural gas cost $4.50/MMBtu or less (all in 1980 dollars) (34). * The na-

*This calculation assumed a value for the capacity factor in orderto determine a breakeven natural gas price. In actual operation itis the other way around. Under the conditions that the buildingowner’s goal is minimum cost and that the cogeneration unit is sized


tional average price of natural gas in the commer-cial sector commercial sector for the third-quarterof 1981 was about $3.50/MMBtu. Therefore thecombined-cycle system described above appearsto have a definite economic advantage for regionswhere electricity is selling for 5cents/kWh or greater.

There is another set of conditions that wouldallow natural gas-fired cogeneration to be eco-nomically competitive even if the price relation-ships just calculated do not hold. If the price thatutilities must pay to cogenerators for power is sethigh enough by the State public utility commis-sion, then cogeneration would be installed evenif its electricity production costs were greater thanthe retail price for electricity. Further, dependingon the purchase power price under PURPA, co-generated electricity from a natural gas unit couldcost more than new, central station coal-firedgeneration and still be economically preferableto the latter. In California, for example, the pur-chase price is based on the cost of oil-fired gen-eration. Many industrial and commercial estab-lishments see this as a very attractive opportunitybecause their natural gas prices are below the fueloil prices paid by the utility. Therefore, thesecogenerators are willing to enter into agreementswith utilities in California to sell them electricityfor the next 5 to 10 years.

Even though natural gas prices will increase andprobably surpass those of residual oil during thatperiod, the cogenerators will still receive a highreturn because of their higher overall efficiencies.Further, the utilities will be able to replace cur-rent oil-fired capacity more quickly than by moreconventional means—i.e., coal or nuclear cen-tral station. For the period beyond 1990, how-ever, coal-fired, central station capacity is plannedand probably will be cheaper than natural gas-

to supply baseload thermal energy, cogeneration would be operatedwhenever it can produce electricity at a cost less than or equal tothe combined cost of central station electricity and separate ther-mal energy production (e.g., a conventional building heating sys-tem). The former cost depends on the price of the fuel for cogenera-tion (natural gas in this case), various financial parameters (interest,taxes, debt/equity ratio, etc.), and O&M costs. The cogenerationunit must be sized to provide baseload thermal energy becausethe cost of electricity alone from the cogenerator will nearly alwaysbe greater than the cost of electricity from a central station plantdue to economic and efficiency reasons. It is therefore necessaryfor the cogenerator to be able to displace building heating fuel andobtain a cost credit in order to meet the minimum cost criteria.

fired cogenerated electricity as the ultimate re-placement for the existing oil-fired capacity. How-ever, successful coal gasification with combined-cycle generation could alter the economics backto favoring cogeneration. More is discussed aboutthis last point below.

The California case is not typical of fuel oil de-pendent utilities, primarily because such utilitieslocated in other States usually can purchase pow-er from neighboring utilities with an excess of coalor nuclear power. In California, power purchasesgenerally are not an option because of limitedtransmission interties with other systems. TheCalifornia case does, however, point out the po-tential for natural gas-fired cogeneration in thenext 10 years. We have also not calculated thatpotential for new buildings since that analysisdetermines longrun generation needs only (hencelongrun avoided costs).

The final point about cogeneration’s potentialin existing buildings concerns the financing con-ditions currently available to prospective cogen-eration owners. Financial factors will help deter-mine the cost of electricity and thermal energyfrom a cogenerator. The current high interestrates and short loan terms available to non utilityinvestors for investments in building energy sys-tems are acting to severely limit cost effective in-vestments of any type—conservation or cogen-eration.

In a study released by OTA, Energy Efficiencyof Buildings in Cities (18), these current financialconditions are partially responsible for keepingabout 60 percent of the otherwise cost-effectiveconservation retrofits identified in that study frombeing installed. Although OTA did not examinecogeneration in this same way, it is likely thatcogeneration retrofits will be affected similarly,perhaps even more so because of the much high-er initial investment levels per building neededfor cogeneration than conservation. This is oneplace where utility or third-party ownershipwould be potentially very helpful. In the formercase, utilities would be able to secure longer termloans at lower interest rates than commercial in-vestors. In addition, utilities possess the engineer-ing skills needed to install and hook up the units.Utilities currently are prohibited from owning

206. Industrial and Commercial Cogeneration

more than so percent of a cogeneration unit andstill qualifying for PURPA benefits.

Aside from this legal barrier, however, a poten-tially more important one exists as a result of thelow thermal load factors in individual buildings.Because of this, cogeneration that supplies base-Ioad thermal demand to these buildings may notproduce excess electricity for sale to the grid.Unless such electricity is produced, utilities can-not be expected to invest in commercial cogen-eration. Raising the load factor, for example, bysupplying clusters of buildings (each with differentload patterns), would be one way to eliminatethis problem. Finally, third-party ownership withlease arrangements may also be promising be-cause of the provisions of the new tax laws.

Although we have not attempted to project theretrofit potential for cogeneration, it is probablethat movement in that direction will be tentativefor the next few years, primarily due to unfav-orable financial conditions. Even should interestrates and loan terms ease in the near future, how-ever, there still will be competition with conser-vation investments, which will reduce the techni-cal potential for cogeneration in a given building.Further the uncertainty over natural gas is likelyto remain until resolution of pricing policy andelimination of end-use restrictions (the Fuel UseAct, see ch. 3). Once these conditions arecleared, however, and if natural gas prices arelow enough, or purchase power rates are highenough, there could be considerable interest andactivity in cogeneration retrofits in the last halfof the 1980’s. If new technologies that can usesolid fuels—through gasification-are successfullydeveloped by then, further stimulus would exist.

Fuel Use

In addition to investigating the changes in utilitycapacity additions and operating characteristicsthat might result from cogeneration, OTA alsoanalyzed the change in proportion of fuels usedin the sample utility regions to determine ifcogeneration would displace any oil or gas. Asmentioned earlier, the analysis assumes that allcogeneration equipment uses distillate fuels inRegions 1 and 2 and natural gas in Region 3. Theresults of the calculations of fuel consumption in1990 and 2000 for the “no-cogeneration” stand-ard scenarios are shown in table 44.

Not all scenarios are shown in table 44 becausethe total fuel used and the proportion used byeach fuel type are similar between the base-case(“NO COG EN”) and the cogeneration scenariosfor each region. Cogeneration accounts for lessthan 1 percent of the total fuel used in all cogen-eration scenarios, and the total fuel and propor-tionate fuel use change less than 1 percent be-tween the two types of scenarios. As expectedfor our fuel price and use assumptions, becausecogeneration cannot compete with baseloadcoal-fired electricity, cogenerators operate onlya small fraction of the time (when they can supplyintermediate and peak demand electricity) andtherefore use only a small fraction of the total fuel.A further caveat is the exclusion of existingbuildings’ thermal demand, as explained earlier.

Because the model was restricted to the casewhere natural gas and distillate prices were equal,no results were obtained for the case when nat-ural gas prices fall low enough so that cogener-ated power could compete with central stationelectricity. OTA calculated this gas price, given

Table 44.-Base-Case Standard Scenario Fuel Use, By Generation Type and Year

Percentage of total fuel used Total annual fuelScenario Base Intermediate Peak Cogeneration Steam boiler use (10’2 Btu)1990l-NO COGEN 98 1 0 64.22-NO COGEN 97 0 0 2 62.53-NO COGEN 95 2 0 o 3 74.0

l-NO COGEN 97 0 0 2 69.32-NO COGEN 95 0 o 4 74.43-NO COGEN 94 1 0 o 5 95.1SOURCE: Office of Technology Assessment.


the set of costs and technical assumptions as wellas the average price of electricity determinedin our analysis (ranging from 3.3cents/kWh to 7.0cents/kwh). Using our assumptions of $575/kW capitalcost for the cogenerator, 0.8cents/kWh O&M cost,and an overall heat rate of 9,750 Btu/kWh withan 80-percent combined heat and electric powerefficiency, we can calculate the breakeven pricerange of natural gas. For a cogenerator capacityfactor of 0.85 this price ranges between $2.55/MMBtu to $8.40/MMBtu, which brackets the cur-rent commercial natural gas price of $3.50/MMBtu (in 1980 dollars). Again, the capacity fac-tor will be determined by the cost of electricityproduced by the cogenerator and, therefore, thecost of natural gas. This is a complex interactionbecause lower capacity factors reduce the fueldisplacement credit, thus increasing the net costof cogenerated electricity.

Similar arguments can be applied for the newtechnologies not considered in the model. Theability of these newer technologies to enter themarket depends ultimately on the cost of steamand power they produce. Currently a few systemsare being developed that will allow these coststo be estimated. One such system is the Cool-water combined-cycle, coal gasification systemrecently announced (1 1). Although that systemis being designed to supply electric power to theSouthern California Edison system, successfuldemonstration of the technology could lead theway to cogeneration applications. An unpub-lished analysis of the economics of the Coolwaterfacility as a cogeneration plant estimates an elec-tricity cost of about 3.6cents/kWh, including a creditfor heat recovery (fuel displaced by byproductsteam from the cogenerator) of about 4.6cents/kWh(34). This price for electricity is lower than themarginal cost of electricity from a new central sta-tion coal plant, although higher than the averagecost calculated in some of the cases of our analy-sis. The calculation, however, assumes a returnon equity that may be less than will be requiredof new plants such as the Coolwater facility. * In

● In the particular example cited, the return on equity assumedwas 10 percent along with a 50/50 debt-equity ratio and a real in-terest rate on debt of 3 percent. If we repeat the calculation witha 15 percent return on equity and a 5 percent real interest rate ondebt, values which we have found to be operative in favor of syn-fuels projects (21), the cost of electricity increases to 5.9cents/kWh.

addition, using such facilities for commercialbuildings entails the development of coal hand-ing, delivery, and storage facilities plus the needfor air quality control equipment. All will add ex-penses to these systems (which were not includedin the calculation cited above), and the questionof the economic attractiveness of these advancedcogeneration systems is still open. Biomass andurban solid waste have been proposed as fuelsfor gasification-cogeneration systems, and, insome cases, are under development. The eco-nomic analysis of these systems is similar to thatgiven for the Coolwater facility. One exceptionis that for proposed solid waste units, a credit isavailable in the form of the tipping fees usuallycharged to dispose of these wastes.

A recent development concerning biomasscogeneration is a combined-cycle system usinga direct-fired combustion turbine fueled by pul-verized wood. Using hot gas cleanup technologydeveloped in the British pressurized fluidized bedcombustion program, turbine blade damage isreduced to an acceptable level. A 3-MW test unitis currently being designed and built by the Aero-space Research Corp. of Roanoke, Va. Economicanalysis of this technology in a cogeneration sys-tem looks very promising and may be competitivewith coal-fired central station electric power (35).As with other systems described in this chapter,the economics are highly dependent on the elec-tric load factor. Consequently, they are more pro-mising for industrial sites then for buildings.

COAL-LIMITED SCENARIOS

While few changes in fuel use are observed in1990 and 2000 between the cogeneration andthe base-case standard scenarios, some changesdo occur in the special scenarios that limit coal-fired capacity additions (thus allowing other typesto operate more frequently than they would with-out these limitations). As mentioned earlier, fourspecial scenarios that limit baseload additionswere constructed: two allowing cogeneration andtwo restricting cogeneration. Figure 58 shows thatthe addition of cogeneration to the sample sys-

Utility financing, however, would allow a lower return even fora first-of-a-kind plant, perhaps close to that assumed in the originalcalculation. This argues in favor of utility ownership of suchcogeneration facilities.


Figure 58.— Fuel Used in 1990 and 2000

Baseload Intermediate

I

or Coal= Limited Scenarios

Thermalboilers Cogeneration

70

60

50

40

30

20

10

0NoCogen Cogen NoCogen Cogen NoCogen Cogen NoCogen Cogen

- - - 1 9 9 0 - - - - - - 2 0 0 0 - - - - - 1 9 9 0 - — — - 2000 — -

- - - - - R e g i o n 1 - - — - - - - - - - R e g i o n 2 — - — — —SOURCE: Off Ice of Technology Assessment.

terns decreases total fuel use when the cogenera-tion scenarios (I-LOW COST COGEN/COAL-LIMITED and 3-LOW COST COGEN/COAL-LIMITED) are compared to their respective base-case scenarios (l-NO COGEN/COAL-LIMITEDand 3-NO COGEN/COAL-LIMITED). This is a re-sult of two factors. First, there is considerablymore cogeneration that operates at higher capac-ity factors, as shown above. Second, this greaterpenetration allows the higher overall fuel efficien-cy of cogeneration to significantly affect total fueluse.

Most of the decrease in overall fuel use in thecoal-limited scenarios (when 1- and 3-LOW COSTCOGEN/COAL-LIMITED are compared to 1- and3-NO COG EN/COAL-LIMITED, respectively) re-sults from the decrease in fuels used by the in-termediate electric generating capacity. While thebaseload coal consumption remains identical be-tween the base-case and the cogeneration sce-

narios, the efficiency of the cogenerators, com-bined with the reduction of intermediate capacitygeneration, reduces overall fuel used for the twospecial coal-limited cogeneration scenarios. Table45 compares the use of oil and gas for the fourcoal-limited scenarios.

In summary, cogeneration has only a small ef-fect on utility fuel use as long as electricity canbe produced more cheaply with other types oftechnologies. However, in the special coal-lim-ited scenarios, cogeneration may cause less totaloil to be used and may displace fuel used by theintermediate capacity.

Sensitivities to Changes in AssumptionsIn addition to analyzing fuel use and operating

characteristics with and without cogeneration, wemust also determine the sensitivity of this analysisto changes in some of the assumptions used in


Table 45.-Comparison of Fuel Use for Coal-Limited Scenarios

Region 1 coal-limited Region 3 coal-limitedscenarios (net change scenarios (net change

in percenta) in Percenta)

1990 2000 1990 2000

Total fuel . . . . . . . . . . . . . . . . . . . . . . . – 1 – 2 –7 –1Total residual . . . . . . . . . . . . . . . . . . . – 6 – l o —Total distillate/natural gas . . . . . . . . +155 + 121 –13 +3Total oil . . . . . . . . . . . . . . . . . . . . . . . . – 3 – 5 –13 +3aA negative change means that the coal-limited cogeneratlon scenarios use less fuel than the no Cogeneration coal-limited

scenarios; a positive change means that the cogeneratlon scenarios use more fuel. All fuel is measured In Btu-equivalents.


the scenarios. One important assumption is thecost for installing and operating cogenerators. Asmentioned above in the discussion of capacityadditions, OTA formulated a scenario, 2-ZEROCOST COG EN, that uses zero capital cost cogen-erators for Region 2.

The sensitivity of our results to the costs ofcogeneration is determined by comparing thetypes of capacity that are installed and how theutility system uses cogeneration for two scenarios:the 2-ZERO COST COGEN scenario with the2-LOW COST COG EN scenario. While the ZEROCOST scenario installs 81 percent of its capacityas cogeneration, the LOW COST scenario installs20 percent. Despite the difference in cogenera-tion capacity between the two scenarios, the fuelsconsumed by cogeneration are only 2 percentof the total fuels used in each scenario. In otherwords, for our fuel price assumptions, baseloadelectricity from coal is still cheaper so it is usedto meet the baseload demand. In the zero capitalcost case, however, cogenerators can supplythermal energy much more cheaply than boilers,so cogeneration is being used primarily to meetspace heating demands plus as much intermedi-ate and peak electricity demand as possible. Zero-capital cost cogeneration therefore is used as aninexpensive heater, without displacing any coal-fired generation. Thus, the cogeneration in thisscenario displaces some of the peakload equip-ment, and does not use its steam during peaksummer days.

Summary

By using the DELTA model and our set of tech-nical and economic assumptions, OTA was ableto determine the interaction of cogeneration with

several sample centralized utility systems. Undermost circumstances, cogeneration additions innew buildings were very limited because theycould not compete economically with central sta-tion coal-fired generation. As a result, fuel usagedid not change greatly from an all-centralized sys-tem. When coal-fired expansion was limited,however, cogenerators penetrated the utility sys-tem significantly and provided much of the heat-ing demands and peak and intermediate electric-ity for the system.

Three specific conclusions can be made fromthis analysis. First, given the assumptions, cogen-erated electricity cannot compete with centralstation, coal-fired capacity. Therefore, in com-mercial buildings, cogeneration will only contribute to peak and intermediate demands and willonly operate when it can supply such electricity.This holds for even a zero capital-cost cogenera-tor. Lower natural gas prices, however, couldgreatly increase the opportunity for cogeneration.in fact, natural gas prices somewhat above cur-rent gas prices would allow cogeneration to com-pete with new, baseload, coal-fired central sta-tion capacity. Alternatively, successful develop-ment of gasification technologies that can pro-duce moderately priced (about $5/MMBtu) medi-um-Btu gas from coal, biomass, or solid wastecould expand the competitive position of cogen-eration. Finally, cost relationships could be deter-mined by high utility purchase rates for cogener-ated power that would also make natural or syn-thetic gas-fired cogeneration preferable regardlessof the actual Iongrun marginal costs of new COA

fired capacity.

Second, existing electric generating plantsusually can provide power more cheaply than


new cogenerators. Even if oil is used for these fired central stations that are near retirement.plants, the cogenerator capital costs dominate Third, if oil- and natural gas-fired equipment isany gains from more efficient fuel use; and this used, the best opportunity for cogenerators is indomination results in little significant penetration regions with high heating loads (about 6,000 heat-of cogeneration. However, lower cost natural gas ing degree-days) and moderate electrical growthcould change these economics. In some regions (at least 2 percent annual growth in peak and totalthis is the case now where natural gas-fired co- energy).generation is the preferable choice to existing oil-

RURAL COGENERATIONAlthough industrial and commercial sector co-

generation opportunities are recognized widely,little attention has been paid to cogeneration ap-plications in rural areas, particularly in agriculture.The rural cogeneration potential is not so largeas in the industrial sectors, but could present fueland cost savings on farms or in rural communi-ties. The principal rural cogeneration opportuni-ties arise where there are existing small power-plants or where agricultural wastes can be usedas fuel. Promising cogeneration applications forrural communities include producing ethanol,drying crops or wood, and heating livestock shel-ters.

Small, rural municipal powerplants can gain sig-nificant economic and fuel conservation advan-tages with cogeneration if a market for the ther-mal energy is available. Many of these power-plants use reciprocating internal combustionengines or combustion turbines as their primemovers. Dual fuel engines predominate (generallyburning natural gas, with small amounts of fueloil to facilitate ignition), but diesel engines andnatural gas fueled spark ignition engines also arecommon. Generally, these small rural power-plants have a peak electric power rating of 10MW or less, and they operate at around 33 per-cent efficiency in producing electricity (i.e., 33percent of the fuel input energy is converted toelectricity and 67 percent is exhausted as wasteheat). If only half of the waste heat from theseplants were used, the energy output would dou-ble (IS).

Table 46 shows the distribution and maximumtemperature of waste heat sources in a super-charged diesel engine. As shown in this table,

Table 4&—Distribution of Waste Heat From aSupercharged Diesel Engine

Percent of Maximumtotal waste temperature

Heat source heat (Fo). ,

Engine cooling jacket . . . . . . . . 20 165-171Aftercoolers a. . . . . . . . . . . . . . . . 15 104-111Lubrication system . . . . . . . . . . 10 140-150Exhaust gasb. . . . . . . . . . . . . . . . 55 797-696aAftercoolers generally are used In temperate cllmates, with maximum

use occurring In the summer.bIn engines that are not supercharged, exhaust gas temperatures maybe cooler,

approximately 572° to 662° F.

SOURCE: Randall Noon and Thomas Hochstetler, “Rural Cegeneratlon: An Un-tapped Energy Source,” Public Power January-February 1981.

most of the waste heat is in the exhaust gases.The engine cooling jacket and lubrication systemtogether produce almost as much waste heat asthe exhaust gases, but at a much lower tempera-ture (15).

The hot exhaust gas from an existing power-plant fueled with natural gas can be used direct-ly in a waste heat boiler. Alternatively, water canbe preheated via heat exchange with the after-coolers, lubrication system, and cooling jacket,then flashed into dry steam through heat ex-change with the exhaust gas. Steam temperaturesas high as 850° F can be obtained in this man-ner (15).

For on-farm systems, a small powerplant (withdirect heat recovery or steam production, as de-scribed above) could be connected with an an-aerobic digester (using animal wastes as the feed-stock) producing biogas, or with a small gasifierthat converts biomass (e.g., crop residues) to low-or medium-Btu gas. However, as described inchapter 4, further development of combustionturbine or internal combustion engine technol-


ogy may be necessary if these systems are to oper-ate efficiently for long periods of time with low-or medium-Btu gas derived from lower qualityfeedstocks.

Potential Applications

Ethanol production is one promising applica-tion for rural cogeneration. Ethanol has beenshown to be a useful fuel for spark ignition en-gines, and it can be produced readily from renew-able biomass feedstocks (e.g., grains and sugarcrops). If ethanol is used as an octane-boostingadditive in gasoline, and if the ethanol is distilledwithout the use of premium fuels, then each gal-lon of ethanol can displace up to about 0.9 gallonof gasoline. However, if ethanol distilleries arefueled with oil, then ethanol production for gaso-hol could actually mean a net increase in oil use. *Moreover, the premium fuels usually consideredfor ethanol distilleries–diesel fuel and naturalgas–already are used widely in the agriculturalsector but often are in short supply. Using thesefuels in distilleries could aggravate any shortages.

One way to improve ethanol production’s pre-mium fuels balance is to cogenerate with existingsmall rural powerplants. The waste heat wouldbe flashed into dry steam (as described above),and the steam distributed into the distillation col-umns of the ethanol recovery system. To facilitatecooking (the process stage where starch grainsare ruptured for effective enzymatic action),steam above atmospheric pressure and at about300° F can be bled from the exhaust gas heat ex-changer. In addition, warm water can be bledfrom the aftercooler heat exhanger to soak themilled corn and speed up water absorption. Final-ly, heat for drying wet stillage into distillers driedgrain (which can be used as a livestock feed sup-plement) can be obtained either directly from theexhaust gas in a natural gas-fired plant, or by plac-ing an air-to-exhaust gas heat exchanger down-stream from the steam-producing heat exchanger(15). Figure 59 shows a schematic of ethanol co-generation with diesel engine heat recovery.

The waste heat from a 1 -MW powerplant oper-ating at full load (33o full-time operating days) is

*See Energy From Biological Processes (OTA-E-124; July 1980)for an in-depth analysis of ethanol production.

sufficient to produce around 600,000 gallons ofanhydrous ethanol per year with wet byproduct,or 300,000 to 400,000 gallons annually with drieddistillers grain byproduct (15).

Cogeneration also can be used for grain dry-ing, which requires relatively low-temperatureheat. Seed drying requires a temperature of ap-proximately 110° F, while milling drying requires130° to 1400 F depending on the crop, and ani-mal feed drying needs around 180° F. Thesetemperatures are well below those of exhaustgases, and thus, for grain drying, the exhaust gasof natural gas-fired powerplants can be mixedwith flush air and used directly (i.e., without heatexchangers). For plants that use fuels other thannatural gas, a heat exchanger may be requiredin order to recover the energy without contami-nating the grain with the exhaust gas. Due to thelow temperatures needed, waste heat from thecooling water or lubrication oil also can be recov-ered and used to dry grain (15).

The waste heat from a 1-MW powerplant coulddry grain at a rate of approximately 370 bushelsper hour. In the case of field-shelled corn, thiswould reduce the moisture content from around25 to about 15 percent—a safe level for storage.That grain-drying rate is comparable to that ofmany commercial dryers, and is sufficient for thegrain-drying needs of small communities (1 5).However, grain drying is a seasonal activity andother uses for the waste heat would have to be

Photo credit: Department of Agrlculture

Small existing powerplants can be retrofitted forcogeneration with the thermal output used for applications

such as drying grain


Figure 59.—Ethanol Cogeneration With Diesei Engine Waste Heat Recovery

Water

\ 1

Lubrication

Engine cooling jacket

!t

found in the off-seasons in order to optimize the

efficiency of the system.

In most cases, applying cogeneration to graindrying using existing powerplants will cost onlyslightly more than a conventional grain dryingfacility. A relatively small additional investmentwould be required for the engineering designneeded to interface the exhaust stacks (or heatexchanger) with the drier. The grain drying wouldneed flexible scheduling in order to coordinatewith the powerplant’s operation, especially whenexpected electricity demands do not materialize,but this is a relatively minor inconvenience. A

more important concern is that rural grain eleva-tors usually have low priority or interruptible serv-ice from natural gas suppliers (unless they usepropane). Any resulting shutdowns can be a seri-ous problem during a harvest season that is wetand cold, because the grain could spoil beforeit can be dried.

Drying crops with cogeneration can have signif-icant dollar and fuel savings advantages. If thecost of waste heat is set at so percent of the costper Btu for natural gas, then a facility drying 500bushels of grain per hour would save $11.25 perhour compared to the cost of using a separate

Ch. 5–industrial, Commercial, and Rural Cogeneration Opportunities ● 213

natural gas-fired dryer using $2.50/MCF gas forcontinuous operation, and the fuel cost savingswould amount to $7,000 per month (1 5).

Wood drying is similar in many respects tograin drying. Both commodities are dried priorto shipping to minimize moisture weight. Histor-ically, both drying processes have relied on rela-tively cheap and plentiful natural gas supplies,but can do so no longer. Furthermore, mostwood drying kilns, like grain drying facilities, re-quire relatively low-temperature heat–104° to117° F–although a few kilns may need tempera-tures above 212° F (1 5).

Because most modern wood drying kilns usenatural gas combustion units, the exhaust gasfrom a small powerplant can be substituted easilyfor the natural gas burner. A 1-MW powerplantwill produce approximately 8,000 MWh of usabledrying heat annually (based on 24 hours per day,330 days per year operation). This is sufficient todry as much as 11 million board feet of air driedhardwood or 6.5 million board feet of green soft-wood per year.

As with grain drying, substantial savings can begained through cogeneration/wood drying. Be-cause the basic design would not change in acogeneration retrofit, the capital and installationcosts of a cogenerating unit would not be sub-stantially more than those of a new conventionalgas-fired kiln. It is estimated that 2 to 5 MCF ofnatural gas would be saved for each 1,000 boardfeet of lumber that is dried with cogeneration.For the 1-MW powerplant drying 11 millionboard feet, this would mean a savings of 22000MCF/yr. If the cogenerated heat were sold at 50percent of the value of $2.50/MCF natural gas,$27,000 per year could be saved in fuel costs (1 5).Additional savings would accrue from the elec-tricity generation.

Fuel Savings

The three rural cogeneration applications de-scribed above—producing ethanol and dryinggrain or wood–rely on existing small power-plants fueled with oil or natural gas. In each case,fuel savings is assumed to result when the plant’swaste heat is recovered and substituted for a sec-

ond oil- or gas-fired facility. However, as dis-cussed earlier in this chapter, the fuel saved maynot always be oil. For example, recovering thewaste heat from a diesel oil fueled engine andsubstituting it for heat previously provided by anatural gas combustion unit will save gas but in-crease oil consumption. Similarly, if the wasteheat from a spark-ignition engine burning oil issubstituted for a boiler using coal or biomass, nooil would be saved.

As a result of these fuel use considerations, ruralcogeneration opportunities that use fuels otherthan oil (i.e., that do not rely on waste from anexisting powerplant) merit a good deal of atten-tion. These opportunities are based on the directfiring of cogenerators with fuels derived fromplentiful rural resources.

Wood wastes have long been the traditionalfuel in the forest products industry, which histor-ically has been the largest industrial—and rural—cogenerator. The cogeneration potential in theforest products industry was discussed earlier inthis chapter. At this point it will be sufficient tomention that, in the wood drying example citedabove, a steam turbine and boiler can be substi-tuted for the powerplant and natural gas-firedkiln. Although the capital costs of the boilersystem would be higher (about one boiler horse-power is needed to dry 1,000 board feet of hard-wood), and it would not produce as much elec-tricity, this system can burn wood wastes or coaland thus save oil or natural gas. Similarly, fuelsavings in ethanol distilleries will be greater if coalor biomass is used as the primary fuel for thecogenerator. Savings also can be achieved ingrain drying but the potential for contaminatingthe grain would be greater unless heat exchangerswere used.

Alternatively, internal combustion engines orgas turbines can be adapted to alternate fuels.These technologies, if successful, would requirea smaller investment for equipment than steamturbines, an important consideration for small dis-persed cogenerators. In some cases, fuel flexibilitycan be achieved through advanced engine de-sign, advanced combustion systems such as fluid-ized beds, or fuel conversion (synthetic gas or oil).The technical and economic aspects of using fuels

214 Industrial and Commercial Cogeneratlon

other than oil or natural gas in conjunction withcombustion turbines or internal combustion en-gines are discussed in detail in chapter 4. Twoapplications that are especially promising for ruralareas include gasification of crop residues andanaerobic digestion of animal wastes. However,small powerplants also can be modified to ac-commodate alternate liquid fuels such as ethanoland methanol, which can be made from relativelyplentiful rural biomass resources; these liquid fueloptions are discussed in more detail in OTA’sreport on Energy From Biological Processes.

Gasification of crop residues has been sug-gested as a means of providing relatively cheapnonpremium fuels for rural cogenerators. Onedemonstration project being developed in lowauses downdraft gasifiers to produce low-Btu gasfrom corn stover for use in retrofitted diesel en-gines. Some of the probable end uses for the ther-mal energy include grain drying, green houses,,dairies, food processing, space heating, or dry-ing the corn cob feedstock (22).

Downdraft gasifiers were selected for this proj-ect because they can generate producer gas thathas relatively low amounts of tars and other hy-drocarbons and is suitable for use in steam gen-erators, directly fired dry kilns, or internal com-bustion engines. Field tests with downdraft gasi-fiers in California have produced diesel qualityproducer gas successfully from corn cobs, walnutshells, and other crop residues (32).

The demonstration project focuses on station-ary diesel engines for several reasons. First, thewide number of domestic diesel models in placeallows a range of retrofit considerations to beevaluated. Second, a number of tests are under-way around the country using dual-fuel dieselsfired with 80 percent producer gas and 20 per-cent diesel oil. European firms have offered effi-cient commercial producer gas/diesel packagescapable of continuous operation on 90 percentgas/10 percent diesel oil since World War 1.Third, a large number of functional diesel power-plants are standing idle because of high oil prices.A recent survey showed that more than 70 lowacommunities have diesel generators with a totalcapacity of over 300 MW that operate at an aver-age capacity factor of less than 2 percent (22).

Finally, the projects will use corn cobs as thefeedstock because this is a relatively plentiful,clean fuel with a low ash and sulphur content.Moreover, they require no special handling (e.g.,baling, chopping) and they are easy to gather andstore. * Other possible biomass gasification com-binations for cogeneration include other types oforganic wastes (e.g., crop residues, wood waste)and wood from excess commercial forest produc-tion or intensively managed tree farms.

Cost estimates for this project are shown intable 47. Two rural test sites designed to demon-

*For an in-depth analysis of the technical, economic, and en-vironmental considerations related to the use of crop residues asa fuel or feedstock, see Energy From Biological Processes(OTA-E-124, July 1980).

Table 47.—Model Community Gasification/DieseiEiectric Generation Energy Cost Estimate

Operating data from the fuel rate calculations:Energy output: Maximum, 1,000 kW; average, 750 kWGas input for electrical powec 10.18 MMBtulhrSolid fuel input for electrical power: 1,810 Ib/hrFuel oil input for electrical power: 0.825 MMBtulhr at 7.5

percent of total energy input (5.9 gal/hr)

Costs-gasiWr plant:Equipment:

Gasifier system . . . . . . . . . . . . . . . . . . $259,610Installation . . . . . . . . . . . . . . . . . . . . . . 64,800Capital cost total . . . . . . . . . . . . . . . . . 324,410

Annualized at 5°/0 for 20 years . . . $33,670Diesel retrofit @ $150/kW . . . . . . . . . 150,000

Annualized at 8.25% for 20 yrs. . . 15,564Insurance at 2.5°/0 of plant cost . . . . 6,490

Total fixed costly r. . . . . . . . . . . . $55,724@ 6,570,000 kWh/yr, fixed cost = $0.0085/kWh

Operational cost6,570 hr/yr, operating at 75°/0 capacity:Fuel handler, 1 person, 40 hr/wk, w/fringes . . . . . 31,200Maintenance charge @ 5°/0 of plant cost . . . . . . . 16,200

Fuel costs:Diesel oil @ $1.15/gal x 38,716 gal . . . . . . . . 44,523Corn cobs at 18.80/T x 5,979 T/yr . . . . . . . . . 112,400

Total operational costs . . . . . . . . . . . . . . . . . . . . $204,3236.57 MMkWh/yr, operational costs/kWh = $0.0311

Total cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . .$O.0396/kWh

Cost of hot producer gas from gasifierOperating at 90°/0 capacity; with gas conversion efficiency

of 850/o1,810 lb cobs/hr x 8,760 hr x 0.90 = 7,135 T/yr @

$18.80~ = (fuel) . . . . . . . . . . . . . . . . . . . . . . . . $134,138Labor, maintenance, amortization, Insurance. . 87,560Total cost. .$221,698(7,135 T cobs x 15 MMBtu x 0.85

efficiency) = $2.441 MMBtuSOURCE: J. J. O’Toole, et al., “Corn Cob Gasification and Diesel Electric Genera-

tion,” in Energy Technology VIII: New Fuels Era Richard F. Hill (cd.)(Rockville, Md.: Government Institutes, Inc., 1981).


strate the technical and economic feasibility ofdowndraft gasifiers using corn cobs to producelow-Btu gas for diesels have been identified. Thesites (in Iowa) have different diesel models andusage patterns as well as different biomass re-source concentrations (one town has a localsource of excess corn cobs, one must set up acollection and transportation system on neighbor-ing farms). Thus, the sites will allow a sensitivityanalysis on a wide range of variables, includingenergy prices, Btu value, moisture content, farm-er participation rate, and cob processing costs.Economic modeling for the project will yield dataon agricultural production for the site, the quan-tity of cobs used, the system kWh costs, emis-sions, and energy balance. If these and other testsyield positive results, then gasification of cropresidues could become an important source ofenergy for diesel cogeneration in rural communi-ties—one that enables those communities to useexisting local resources and equipment at a costcompetitive with energy from central stationpowerplants.

A second rural cogeneration option is the an-aerobic digestion of animal wastes to producebiogas (a mixture of 40 percent carbon dioxideand 60 percent methane). The national energypotential of wastes from confined animal opera-tions is relatively low—about 0.2 to 0.3 Quad/yr–but other important benefits are that anaerobicdigestion also serves as a waste treatment proc-ess and the digester effluent can be used as a soilconditioner, or dried and used as animal bedding,or possibly treated and used as livestock feed.Digesters for use in cattle, hog, dairy, and poultryoperations are now available commercially andare being demonstrated at several sites in theUnited States. * Wastes from rural-based indus-tries (e.g., whey from cheese plants) also are be-ing used as a feedstock for farm-based digesters.

In a typical digester system (see fig. 60), a set-tling pond is used to store the manure prior todigestion. The digester consists of a long tank intowhich the manure is fed from one end. After sev-eral weeks, the digested manure is released atthe other end and stored in an effluent lagoon.

*For a detailed analysis of anaerobic digestion of animal waste,see Energy From Biologica/ Processes (OTA-E-1 24, July 1980).

Figure 60.-Anaerobic Digester System


Gas exits from the top of the digester tank, thesmall hydrogen sulfide content is removed if nec-essary, and the biogas is used to fuel an internalcombustion engine that drives an electric gener-ator. The system supplies electricity for onsite use(or for export Off-Sit@. The heat from the enginecan be used onsite for a variety of purposes, in-cluding heating the animal shelter or a green-house (that could also use the soil conditioningeffluent), or for crop drying, or even residentialspace heating.

Finally, it should be noted that the above appli-cations can be combined in farm energy com-plexes that integrate methane and alcohol sys-tems so that waste heat and byproducts are uti-lized more fully. For example, the waste heatfrom generating electricity with biogas can beused in alcohol production, while spent beerfrom the distilling process can be used as a di-gester feedstock. Moreover, the waste heat froma generator often is used to help maintain anoptimum digester temperature.

Summary

Significant energy and economic savings canbe achieved with cogeneration in rural areas.Communities can improve the economics of op-erating small powerplants by recovering wasteheat for use in distilling ethanol, drying grain or

wood; heating homes, greenhouses, or animalshelters, and other applications; or by retrofittingexisting powerplants to accommodate alternate

216 Industrial and Commercial Cogeneratlon

fuels. In addition, significant oil savings can be economy rather than being recirculated to pro-achieved if the cogenerator uses alternate fuels duce a second round of local income. Develop-or replaces two separate oil-fired systems. ing cogeneration opportunities could double the

Although the rural cogeneration potential is notproductive energy output of rural powerplants,creating significant local economic expansion in

so large as that in industry and urban applications, both public revenues (from electric and thermalthe cost and fuel savings can be very importantfor farms and rural communities. in rural econo-

energy sales) and private income (from new jobs)

mies, much of the gross income escapes the localwithout increasing the base demand of energy.

1.

2.

3.

4.

5.

6.

7.

8.

9.

10.

11.

12.

American Gas Association, An Energy and Eco-nomic Analysis of Gas-Fired Cogeneration in Com-mercial and Industrial Applications (Arlington, Va:American Gas Association, 1981).American Gas Association, The Gas Energy SupplyOutlook: 1980-2000 (Arlington, Va: American GasAssociation, January 1982).Bullard, Clark, University of Illinois at Urbana-Champaign, private communication to OTA.California Energy Commission, Commercial Sta-tus: Electrical Generation and NongenerationTechnologies (Sacramento, Calif.: California Ener-gy Commission, P102-8O-OO4, April 1980).California State Department of Water Resources,et al., Cogeneration Blueprint for State Facilities(Sacramento, Calif.: Department of Water Re-sources, March 1981).DOW Chemical Co., et al., Energy Industrial Cen-ter Study (Washington, D. C.: National ScienceFoundation, June 1975).Energy Information Administration, Analysis ofEconomic Effects of Accelerated Deregulation ofNatural Gas Prices (Washington, D. C.: U.S. Gov-ernment Printing Office, August 1981).Energy Information Administration, Annual Reportto Congress, Volume Two (Washington, D. C.:U.S. Government Printing Office, April 1981).Energy Information Administration, Typical Elec-tric Bills, January 1, 1980 (Washington, D. C.: U.S.Government Printing Office, December 1980).Exxon Corp., Energy Outlook 1980-2000 (Hous-ton: Exxon Corp., December 1980).“Gasification Plant Finds Private Aid,” The NewYork Times, Dec. 14, 1981.General Energy Associates, Industrial Cogenera-tion Potential: Targeting of Opportunities at theP/ant Site (Washington, D. C.: U.S. Department ofEnergy, 1982).

13.

14,

15.

16.

17.

18

19.

20.

21

22.

23.

Harkins, William, testimony before the New YorkPublic Service Commission, Case 27574, Nov. 10,1980.Mitchell, Ralph C., Ill, Arkansas Power & Light Co.,private communication to OTA, November 1981.Noon, Randall, and Hochstetler, Thomas, “RuralCogeneration: An Untapped Energy Source,” Public Power, January-February 1981.North American Electric Reliability Council, Elec-tric Power Supply and Demand 1981-1990(Princeton, N.J.: North American Electric Reliabil-ity Council, July 1981).Office of Technology Assessment, U.S. Congress,Application of Solar Technology to Today’s EnergyNeeds, OTA-E-66 (Washington, D. C.: U.S. Gov-ernment Printing Office, June 1978).Office of Technology Assessment, U.S. Congress,Energy Efficiencyof Buildings in Cities, OTA-E-168(Washington, D. C.: U.S. Government Printing Of-fice, March 1980).Office of Technology Assessment, U.S. Congress,The Future of Liquefied Natural Gas Imports,OTA-E-1 10 (Washington, D. C.: U.S. GovernmentPrinting Office, March 1980).Office of Technology Assessment, U.S. Congress,Residential Energy Conservation, OTA-E-92(Washington, D. C.: U.S. Government Printing Of-fice, July 1979).Office of Technology Assessment, U.S. Congress,Synthetic Fuels for Transportation, OTA-E-185(Washington, D. C.: U.S. Government Printing Of-fice, September 1982).O’Toole, J. J., et al., “Corn Cob Gasification andDiesel Electric Generation,” in Energy TechnologyV///: New Fuels Era, Richard F. Hill (cd.) (Rockville,Md.: Government Institutes, Inc., 1981).Resource Planning Associates, Inc., The Potentialfor Industrial Cogeneration Development by 1990


(Cambridge, Mass.: Resource Planning Associates,1981 ).

24. Resource Planning Associates, Inc., The Potentialfor Cogeneration Development in Six Major Indus-tries by 7985 (Cambridge, Mass.: Resource Plan-ning Associates, Inc., December 1977).

25. Rosenthal, Arnold, Consolidated Edison Co. ofNew York, private communication to OTA.

26. Schlesinger, Ben, American Gas Association, pri-vate communication to OTA.

27. Solar Energy Research Institute, A New Prosper-ity (Andover, Mass.: Brick House Publishing Co.,Inc., 1981).

28. SRI International, et al., Draft Environment/ Im-pact Statement, Small Power Production and Co-generation Facilities–Qualifying Status/Rates andExemptions (Washington, D. C.: U.S. GovernmentPrinting Office, FERC/EIS-0019/D, June 1980).

29. Synergic Resources Corp., Industrial CogenerationCase Studies (Palo Alto, Calif,: Electric Power Re-search Institute, EPRI EM-1531, 1980).

3 0

31

32

33.

34.

35.

Thermo Electron Corp., A Study of Inplant Elec-tric Power Generation in the Chemical PetroleumRefining and Paper and Pulp Industries (Waltham,Mass.: Thermo Electron Corp., TE5429-97-76,1976).U.S. Department of Energy, Month/y Energy Re-view (Washington, D. C.: U.S. Government Print-ing Office, February 1982).Williams, R. O., and Lang, R. C., “Fuel FromWaste Products,” Food Engineering October1979.Williams, Robert H., “Industrial Cogeneration,”3 Annual Review of Energy 313-356 (Palo Alto,Calif.: Annual Reviews, Inc., 1978).Williams, Robert H., Princeton University, privatecommunication to OTA, February 1982.Williams, Robert H., Princeton University, “Bio-mass Cogeneration as a Major Option in the Swed-ish Context, ” draft report, October 1982.

Chapter 6

Impacts of Cogeneration

.

Contents

PageEnvironmental Effects of Cogeneration . . . . . . 221

Characteristics of Cogeneration Systems andTheir Effects on Air Quality . . . . . . . . . . . . 221

Emissions Balances: Cogeneration v.Separate Heat and Electricity. . . . . . . . . . . 229

An Air Quality Analysis of Urban DieselCogeneration. . . . . . . . . . . . . . . . . . . . . . . . 231

Emission Controls. . . . . . . . . . . . . . . . . . . . . . 233Health Effects From Cogenerator

Emissions. . . . . . . . . . . . . . . . . . . . . . . . . . . 236Effects of Some Cogeneration Technology/

Fuel Options . . . . . . . . . . . . . . . . . . . . . . . . 238Policy Options: Removing Environment-

Associated Regulatory Impediments . . . . . 239Other Potential Impacts. . . . . . . . . . . . . . . . . 241

Potential Regulatory Burden onEnvironmental Agencies . . . . . . . . . . . . . . . 242

Environmental Permitting and EnforcementAgencies . . . . . . . . . . . . . . . . . . . . . . . . . . . 242

Potential Impacts on Agency Caseloads. . . . 244Summary. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 246

Economic and Sociall Implications . . . . . . . . . . 246Economic Impacts . . . . . . . . . . . . . . . . . . . . . 247Utility Planning and Regulation ., . . . . .*.* 254Other Economic and Social Impacts . . . . . . 257Centralization and Decentralization of

Electricity Generation . . . . . . . . . . . . . . . . . 259

Chapter 6 References . . . . . . . . . . . . . . . . . . . . 263

Tables

Table No.48. Effect of Cogeneration Characteristics on

Air Quality. . . . . . . . . . . . . . . . . . . . . . . . . . 22249. Uncontrolled Emissions of Competing

Combustion Technologies Using theSame Fuel, in Pounds/MMBtu Fuel Input . 223

50. Maximum Size Cogenerator NotRequiring New Source Review . . . . . . . . . 226

51. Selected Emissions Balances forCogeneration Displacing Central PowerPlus Local Heat Sources. . . . . . . . . . . . . . . 231

52.

53.

54.

554

56.

PageSummary of NOX Emission ControlTechniques for Reciprocating IC Engines . 234NOX Control Techniques that AchieveSpecific Levels of NOX Reduction . . . . . . . 235Costs of Alternative NOX Controls forDiesel Cogenerators . . . . . . . . . . . . . . . . . . . 235Emissions From Oil- and Coal-FiredDiesels . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 238Approximate Costs of proceduresRequired Under the Clean Air Act . . . . . . 240

57. Penetration Scenario for Cogeneration inCalifornia and Colorado . . . . . . . . . . . . . . . 244

58. Increase in Agency Workloads Due tothe Deployment of CogenerationTechnologies in Colorado. . . . . . . . . . . . . . 245

59. Increase in Agency Workloads Due tothe Deployment of CogenerationTechnologies in California . . . . . . . . . . . . . 246

.60. Market Penetration Estimates forCogeneration . . . . . . . . . . . . . . . . . . . . . . . . 248

61. Scenarios for Cogeneration

62

6364

Implementation . . . . . . . . . . . . . . . . . . . . . . . 249Assumptions Used to Compare Capita!Costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 250Comparison of Capital Requirements . . . . 251Assumptions Used in EstimatingOperating and Maintenance Costs. . . . . . . 251

65. Comparison of Operating andMaintenance Costs . . . . . . . . . . . . . . . . . . . 252

66. Comparison of Construction LaborRequirements. . . . . . . . . . . . . . . . . . . . . .. ..253

67. Craft Requirements for Central StationPowerplant Construction . . . . . . . . . . . . . . 254

68. Estimated Operating and MaintenanceLabor . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 254

69. Pacific Gas & Electric Cost StructureAdjusted for PURPA, 1990 . . . . . . . . . . . . . 256

Figures

Figure No..

61. CWE Fixed Cost Structure as a Functionof Sales Growth. . . . . . . . . . . . . . . . . . . . . . 256

Chapter 6

Impacts of Cogeneration

ENVIRONMENTAL EFFECTS OF COGENERATIONThe major environmental issue that has arisen

from the promotion and deployment of cogen-eration technologies concerns whether thewidespread use of cogeneration may lead eitherto improved or degraded air quality. This issueis especially critical in urban areas, where airquality may not be in compliance with nationalambient standards or where the allowable marginfor additional emissions may be small. A corollaryissue, also critical for urban areas, concerns therelative value of promoting cogeneration by eas-ing environmental standards. Examples of sug-gested regulatory changes designed to favorcogeneration include basing emission standardson energy output rather than (currently used) fuelinput, * and awarding emissions “offsets”**created by the cogenerator’s substitution ofcogenerated electric power for utility-generatedelectric power. Clearly, the issues are intercon-nected, because cogeneration’s effect on airquality will provide a powerful argument for oragainst any changes in environmental standards.

This analysis of the environmental effects ofcogeneration focuses on these air quality issues,with a final section devoted to other potential im-pacts (such as noise). First, cogeneration is char-acterized according to a list of attributes that af-fect air quality. These attributes are then dis-cussed qualitatively and, to the extent possible,quantitatively. Next, a series of cogeneration ap-plications are evaluated to determine their “emis-sions balances:” the net emissions increases ordecreases in the total system (the utility grid pluslocal heat and electricity sources), and the netchanges at the cogenerator site. Then, an evalua-tion of an existing air quality study of cogenera-tion is presented, followed by discussions of emis-

*Because a cogenerator produces more usable energy per unitof fuel consumed than a similarly sized electric generator using thesame technology, an output-based standard would allow the co-generator to emit more pollutants per unit of fuel consumed andthus incur lower pollution control costs.

**New sources attempting to locate in an area that has not at-tained Federal ambient standards must obtain pollution “offsets”(i.e., reduced emissions), from existing sources in the area so asnot to increase total emissions.

sion controls and the health effects of exposureto the major pollutants emitted by cogenerators.The air quality evaluation concludes with a dis-cussion of the potential air quality concerns as-sociated with advanced cogeneration technolo-gies and an analysis of some suggested policy op-tions for promoting cogeneration by easing en-vironmental regulations. The chapter ends witha discussion of other potential impacts ofcogeneration, including water discharges, solidwaste disposal, noise, and cooling tower drift.

Characteristics of CogenerationSystems and Their Effects on Air Quality

The deployment of cogeneration systems mayinvolve a number of changes in the physical char-acteristics of electricity generation and (useful)heat or steam production. These physical changesmay, in turn, alter the magnitude and dispersioncharacteristics of emissions from these activities.The result will be a change in air quality.

At a minimum, cogeneration will increase fuelefficiency by replacing separate devices produc-ing either electricity or thermal energy with asingle device providing both. Thus, less fuelwould have to be burned to produce the sameenergy. Cogeneration may involve merely the ad-dition of waste heat capturing equipment to ex-isting electric generators, or the addition of tur-bines to existing steam producers; in this case,cogeneration technology is different from onlyone of the separate technologies. However, manycogeneration systems use technologies differentfrom both the separate electricity generator andheat or steam producer. Cogeneration systemsgenerally are different in scale from separateelectricity and thermal energy systems; for virtual-ly all applications except simple additions ofwaste heat recovery equipment, they are smallerin scale than the central electricity generatingsystems they substitute for, and in many applica-tions they are larger in scale than the thermalenergy systems. Cogeneration systems often use

221

—


a different fuel from either or both systems theyreplace, and often they have a different loca-tion–usually closer to the electricity demandsource, at times slightly farther away from thethermal demand sources.

Table 48 summarizes the separate impact onair quality of each of these cogeneration charac-teristics, assuming all other factors remain thesame. For example, a reduction in fuel burnedwill lead to decreased emissions and improvedair quality if everything else remains the same.Usually, however, lots of things have changed.For example, the substitution of several smallcogenerators for a central power station mayimply:

●

●

●

●

●

fewer controls, because most regulations in-crease in stringency as size increases;lower stacks, which have greater impacts onground level air quality per unit of emission;dispersal of powerplant emissions sources–i.e., more sources with lower emissions fromeach separate source;different technology-e. g., diesels instead offossil boilers and gas-fired furnaces;use of a different fuel—e.g., diesel fuel usedinstead of coal and natural gas.

The complex mixture of effects in this exampleand in table 48 implies that cogeneration as ageneral concept cannot be characterized easilyas environmentally beneficial or adverse. A moredetailed exploration of cogenerator characteris-tics is necessary in order to identify those cir-cumstances where the environmental value of co-generation can be defined less ambiguously.

Increase in Fuel EfficiencyAs noted above, all near-term cogeneration ap-

plications involve the use of a fuel burning tech-nology that produces both electricity and ther-mal energy, and that substitutes for a separateelectric generator and thermal system. Althoughmost applications involve a change in the scaleof electricity generation (from central station toinplant generation) and many involve a basictechnology change as well (e.g., steam turbinesto diesels), combining the production of bothelectric and thermal energy in one unit createsa substantial energy savings by itself. For exam-ple, using a diesel cogenerator in place of a dieselelectric generator and an oil-fired furnace canreduce total fuel use by at least 25 percent ifthree-quarters of the potentially usable heat can

Table 48.–Effect of Cogeneration Characteristics on Air Quality

Effect on air qualityTechnological characteristic Direct physical effect (positive or negative)

1. Increased efficiency Reduction in fuel burned Positive2. Change in scale (usually Change in pollution control Negative for electrica

smaller for electric generation, requirements (stringency Positive for heatat times larger for heat/steam increases with scale)production) Change in stack height and Negative for electric

plume rise (increases with Positive for heatscale)

Changes in design, combustion Mixedcontrol

3. Changes in fuel combustion Changes in emissions Mixedtechnology production, required controls,

types of pollutants, physicalexhaust parameters

4. Change of fuels Change in emissions Mixedproduction, type ofpollutants

5. Change of location (most often Change in emissions density Mixedfor electric generation) and distribution—electric

power more distributed, heat/steam may become morecentralized

aThe air quallty effect of replacing the electric power component of the conventional system with the electric componentof the cogeneratlon ayetem is negative.

SOURCE: OffIce of Technology Assessment.

Ch. 6—Impacts of Cogeneration .223

be recovered* (11). Similar savings can beachieved by using a gas turbine cogenerator inplace of a gas turbine electric generator and aseparate furnace. Substitution of a steam electriccogenerator for a steam electric generator andseparate low-pressure steam boiler can reducefuel use by 15 percent (42).

Such substitutions may lead to substantial re-ductions in total emissions because they eliminateemissions from the heat source. For example, adiesel cogenerator could reduce sulfur oxide(SOX) emissions by about 0.1 Ib for every 100 kilo-watthours (kWh) of electricity it generated, bydisplacing oil heat using 0.2 percent sulfur dis-tillate oil. Similarly, a gas turbine cogeneratorcould reduce nitrogen oxide (NOX) emissionsfrom a displaced oil-fired industrial boiler by 0.3lb/loo kWh (see app. B for emissions informa-tion). In some cases, however, fuel used–andthus emissions generated—by the cogenerator toproduce thermal energy and electricity may begreater than for electricity generation alone, andtheoretically total emissions could increase if theseparate thermal system that is displaced werea particularly clean one. A coal or residual oil-fired steam turbine that was used for both elec-tricity and space or process heat, for example,would add to total SOX emissions if it replaceda similarly fueled electric generator and a separateheat system that used gas or low sulfur distillateoil.

Aside from any benefits attained by reducingemissions at the fuel combustion source, thecogenerator should be credited with environmen-tal benefits from the remainder of the fuel cycle—i.e., the benefits of extracting, refining, andtransporting less fuel. For example, reducing theuse of oil for heating is most likely to reduce theimpacts of importing and refining crude oil andtransporting the refined product from refinery tomarket area. These impacts include spills of thecrude and refined product and a number of pollu-tion problems generally associated with refineries.These benefits must be balanced by any negativeeffects related to increased fuel transportation re-quirements for multiple cogeneration units.

● The reduction is 27 percent assuming a heat rate for the dieselof 10,700 Btu/kWh, potentially recoverable heat of 4,300 Btu/kWh,furnace efficiency of 80 percent.

Quantification of these costs and benefits is notattempted in this report, but it is important notto forget that they exist. In fact, as the more ac-cessible fuel reserves become exhausted and ex-traction becomes more difficult and potentiallymore damaging, the magnitude of the potentialbenefits will grow.

Different Technology and FuelAlthough the alternative to a cogeneration sys-

tem can be the identical electricity generatingtechnology (without heat recovery) with a sep-arate thermal energy source (boiler or furnace),often a cogeneration system replaces a complete-ly different (usually large-scale centralized) elec-tric generation technology. A common exampleis a cogenerator with diesel or gas turbine tech-nology being used in place of electricity suppliedby a central oil- or coal-fired steam or nuclearsteam generating plant. Also, the smaller cogen-eration systems typically use cleaner fuels (dis-tillate oil or natural gas) than central station fossilplants (coal or residual oil). The technological andfuel differences both create sharp differences inemissions rates.

Table 49 displays typical levels of uncontrolledemissions from the three major competing cogen-eration technologies; the steam turbine alsorepresents the technology used in most centralstation powerplants. Although the same fuel isassumed, there are substantial differences inNOX and carbon monoxide (CO) emissions, andsmall differences in particulate and hydrocarbonemissions. The magnitude of uncontrolled SOX

emissions is not technology-dependent becauseessentially 100 percent of the sulfur in the fuelis converted to SOX regardless of the technology.

Table 49.—UncontroIled Emissions of CompetingCombustion Technologies Using the Same

Fuei, in Pounds/MMBtu Fuei input(using 0.2% sulfur distillate oil

N OX Particuiates CO HC SOX

Low-speed dieseia. . 3.48 0.07 0.91 0.10 0.20Gas turblneb. . . . . . . 0.90 0.02 0.04 0.20Steam turbinec. . . . . 0.16 0.01 0.04 0.01 0.20aBased on sales-weighted averages for large-bore dlesels, in Environmental pro-

tection Agency (39).bBased on Environmental Protection Agency (40) and particulate emissions data

from a GE 7821B combustion turbine.cBased on Environmental ProtectIon Agency (38).



A shift from central station electricity to dieselor gas turbine generation generally will be accom-panied by a substantial increase in NO-X emis-sions. CO emissions also will increase significantlywith diesel generation. As discussed later, how-ever, significant differences in efficiencies andemission rates among diesels and gas turbines ofdifferent sizes, configurations, and manufacturersmake it imperative that considerable caution beused in applying “average” emission factors andefficiencies to analyses of cogeneration impacts.

Aside from their relatively high levels of NOX

and CO emissions compared to alternative com-bustion technologies, diesel cogenerators face theadditional problem of producing particulate emis-sions that appear to have a possibility of causingadverse health effects because of their chemicalmakeup. The potential effects of these par-ticulate are discussed below in the section onhealth effects.

Diesel and gas turbine cogenerators must usecleaner fuels (primarily distillate oil or natural gas)than those burned in fossil-fueled powerplants(generally coal or residual oil), yielding emissionbenefits to the cogenerators. * Natural gas, for ex-ample, contains virtually no sulfur, and distillateoil may contain only 0.1 or 0.2 percent sulfurcompared with more typical 1 percent sulfurresidual oil and 1 to 5 percent sulfur coal; SOX

emissions are roughly proportional to thesepercentages. Although scrubbers will be used onnewer utility powerplants, substantial differencesamong technologies in expected SOX emissionswill remain.

Fuel choice is also important for particulate andNOX emissions, even though widely required par-ticulate controls may eliminate some of the dif-ferences for particulate. The differences in un-controlled industrial steam turbine NOX emis-sions for coal, oil, and natural gas are displayedbelow:

*However, if use of these fuels were supply limited, then theiruse by cogenerators would have to be balanced by the withdrawalof supply from an alternative combustion source. At the momentthere is no such limitation.

NO, emissions (lb/MMBtu) (38):*

Coal (bituminous) . . . . . .....0.60Oil (residual) . . . . . . . . . .....0.40Gas . , . . . . . . . . . . . . . . . . . . . .0.1 7

Because some large diesels (e.g., those inmarine applications) use residual oil, and othersare being developed that can use coal as well,some of these “clean fuel benefits” may disap-pear in the future as cogenerators begin to usethe same types of fuels as the powerplants theydisplace.

Finally, fuel choice dictates the costs and ben-efits associated with eliminating the environmen-tal effects of exploring for, extracting, refining andtransporting the fuel used in the (displaced) con-ventional system, and adding these effects for thecogenerator fuel. Although many cogenerationsystems use natural gas and oil, which may havefewer than or the same noncombustion environ-mental costs per unit of energy as fuels used incentral station powerplants, cogeneration systemsbased on steam turbines may use coal and dis-place oil and natural gas. In these cases, cogen-eration’s net environmental benefit associatedwith the noncombustion portion of the fuel cyclemay be negative even though total energy usagehas decreased, because of the relatively greateradverse impacts of coal mining and transporta-tion.

Change in Location and ScaleEven when fuel type, technology type, and ef-

ficiency are not considered, the substitution ofseveral smaller energy producers for one or a fewlarge producers can have substantial air qualityimpacts. Control requirements will vary with thesize of the equipment, resulting in changes intotal emissions, while the substitution of severalmore widely distributed, smaller smokestacks fora few large ones will change the dispersion ofthose emissions. Poor enforcement of controlcompliance for the dispersed system (due to themultiplicity of sources and the limited local en-

*Large commercial and general industrial boilers (10 to 100MMBtu/hr), bituminous coal heat content 25 MMBtu/ton.

Ch. 6—Impacts of Cogeneration . 225

forcement capabilities of regulatory agencies) alsomay affect air quality. Of course, to the extentthat the cogenerators may represent a centraliza-tion of heat production (e.g., in a total energysystem for an apartment complex that replacesmultiple small heating units), these effects maybe reversed.

In general, control requirements for energy pro-duction technology become more stringent assize increases. Many cogenerators will be con-trolled less stringently than utility generators usingthe same combustion technologies, but con-trolled more strictly than small heating systems.Examples of the effect of size on control require-ments for each cogenerator technology are:

New steam generators and steam turbinesmust comply with Federal New Source Perform-ance Standards (NSPS) only if they are larger than250 million Btu per hour (MMBtu/hr) fuel input(45). * Smaller units are subject only to local andState rules, some of which may not be so strin-gent. Furthermore, generators larger than thiscutoff are subject to different emission limitsdepending on whether or not they are utility-operated. New utility-operated steam generatorsmust achieve 90 percent SOX control for oil andfor medium to high sulfur coal, and 70 percentfor low sulfur coal, with an upper limit of 1.2lb/MMBtu input. In addition, they are restrictedto 0.03 lb of particulate per million Btu input.in contrast, new large steam generators used asindustrial cogenerators need achieve only 1.2 lbof SOX per million Btu input and 0.10 lb of par-ticulate per million Btu input.

New gas turbines with fuel rates greater thanabout 100 MMBtu/hr must achieve 75 ppm NOX

(about 70-percent reduction from uncontrolledlevels) under Federal NSPS, whereas turbines inthe 10 to 100 MMBtu/hr range need reach only1 so ppm (40-percent reduction) (46). The iatterstandard does not go into effect until about 1983.Gas turbines smaller than 10 MMBtu/hr are sub-ject only to State and local regulations (if any),although gas turbines in this size range current-ly do not appear to be a likely technologicalchoice for cogeneration applications.

*Equivalent to about 200,000 lb of steam per hour or 25 MWof electrical capacity.

Thus, it appears that new gas turbine cogen-erators will have either emission standards equalto those of large utility gas turbines or, for thesmaller units, half as stringent. Future im-provements in the efficiency and economics ofvery small gas turbines conceivably might lead,however, to turbine cogenerators below theNSPS cutoff and thus only subject to local emis-sion standards.

Stationary diesels currently are not regulatedat the Federal level. The Environmental Protec-tion Agency (EPA) has proposed new source per-formance standards for stationary diesels above560 cubic inch displacement per cylinder, whichessentially includes most low- and medium-speeddiesels (less than 1,000 rpm) (39). In the absenceof the NSPS, it appears likely that most cogener-ators would fall in this size range. However, itis unclear whether the incentive of potential es-cape from controls might lead, upon the promul-gation of a Federal emission standard, to deploy-ment of smaller displacement diesel cogenera-tors. In fact, incentives to purchase such smallerdisplacement diesels may precede a Federalstandard; at least one EPA regional office isreported to be requiring control to the proposedNSPS level even without the benefit of a formalstandard (8).

Small cogenerators could escape the effect ofadditional emission limitations (beyond the Fed-eral NSPS) in nonattainment and prevention ofsignificant deterioration (PSD) areas (see ch. 3).These limitations are triggered by annual emis-sions of either 100 tons per year (tpy) (steam tur-bine) or 250 tpy (diesel and gas turbine) of anycriteria* pollutant (44). For example, a 1-MWdiesel achieving the proposed NSPS NOX level(600 ppm or about 2.20 lb/MMBtu) (2,39) wouldemit a maximum of 96 tpy of NOX even if it rancontinuously at full load. Thus, it could avoid thenonattainment or PSD requirements, whereas alarge utility plant could not.

Table 50 indicates the size limit necessary toavoid a nonattainment or PSD review (i.e., to emit

*A “criteria” pollutant is one that is regulated under the CleanAir Act by a National Ambient Air Quality Standard. Current criteriapollutants are sulfur oxides, particulate matter, nitrogen dioxide,hydrocarbons, photochemical oxidants, carbon monoxide, andlead.


Table W.—Maximum Size Cogenerator Not RequiringNew Source Review

Technoloav Megawatts

Dlesels 300/0 efficient

NO, limit:Oil-fired uncontrolled . . 1.5Dual-fuel uncontrolled . 2.2Proposed NSPS . . . . . . . 2.5

Gas turbines 30°A efficient

NOX limit, assuming NSPS 17.0SOX limit:

1.O% sulfur oil . . . . . . . . 5.00.30% sulfur oil . . . . . . . . 16.50.20% sulfur oil . . . . . . . . 24.8

Steam turbines 150/0 efficient

NOX limit:Coal-fired . . . . . . . . . . . . 7.9Oil-fired . . . . . . . . . . . . . . 3.4Gas-fired . . . . . . . . . . . . . 2.2

SOX limit:0.2% sulfur oil . . . . . . . . 5.01.0% sulfur oil . . . . . . . . 1.0

200/0 efficient

11.5

7.510.816.3

100/0 efficient

5.62.41.6

3.30.7

aPlant electrical efficiency, Btu (electrlcity) 100/Btu (Input fuei).


less than 100 or 250 tpy of a criteria pollutant)for a cogenerator operating at 100 percent load.Under existing regulations, cogenerators largerthan this size also could avoid review by apply-ing sufficient controls to reduce their emissionsto just below the limit.

The change in scale and location associatedwith cogeneration replacing conventional energysystems can have a substantial effect on the dis-persion characteristics of the emissions. In somecircumstances, this change in dispersion will in-fluence ambient air quality more strongly thanthe changes in the amount of emissions. The airquality changes, however, will depend on a varie-ty of factors including meteorological conditions,effective stack heights, terrain, and location of theemissions sources. This large number of physicalfactors, coupled with a wide range of technol-ogy choices, makes air quality modeling of an ap-propriate range of cogeneration and conventionalsystems expensive, and it was not attempted.However, by relying on existing studies and dif-fusion theory, some of the qualitative differencesbetween alternative electric and thermal energyproduction systems can be described.

Although both a cogeneration-based systemand a conventional system consist of combina-

tions of centralized and dispersed sources (thecogeneration system usually requires central sta-tion backup), a good part of the air quality dif-ferences between the two systems can be under-stood by comparing the pollution effects of cen-tralized emission sources with tall stacks to theeffects of multiple dispersed sources with shorterstacks. This is because cogeneration installationsoften are added to a large existing (conventional)system (i.e., a utility grid and a series of localizedheat sources) and in many cases simultaneouslyincrease the emissions from dispersed sources*and decrease the centralized emissions. The airquality tradeoff between dispersed and central-ized sources thus is an important determinant ofwhether adding cogeneration is environmentallypreferable to maintaining the conventional sys-tem.

The air quality tradeoff between central anddispersed sources–between a few sources withtall smokestacks and multiple sources with rel-atively short stacks—is difficult to evaluatebecause the tradeoff changes with local condi-tions. Some of the general features of the tradeoffcan be described, however, by looking at a sim-plified example and then showing the effects ofvarying conditions, one at a time.

The simplified example considers a very largearea with a relatively flat terrain. The centralizedsystem is represented by a few large emissionsources with tall stacks—on the order of severalhundred feet in height. The dispersed system isrepresented by many smaller sources with shortstacks scattered relatively uniformly throughoutthe area. The total emissions from each systemare assumed to be equal.

As long as the area in question is very large andthe air quality is averaged over a long period—ayear, for example–striking differences in airquality between the two systems usually will notbe seen. * The few tall stacks achieve a relativelyuniform dispersion of pollution because of theirsuperior diffusion characteristics; the more nu-merous shorter stacks achieve a somewhat sim-

● There are important exceptions to this, e.g., when the heatsource that is substituted for is more polluting than the cogenerator,or when the cogenerator is replacing multiple small heat sources.

*in some situations, when there are strong differences in the pre-vailing winds at the different heights, strong differences may occur.

Ch. 6—impacts of Cogeneration ● 227

Photo credit: Environmental Protection Agency

Photo credit Department of Housing and Urban Development

The substitution of multiple small cogenerators in urban areas in place of centrally located powerplants involves shifts inlocation, stack height, magnitude, and type of air emissions and can have significant impacts on air quality


ilar effect (albeit with many small peaks andvalleys in pollutant concentration levels) becausethey are spread out.

The actual characteristics of the choice facinga decision maker usually are quite different fromthis idealized case. Often, the short stacks—thecogenerators—are clustered within a relativelysmall area rather than being widely scattered.Short-term meteorological conditions may disruptthe smooth dispersion of pollutants from tall andshort stacks in drastically different ways. Whenthe cogenerators are located in urban areas, theirproximity to other buildings may affect emissionsdispersion. And sometimes the tall stacks–thecentral power stations—are located in a differentarea from the cogenerators. Each of these con-ditions affects air quality and must be consideredin examining the tradeoff between cogeneratorsand conventional central utility systems.

Clustering of the small sources within an urbanarea makes the dispersion characteristics of a tallstack in the same area superior to those of thesmall stacks. This is because the effective area ofdispersion of a tall stack is very large, whereasthe clustering of small sources has defeated theirpotential for geographically based dispersion.Thus, a series of emission sources with relativelyshort stacks—such as cogenerators—located in arelatively small area will have a considerablygreater impact on local (average annual) air quali-ty than a single source with a tall stack locatedin the same area.

However, if the tall stack is located some dis-tance from the cluster of short stacks, the airquality of areas at a distance from the cluster ofsmall sources may show some improvement asa result of reducing emissions from the tall stack.In situations where the problems associated withlong-distance transport of air pollution (e.g., acidrain) are considered to be more important thanexisting local air pollution problems, a switch toshort stacks may be viewed as beneficial to over-all air quality.

Short-term meteorological conditions maysubstantially change dispersion characteristicsand alter the air quality tradeoffs between shortand tall stacks. Under inversion conditions, whenhigh levels of pollutant concentrations can result

from sources under the inversion layer, thebuoyant plume from a tall stack may be able topunch through the inversion layer and, conse-quently, have minimal impact on local air quali-ty. Emissions from lower stacks, on the otherhand, are trapped beneath the layer and arepoorly dispersed. During other conditions,plumes from either tall or short stacks may beforced to ground level (“fumigation”). Underfumigating conditions, the concentration peaksfrom the few large sources with tall stacks canbe considerably larger than the concentrationspossible with a series of dispersed, smallersources with low stacks. Fumigation conditionsinclude the breakup of a night-time inversion, cer-tain kinds of shoreline wind conditions, and ther-mal instability causing looping plumes. Moun-tainous terrain can also cause powerplant plumesto touch down. Other conditions, such as thetrapping of emissions beneath elevated inver-sions, may also diminish the dispersion advan-tages of tall stacks.

Careful siting of cogenerators can be criticalin urban situations because the unique terrainconditions can adversely affect dispersion ofemissions. Plumes from cogenerator stacks maybe caught in aerodynamic downwashes causedby the action of wind around neighboring build-ings (or, in some cases, around the stack itself)and cause high pollutant concentrations in theimmediate area of the stack. In addition, theplume may impinge on surrounding buildings,especially if they are taller than the stack or fair-ly close to it.

Pollutant concentrations caused by this “urbanmeteorology” may be much higher—perhaps byan order of magnitude or more—than predictedby models assuming unobstructed dispersion. Forexample, a calculation of the effect of downwashcaused by airflow around a small building hous-ing a diesel cogenerator showed an increasein maximum ground level concentrations of NOX

from 400 micrograms per cubic meter ( ug/m3)(no downwash, 10 m stack) to 6,000 ug/m3(downwash) (5). Concentrations may be stillhigher on the faces and roofs of surroundingbuildings. Because roof areas may be used asrecreation areas or for fresh-air intake, and build-ing faces may have open windows, downwashproblems must be taken extremely seriously.

Ch 6—Impacts of Cogeneration ● 229

Aerodynamic problems from the cogenerator’sbuilding or from surrounding buildings of similarheight can be eliminated by the simple expedientof increasing the stack height. Unless surround-ing buildings are close and their height is con-siderably taller than the stack, the stack heightlevels needed either to avoid any effects or toavoid the worst downwash effects usually are notso high as to render the system infeasible. For ex-ample, for a 7 m high building with no problemsfrom surrounding buildings, stack heights thatavoid all building interaction effects are on theorder of 10 to 14 m above the roofline if the build-ing is of moderate horizontal dimensions. A 6 mstack might be tall enough to avoid the worstdownwash effects (5). The presence of nearbybuildings of similar height adds to the downwashproblem, but the additional stack height neces-sary to avoid problems is not great; for 9 m highbuildings, only 3 m would have to be added tothe stack (5). If the surrounding buildings aremuch taller than the cogenerator’s building andcloser than about three times their height, how-ever, then the cogenerator can only free itself oftheir adverse aerodynamic influence by raisingits stack above their height (5). The economic andesthetic effects of this requirement will be quitehigh in some cases.

Finally, in cases where an area’s electricity isimported from distant powerplants, the tradeoffbetween short stack cogenerators and centralpowerplants with tall stacks is complicated: theemissions from each alternative affect differentareas that may have different meteorological con-ditions, background air quality, and other factorsthat determine pollution impacts. Also, becausea utility often can choose among a variety of sup-ply alternatives, including different types ofpowerplants within its airshed (possibly using dif-ferent fuels or maintaining different levels ofpollution control) and long-distance power im-ports, the air quality tradeoff becomes still morecomplex and is difficult to evaluate properly.

One factor in this tradeoff is fairly consistent,however. New powerplants generally are locatedfar from densely populated urban areas, whereascogenerators serving urban areas are locatedthere. Thus, peak pollutant concentrationscaused by short-term unfavorable meteorological

conditions generally fall outside of the urbanareas for powerplants and inside these areas forcogenerators. Consequently, the actual popula-tion exposure due to the cogenerators may behigher than the exposure caused by the power-plant even during conditions when the cogen-erator-related concentrations are much lowerthan the concentrations associated with thepowerplant. These differences may have impor-tant implications for the health effects of alter-native centralized and decentralized systems,although there are other effects (such as ecolog-ical damage) for which the above differences areeither unimportant or imply higher costs from thepowerplants.

Emissions Balances: Cogeneration v.Separate Heat and Electricity

Computing the air quality effects of any tech-nological change is always made difficult by thecomplexity, expense, and inaccuracy of air quali-ty modeling. In the case of cogeneration, thiscomputation is further complicated by difficultiesin determining the emissions changes occurringin the central utility system and by substantialvariability in the emissions factors to be appliedto the cogenerators.

The response of the utility system to an increasein cogenerated power—a critical parameter in de-termining not only emissions impact but also oilsavings (or Ioss)—is difficult to predict. The addi-tion of significant levels of cogenerated power toa utility’s service area will affect both its currentoperations and future expansion. If the cogen-erated power represents a displacement of cur-rent electricity demand in the service area (i.e.,with retrofit of an existing facility for cogenera-tion), the utility will either reduce its own elec-tricity production or reduce power imports, withits decision based on costs, contractual obliga-tions or, perhaps, politics. It may also move upthe retirement date for an older powerplant orcancel planned capacity additions in response tocogenerators’ displacement of either current oranticipated future demand. Because most uti{itygrids draw on a mix of nuclear-, coal-, and oil-fired steam electric generators for base and in-termediate loads, and oil- or natural gas-fired tur-


bines for peaking capacity (as well as hydroelec-tric and natural gas-fired steam electric plants insome parts of the country); because these plantsmay be scattered over a wide area; and becausecontrol systems for the fossil plants may varydrastically in effectiveness, the pollution implica-tions of the response of the utility system to co-generation are highly variable.

Aside from problems in computing the utilitysystem impacts, a variety of factors create ana-lytical difficulties in calculating the emissions like-ly to be produced by a cogenerator. For exam-ple, the potential variability in organic nitrogenand sulfur content of future fuel supplies for gasand steam turbines and diesels may have substan-tial impacts on the level of NOX and SOX emis-sions unless appropriate controls are applied tocompensate for fuel quality. Differences in thespecific design and duty cycle of cogeneratorsalso may create substantial variability in emissionsfrom engines of the same size and technology.CO and unburned hydrocarbon emissions fromdiesels depend on injection pressure (range:several hundred to 20,000 psi, though not for thesame size engine), engine speeds, use of a pre-combustion chamber, and other factors. NOX

emissions depend on combustion and postcom-bustion temperatures, which can vary substan-tially in diesels and gas turbines. Emissions of allthree of the above pollutants depend on load,which can vary from application to application.Data from EPA and other sources show that un-controlled diesel hydrocarbon emissions can va~by a factor of 29 (0.1 to 2.9 grams/horsepower/hour (g/hph)), CO emissions by a factor of 49 (0.3to 14.6 g/hph), and NOX emissions by a factor ofeight (2.1 to 17.1 g/hph) (39). Although controlsrequired by uniform emission standards shouldreduce this variability, it is likely that even con-trolled emission rates will vary substantially fromone installation to another, because controls areunlikely to be “fine-tuned” to account for varia-tions in fuels and operating procedures, and be-cause different manufacturers will choose dif-ferent margins of safety and control techniquesto ensure compliance.

OTA calculated the emissions impact–both atthe cogenerator site and over a larger area en-compassing the cogenerator site and the entire

utility grid—for a variety of situations where acogenerator replaces or substitutes for a moreconventional electricity and heat supply option(e.g., central station power plus onsite boiler).The results are shown in table 51. The substan-tial number of combinations of: 1) cogeneratortype and fuel, 2) central power station type andfuel, and 3) local heating type and fuel that areanalyzed, and the normalization of the calcula-tions to 100 kWh of electricity generation aredesigned to compensate in part for the site-spe-cific variability of cogeneration installations dis-cussed above. Emissions data for each of the sep-arate modules are given in appendix B, and thesedata may be readily used to compute additionalcombinations. Unfortunately, the variability inemissions factors caused by design and operatingvariations is not accounted for in table 51.

A key conclusion that can be drawn from table51 is that substituting cogeneration for more con-ventional systems will not result in automaticpollution gains or losses despite the increased ef-ficiency. If the variability not accounted for in thetable is further considered (e.g., alternative fuelcompositions, or the considerable range of emis-sions factors possible within a cogenerator tech-nology type), the potential for achieving a widerange of positive and negative emissions effectsby varying the precise cogeneration system de-sign becomes even more readily apparent.

Diesel cogeneration may be an important ex-ception to this conclusion. Diesel cogeneratorswill tend to cause a strong increase in NOX bothat the cogeneration site and in the overall regionalbalance (utility plant reduction included), main-ly because diesels are very high emitters of NOX.Although CO emissions increase by about thesame order of magnitude as NOX, the CO in-creases are far less significant because the toxiceffects of NOX occur at concentrations that areat least 10 times lower than the levels at whichCO becomes toxic.

The actual effect of diesel cogenerators onemissions and air quality will depend on thedegree of attention paid to environmental con-trol. If minimum NOX emissions were judged tobe of critical importance in a series of cogenera-tion installations in an area, appropriate selection

Ch. 6—Impacts of Cogeneration . 231

Table 51.—Selected Emissions Balances for Cogeneration Displacing Centrai PowerPius Locai Heat Sourcese (normalized to 100 kWh)

Net emissions (lb) Net emissions at cogeneratlon site (lb)

Cogenerator Replaces Central power PIUS Heat NOX Partlculates CO HC SOX NO X Partlculates CO HC SOX

Diesel (011) New coal plant Domestic gas +2.84 +0.04 + 0 . 6 5 + 0 . 0 9 – 1 . 1 2 + 3 . 3 9 +0.07 +0.90 +0.10 +0.20Older oil-fired plant Domestic oil +2.69 –0.01 + 0 . 8 8 + 0 . 0 8 – 0 . 9 3 + 3 . 3 7 +0.06 +0.89 +0.10 +0.12Existing gas turbine

(oil) peaking unit Domestic 0il +2.36 +0.02 +0.77 +0.06 +0.09 +3.37 +0.06 +0.89 +0.10 +0.12

Note: Proposed diesel NSPS subtracts 1.2 lb NOx/100 kllowatthours

SIgnlflcant changes from above:Diesel (90 percent gas, 1) 0.77 lb/100 kWh more HC

10 percent oil) Any combinations 2) 0.94 Ib/1OO kWh leas NOX

Gas turbine (NSPS) (gas) Older coal-fired plant Domestic oil –0.39 –0.29 + 0 . 0 9 + 0 . 0 3 – 4 . 5 2 + 0 . 3 0 +0.02011-fired Industrial

+0.13 +0.04 –0.14

boiler –0.80 –0.40 +0.09 +0.03 –5.17 +0.09 –0.09 +0.13 +0.04 –0.79Older oil-fired plant Coal-fired

Industrial boiler –0.84 –0.40 + 0 . 0 5 + 0 . 0 1 - 3 . 2 7 - 0 . 0 4 -0.35New coal plant

+0.09 +0.02 –2.18Gas-fired

Industrial boiler –0.28 –0.01 +0.10 +0.04 –1.31 +0.27 +0.02 +0.14 +0.05 +0.01

Note: Removing gas turbine NSPS adds 0.4 lb NOx/lOO kilowatthours

Gas turbine (NSPS) (oil) Older oil-fired plant Oil-fired Industrlalboiler –0.61 –0.09 –0.03 +0.03 –1.65 + 0 . 0 9 –0.04 +0.01 +0.04 –0.60

Older natural gas- Gas-firedfired plant Industrial boiler –0.40 +0.06 o +0.01 +0.20 +0.27 +0.07 +0.02 +0.05 +0.20

Note: removing gas turbine NSPS adds 0.8 lb NOx/100 kllowatthours

Steam turbine, coal fired Older oll-flred plant NSPS steamboiler, coal –0.38 –0.01 –0.02 o –0.49 +0.32 +0.04 +0.02 +0.01 +0.56

Older natural gas- NSPS steamfired plant boiler, coal –0.35 +0.03 o –0.03 +0.56 +0.32 +0.04 +0.02 +0.01 +0.56

Nuclear plant NSPS steamboiler, coal +0.32 +0.04 +0.02 +0.01 +0.56 +0.32 +0.04 +0.02 +0.01 +0.56

Older oil-fired plant Oil-fired Industrialboi ler +0.38 –0.13 o 0 - 0 . 1 1 + 1 . 0 8 -0.06 +0.04 +0.01 +0.94

Older oll-firedboiler c –0.37 +0.12 –0.02 –0.01 –0.12 +0.33 +0.17 +0.02 o +0.94

aSee app. A for assumptions on controls and emlsslons rates.b This might represent replaclng a number of oil-fired process heat boilers In an Industrial park with a single coal-fired cogenerator.cEssentially ldentical in (emissions per million Btu) with the older Oil-fired PowerPlant.


of diesel designs and use of controls could loweremissions from the level shown in table 51.

Gas turbine cogenerators do not appear tocause consistently strong changes in emissionseither locally or regionally, except for: 1 ) regionalSOX reductions due to turbines’ clean fuel re-quirements, 2) regional NOX reductions resultingfrom the increased efficiency of the cogenerationsystems, and 3) small NOX increases locally. Theregional NOX reductions would be largely lostand local increases made larger by 0.4 to 0.8lb/100 kWh if NOX controls were no longerrequired.

Finally, coal-fired steam turbine cogeneratorsare likely to create mild increases in NOX andsomewhat larger increases in SOX emissionslocally because of the increased fuel consump-tion at the site. Regional effects are mixed.

An Air Quality Analysis ofUrban Diesel Cogeneration

To our knowledge, there have been few anal-yses of the air quality effects of an areawide in-stallation of cogeneration equipment, and onlyone non hypothetical area—New York City—hasbeen modeled explicitly. Both ConsolidatedEdison (ConEd), the utility serving New York City,and the New York State Public Service Commis-sion staff have conducted dispersion modelingstudies to evaluate the impacts of installing multi-ple cogenerators with a combined electric capaci-ty of as much as 1,000 MW* (14,19,21). Theresults of these studies, which generally show

● The Con Ed analysis is reported in detail in Environmental Re-search and Technology, Inc. (19), and updated and revised inFreudenthal (21). The Public Service Commission analysis is de-

scribed in Domaracki and Sistla (14).


adverse effects on air quality, have been widelydisseminated by ConEd, which is opposed tourban cogeneration, and they have become con-troversial. Consequently, they deserve closerexamination.

The most recent study by Con Ed examines theimpact of installing 141 cogenerators in Manhat-tan, displacing 514 MW of ConEd’s capacity aswell as a considerable amount of space heating.In this study, annual nitrogen dioxide (N02) con-centrations in a large part of Manhattan werepredicted to increase by more than 14 pg/ms,with a resulting violation of Federal ambientstandards in this area (21). This most recent ver-sion of ConEd’s analysis corrects two major prob-lems affecting the results of an earlier study ex-amining the impacts of 1,086 MW of cogenera-tion capacity: collocation of multiple emissionsources and location of receptors too close toemission sources (19).

However, evaluation of the most recent Con-Ed analysis should take into account the follow-ing considerations:

1.

2.

The analysis assumes an emission rate of17.3 g/kWh of NOX for the diesels. This ap-pears to be a reasonable value for uncon-trolled oil-fired diesels, but it is substantial-ly higher than the approximately 10 g/kWhproposed for the Federal NSPS. Further-more, diesels that do considerably betterthan the assumed uncontrolled rate areavailable, so that careful selection of manu-facturers and models could yield significantlylower emissions even without adding con-trols. Consequently, the assumed emissionrate is valid only if selection of diesels ismade with no concern about their emissionrate and if manufacturers of diesels make noattempts to reduce emission rates in the nextfew years.The analysis examines only one distributionof sources and does not attempt to find amore acceptable pattern (e.g., by removinga few critical cogenerators). This implicitlyassumes that air quality considerations willplay no role in the siting of cogenerators, andthus that permitting procedures are ineffec-tive. This implicit assumption has been chal-

3.

Ienged by the State Department of PublicService (DPS) (14). DPS notes that mostcogenerators will undergo PSD reviews, andalso that proliferation of cogeneration willresult in an appropriate regulatory responseon the part of the State. DPS believes thatthe present inadequacy of regulations for co-generator siting is the result of the lack ofdevelopment activity. However, there is noguarantee that local reviews, currently con-sidered by some to be inadequate, will besufficiently upgraded in response to a surgein cogeneration activity. In the testimonycited above, the witnesses agreed that noneof the cogeneration sources included in theCon Ed analysis would have been prohibitedunder existing regulations,ConEd has assumed that commercial cogen-erators will be able to use only 50 percentof their recoverable heat (thermal efficien-cy of 52 percent), and residential cogenera-tors will use 75 percent of their recoverableheat (62 percent thermal efficiency). Avail-able studies of cogeneration assume signif-icantly higher thermal efficiencies, which inturn would change the emissions balance ofcogenerator, central power station, and fur-nace or boiler in favor of the cogenerator.As discussed in chapter 5, ConEd’s assump-tions imply no thermal storage and “elec-trical dispatch” —running the cogeneratoronly when sufficient electrical demand ex-ists. With the Public Utility RegulatoryPolicies Act of 1978 (PURPA), cogeneratorsare more likely to operate on “thermal dis-patch” and distribute any excess electricityto the grid. Consequently, their overall effi-ciencies should be higher than what Con Edassumes, with more favorable emissionsbalances.

Despite the inherent inaccuracy of diffusionmodels, especially in urban applications, it seemsprudent to consider the prediction of a generalincrease in NOX concentrations to be roughly ac-curate for the particular situation examined. Thepotential problems in ConEd’s analysis with thecogenerator thermal efficiencies should not dras-tically affect this prediction. The remaining prob-lems with the analysis, however, demand a very

Ch. 6—impacts of Cogeneration 233

careful interpretation: OTA interprets the Con-Ed analysis as showing that any additional de-velopment—including multiple installations ofdiesel cogenerators—that could produce an in-crease in local urban emissions, might create airquality problems if adequate controls were notrequired and if permits were issued withoutcareful consideration of stack height, siting, andother parameters affecting pollutant dispersion.In areas where existing air quality is not substan-tially better than the Federal ambient standards,it appears likely that some permits may have tobe denied to avoid violations of these standards.

Emission Controls

Potential air quality problems like the onesdescribed above can be ameliorated if emissionscan be controlled sufficiently. As noted previous-ly, however, controls will not automatically berequired by law in many situations, especially forsmall cogenerators such as diesels and spark-ignition engines that are not covered by FederalNSPS and may not be subject to State and localregulation. For technologies to which NSPS doapply (e.g., gas turbines) the required level of con-trol may not be as stringent as the local air quali-ty situation might call for, because most State andlocal environmental authorities are reluctant togo beyond the NSPS requirements. This sectiondescribes the available controls for NOX emis-sions from reciprocating internal combustionengines and gas turbines. Emissions from in-dustrial boilers (for steam turbine cogenerators)are not discussed, but EPA is preparing an NSPSbackground document for these emissionssources. *

Reciprocating Internal Combustion Engines

In 1979, EPA proposed an NSPS of 600 partsper million (ppm) NOX corrected to 15 percentoxygen (equivalent to about 7 g/hph or about 2.2lb/MMBtu fuel input) (2) for diesels burning oilor oil/natural gas combinations (39). This is anorder of magnitude higher than emission ratesfrom other combustion sources such as industrialboi!ers or even gas turbines (38). “Typical” un-controlled NOX levels from diesels are 11 g/hph

*A draft has been prepared by the Radian Corp.

(about 3.5 lb/MMBtu) for oil-fired engines and 8g/hph (about 2.5 lb/MMBtu) for dual-fuel engines(39). As noted above, emission levels vary wide-ly among different engine manufacturers andmodels.

Table 52 lists the wide variety of control op-tions available to reduce NOX emissions. In its ef-forts to formulate the internal combustion engineNSPS, EPA concluded that, of the methods shownin table 52, only retarded ignition timing, air-to-fuel ratio changes, decreased manifold air tem-peratures and engine derating were demon-strated to be effective and readily available forlarge engines (39). Exhaust gas recirculation andcombustion chamber modification were consid-ered to require additional development anddurability testing, and the remaining methodswere considered to have serious technical or costproblems, or to be of uncertain effectiveness forthese engines.

The available control techniques do not workidentically on diesel, dual-fuel, and natural gas-fired spark-ignition engines. Table 53 showswhich techniques will achieve emission reduc-tions of 20, 40, and 60 percent for the threeengine types; the table also shows the expectedincreases in fuel consumption with these levelsof emissions reductions. The increased fuel use,combined in some cases with higher mainte-nance costs and capital charges from add-onequipment, can cause significant increases in totalcosts; table 54 shows the increases in total an-nualized costs for different control types andemission reductions applied to diesel engines. ig-nition retard, with or without an air-to-fuel ratiochange, and a combination of air-to-fuel changeand manifold cooling can reduce NOX emissionsby 40 percent with total annualized cost increasesof less than 10 percent. This level of control wasselected by EPA for its proposed NSPS, althoughthe proposal was withdrawn.

More recent information implies that greaterNOX emission reductions than those indicated byEPA may be possible. For example, although EPArejected water induction as a viable control strat-egy because of its potential for corrosion and oilcontamination (39), the use of fuel/water emul-sions or carefully timed direct injection apparent-ly can bypass these problems (15). Control levels


Table 52.—Summary of NOX Emission Controi Techniques for Reciprocating IC Engines

BSFCa

Control Princicple of reduction Application Increase comments-limitations-- . . . . -. . .Retard Reduces Desk temperatureInjection (Cl b

Ignition (SI)c

Alr-to-fuel(A/F) Ratiochange

Derating

Increase-speed

Decreased Inlet manifoldair temperature

Exhaust gas recirculation(EGR)

External

Internal:Valve overlap or

retard

Exhaust backpressure

Chamber modlflcationPrecombustion (Cl)Stratified charge (SI)

Water lnduction

Catalytic conversion

by delaying start of com-bustion during the com-ustlon period.

Peak combustion tempera-ture Is reduced by off-stolchiometrlc operation

Reduces cylinder pressuresand temperatures.

Decreases residence timeof gases at elevated tem-perature and pressure.

Reduces peak temperature.

Dllutlon of incoming com-bustion charge with inertgases. Reduce excessoxygen and lower peakcombustion temperature.

Cooling by increased scav-enging, richer trappedair-to-fuel ratio.

Richer trapped air-to-fuelratio.

Combustion In antechamberpermits lean combustionIn main chamber (cylln-der) with less availableoxygen.

Reduces peak combustiontemperature.

Catalytic reduction of NOto N2.

An operational adjustment.Delay cam or Injectionpump timing (Cl); delayignition spark (SI).

An operational adjustment.Increase or decrease tooperate on off-stoichio-metric mixture. Resetthrottle or Increase air rate.

An operational adjustment,limits maximum bmepd

(governor setting).

Operational adjustment ordesign change.

Hardware addltlon to in-crease aftercooling or addaftercoollng (larger heatexchanger, coolant pump).

Hardware addition; plumbingto shunt exhaust to Intake;coollng may be requiredto be effective; controlsto vary rate with load.

Operational hardwaremodification: adjustmentof valve cam tlmlng.

Throttling exhaust flow.

Hardware modification; re-quires different cylinderhead.

Hardware addition: injectwater into inlet manifoldor cylinder dlrectly; effec-tive at water-to-fuel ratio1 (lb H2)/lb fuel).

Hardware addition; catalyticconverter installed In ex-haust plumbing or reduc-ing agent (e.g. ammonia)injected Into exhauststream.

Yes

Yes

Yes

Yes

No

Noe

Yes

Yes

Yes

No

No

Particularly effective with moderateamount of retard; further retardcauses high exhaust temperaturewith possible valve damage and sub-stantial BSFC Increase with smallerNOX reductions per successivedegree of retard.

Particularly effective on gas or dualfuel engines. Lean A/F effective butIlmited by mlsfirlng and poor loadresponse. Rich A/F effective but sub-stantial BSFC, HC, and CO Increase.A/F less effective for diesel-fueledengines.

Substantial Increase In BSFC with addi-tional units required to compensatefor less power. HC and CO emissionincrease also.

Practically equivalent to deratlng be-cause bmep is lowered for given bhprequirements. Compressor applica-tions constrained by vibration con-siderations. Not a feasible techniquefor existing and most new facilities.

Ambient temperatures Iimit maximumreduction. Raw water supply may beunavailable.

Substantial fouling of heat exchangerand flow passages; anticipate in-creased maintenance. May causefouling in turbocharged, aftercooledengine. Substantial Increases In COand smoke emissions. Maximum re-circulation Ilmlted by smoke at nearrated load, partlcularly for naturallyaspirated engines.

Not applicable on natural gas enginedue to potential gas leakage duringshutdown

Limited for turbocharged engines dueto choking of turbocompressor.

5 to 10 percent increase In BSFC overopen-chamber designs. Higher heatloss implies greater cooling capacity.Major design development.

Deposit buildup (requiring deminerali-zatlon); degradation of lube oil,cycling control problems

Catalytic reduction of NO is difficult inoxygen-rich envlronment.-Cost ofcatalyst or reducing agent high.Little research applied to large-boreIC engines.

aBSFC-brake specific fuel consumption.bCompression Ignition.cSpark Ignition.d bmep—brake mean effactlve pressure.e lf EGR rates not excessive.

SOURCE: Environmental Protection Agency, Standards Supporf and Environmental Impact Statement for Stationary Internal Combustion Engines (EPA-450/2.7&125a,draft, July 1979).

Ch. 6—Impacts of Cogeneration ● 235

Table 53.—NOX Control Techniques That Achieve Specific Levels of NOX Reduction

NOX Diesel Dual fuel Natural gasreduction Control (amount) Control (amount) A BSFC,a

‘/0 Control (amount) A BSFC,a ‘/o

20%0 Retard (2° to 4°) o to 4 Retard (2° to 3°) 1 to 3 Retard (4° to 5°) 1 to 4External EGR (7%) o Manifold air coollng 1 Manifold air cooling oDerate (25 to 5070) 3 to 5 External EGR (lO%) 1 External EGR (4%) oAir-to-fuel change (25%) 10 Derate (12 to 25%) O to 8 Derate (5 to 35%) 2 to 6Retard and manifold o to 1 Air-to-fuel changes (5 to IO%) o to 2 Air-to-fuel change (570) 2

air coolingRetard and manifold o to 1

air cooling and air-to-fuelchange

40% Retard (7 to 8°) 4 to 8 Retard (5°) 2 Retard (10°) 2Derate (50%) 14 to 17 Manifold air cooling 1 Derate (10 to 50%) 2 to 24Air-to-fuel change and 3 to 5 Derate (30 to 50%) 2 to 8 Air-to-fuel change (7%) 2

manifold air coolingRetard and air-to-fuel change 3 to 5 Air-to-fuel change (lO%) 2 Retard and manifold 7

air cooling andRetard and manifold cooling 3 air-to-fuel change

6 0 % Retard (16°) 19 to 24 Retard (6°) 2 Derate (10 to 50°/0) 2 to 22Retard and air-to-fuel change 21 Derate (50%) 12 Air-to-fuel change (8 to 12%) 2 to 5

Retard and air-to-fuel change 1 to 3 Retard and manifold air 7cooling and air-to-fuelchange

Table 54.-Costs of Alternative NOX Controls for Diesel Cogenerators (percent Increase In total annualized costs)

NOX control Retard External Air to fuelPercent reduction (R) Derate EGR (A) R + Ma R + M + A R + A A +M

200/0 o-3 9-31 6 8 2 340% 3-6 37-40 4 460% 14-18 16

aManlfold air cooling.

SOURCE: Office of Technology Assessment, from Environmental Protection Agency, Standards Support and Environmental Impact Statement for Stationarv Internal.Combustion Englnes (EPA-450/2-78-125a, draft, July 1979).

- .

of 50 percent or greater have been achieved withthese techniques, with some parallel decreasesin particulate emissions* (43). Another, morespeculative NOX control approach is the use ofcatalytic reduction systems. The staff of theCalifornia Air Resources Board (CARB) reportsthat NOX reductions of 90 to 95 percent can beobtained from such catalytic systems (35). Theyalso expect the systems to reduce CO emissionsby 80 percent and hydrocarbon emissions by 75percent. Catalytic reduction systems are currentlyavailable for rich-burning natural gas spark-ignition engines, and the CARB staff expects them

*Wilson (42) reported that water/fuel emulsion achieved 50 per-cent NOX reduction at full engine load with no fuel penalty. At part-Ioad (66 to 93 percent), NO, reductions of 75 percent wereachieved with a combination of exhaust gas recirculation and water/fuel emulsion.

to be available for the other engine types withina year or so, at costs below 10 percent of totalannualized costs (3). However, this projection isviewed with various degrees of skepticism byother researchers (2).

Combustion TurbinesThe Federal NSPS for large combustion turbines

(above 100 MMBtu/hr) is 75 ppm NOX correctedto 15 percent oxygen, which is equivalent toabout 0.3 lb/MMBtu NOX (40). For comparison,a typical emission factor for NOY emissions froman industrial boiler burning distillate oil is abouthalf as much, or 0.16 lb/MMBtu (38). “Typical”uncontrolled NOX levels from turbines are 0.6lb/MMBtu for natural gas-fired engines and 0.9lb/MMBtu for oil-fired engines (40). However, the

variation in emissions among different turbinedesigns and sizes and even in the same turbineunder different operating conditions is extreme-ly high. Thus, the “typical” values are of limitedusefulness in air quality analyses.

The most widely used emission control systemsfor combustion turbine NOX emissions are so-called “wet” controls, which consist of water orsteam injection into the combustion zone of theturbine. The injected fluid absorbs some of theheat of reaction, reducing peak combustion tem-peratures and, consequently, the rate of NOX for-mation. This control is accepted by the industryand does not have significant adverse side effects.Generally, a water/fuel injection ratio of 1.0 willproduce a 70- to 90-percent reduction in NOX

emissions, with a loss of fuel efficiency of 1 per-cent (40).

This range of control effectiveness, coupledwith the variability in uncontrolled emissionlevels, results in actual controlled emissions thatvary widely. EPA has measured “controlled”NOX emissions of 15 to 50 ppm for gas-fired tur-bines and 25 to 60 ppm for oil-fired turbines (40).This implies that appropriate selection of turbinedesign could allow the use of turbines in certainsituations where an “NSPS” turbine would be un-satisfactory.

Still more stringent control may be available byadding so-called “dry” controls. These are op-erating or design modifications such as exhaustgas recirculation, two-stage combustion, catalyticcombustion, and other types of modifications.NOX reductions of at least 40 percent have beendemonstrated for some dry controls, and thisreduction should be additive to any achievedwith wet controls (40).

Finally, catalytic exhaust gas cleanup systemsachieving NOX reductions of 80 to 90 percenthave been tested (40). Although these systemsdo not appear to be economically competitivewith wet and dry controls, they could be usefulif fuels with high nitrogen content were to be used(otherwise, the only viable control for NOX gen-erated by fuel-bound nitrogen is two-stage com-bustion) (40).

EPA has calculated the net NOX emission con-trol costs using wet controls for a baseload 4,000

hp industrial turbine. For a plant located closeto a water source, the controls cost about 0.6mills/kWh v. a total electricity cost of 32.5mills/kWh, or a 1.75-percent increase (40). Trans-porting water for a turbine located in an aridclimate could add considerably to this cost, how-ever. Considering this and other cost variables,EPA considers the range of potential control coststo achieve the 75 ppm NSPS to be about 1.5 to10.0 percent of the electricity cost for industrialturbines (40).

Health Effects FromCogenerator Emissions

Theoretically, any allowed increases in thedeployment of cogeneration technologies shouldhave no significant adverse effects on humanhealth due to the protection afforded by en-vironmental standards—especially the NationalAmbient Air Quality Standards (NAAQS). Asdiscussed above, however, these standards mightbe violated because of ineffective permit reviewprocesses that miss “micro” (close to the emis-sion source) effects in urban areas or that allowsmall cogenerators to escape careful analysis. Thesmallest cogenerators generally will be diesels,and these may therefore have the highest poten-tial to escape detailed review of monitoring and,possibly, to pose health hazards. Judging fromthe emissions balances displayed in table 53 andfrom other environmental analyses of cogenera-tion, the pollutants of major concern are NOX,sulfur dioxide (S02), and particulates-the latternot because of a high emission rate but becauseof their toxic character.

Due to of a variety of difficulties in measuringthe health effects of pollutants, several of theFederal ambient standards–especially the stand-ard for S02—have been criticized severely. A re-cent review in the Journal of the Air PollutionControl Association (JAPCA) concludes, however,that the standards “seem adequate to protect thehealth of the public” and, “until more data areavailable . . . should not be changed” (20). Onthe other hand, a number of other researchersdisagree, arguing that some of the standards haveproved to be unnecessarily stringent (23). Thehealth and other considerations relevant to eval-

Ch. 6—impacts of Cogeneration . 237

uating the NAAQS for S02, NOX, and par-ticulate are reviewed briefly below.

Sulfur Oxides

The 80 ug/m3 long-term standard for S02 isthe most controversial NAAQS because of thesubstantial expense involved in reducing sulfuremissions and, until recently, the lack of firmevidence of adverse health impacts from S02 ex-posure even at levels several times the currentstandards. Recent experiments, however, havedemonstrated health effects in asthmatics (in-creases in bronchoconstriction) at levels near thecurrent 24-hour standard (36). Also, exposure toS02 virtually always occurs in the presence of par-ticulate and other gases, and generally there isa heightened response from the combination ofpollutants. At levels around the ambient stand-ards (100 ug/m3 S02 and 150 ug/m3 particu-Iates, annual averages), respiratory symptoms, in-cluding general lung function impairments andincreased asthma attacks, have been detected(33).

Nitrogen Oxides

The form of most of the NOX emitted directlyby diesels and other cogenerators is nitrous oxide,or NO; eventually, the NO is transformed byphotochemical oxidation to the far more toxicN02. Because this oxidation takes sometime, thedanger associated with a cogenerator’s plume im-pacting on nearby buildings or the ground is con-siderably lessened.

At levels that maybe experienced in pollutedareas (a few hundred ug/m3), N02 appears to beassociated with lung irritation in asthmatics andsome increases in respiratory illness in the generalpopulation. According to the JAPCA review citedabove, the epidemiologic evidence for the lattereffect is not particularly strong (20). In any case,there seems to be little disagreement that the 100ug/ms (annual average) ambient standard is ade-quate to protect public health. EPA currently isinvestigating the need for a short-term standardto protect against the acute effects of brief pollu-tion episodes. It appears likely that this standardwill be no stricter than about 500 ug/m3 for 1hour.

Diesel Particulate

Aside from their relatively high levels of NOX

and CO emissions compared to alternative com-bustion technologies, diesel cogenerators face theadditional problem of producing particulate emis-sions that may cause adverse health effects. Theseeffects, if they occur, would most likely stem fromtoxic substances such as polycyclic organic ma-terial that adhere to the carbon core of the ex-haust particles. The small size of the particlescomplicates their control, allows them to remainairborne for weeks at a time, and allows deeppenetration into and retention by the lungs.

The National Academy of Sciences recently re-leased a report on diesel exhaust health effectsthat stresses the uncertainties in measuring thepotential for adverse effects of these exhausts,while emphasizing that conclusive evidence ofharm is not available (25). Some of the conclu-sions of the report are:

●

●

●

Although current epidemiologic evaluations(statistical analyses of human populations)are inadequate, the available evidenceshows no excess risk of cancer from dieselexhaust in the populations studied.Organic extracts (in which the potentiallyharmful organic compounds are removed,using a solvent, from the carbon particles towhich they adhere) of diesel particulatehave been shown to be mutagenic and car-cinogenic in animal cell and whole animalskin applications. The mutagenic and car-cinogenic potencies of these organic extractsappear to be similar to those of extracts ofgasoline engine exhaust, roofing tar, or coke-oven effluent.Unlike the extracts, inhaled whole diesel ex-haust has not been shown to be carcinogenicor mutagenic in laboratory animals. A possi-ble reason for this could be that many of thepotentially dangerous compounds may notbe released from the particles and thus maynot become biologically available to causeharm. *

*However, another reason could be that the tissue tests used forthese investigations do not adequately reflect what would actuallygo on inside the body.


● Potentially toxic particles can accumulate inthe lungs when diesel exhaust is inhaled, butlong-term effects are uncertain. In the shortterm, cell damage (mostly reversible) canoccur because the diesel exhaust can ad-versely affect the lungs’ defense and clear-ance mechanisms; it is not clear if this iscaused by the particles or by the gases in theexhaust.

● The design and operating characteristics ofthe engine may be a significant determiningfactor in the carcinogenicity of diesel engineexhaust materials.

Evaluating the potential for harm of diesel par-ticulate from cogenerators is complicated by dif-ferences in operating characteristics between co-generators running at constant speeds and rela-tively stable loads, and mobile sources runningat varying speeds and loads. Mobile sources (fromwhich most of the emission data have been gath-ered) operate at far less optimal combustion con-ditions and produce more particulate matter. Itis not unreasonable to speculate that the humanhealth risk from diesel cogenerators per unit ofenergy input or output may be significantly lowerthan the risk from mobile diesels; however, scien-tific data with which to confirm or deny thisspeculation do not appear to be available.

Effects of Some Other CogenerationTechnology/Fuel Options

Although oil-fired and dual-fuel diesels, oil- andnatural gas-fired combustion turbines, and multi-fuel steam turbines are the most likely cogenera-tion options for the immediate future, other tech-nology or fuel choices will be open to potentialcogenerators.

Spark=lgnition EnginesFiat recently introduced a natural gas-fired

spark-ignition cogenerator—called TOTEM–based on its automobile engines. Because theTOTEM modules are extremely small (15 kw),they may escape careful permitting by localauthorities. Proliferation of such cogenerators inurban areas could conceivably lead to air quali-ty problems.

EPA data indicate that gas-fired spark-ignitionengines have higher NOX emissions than diesels(sales-weighted average of about 4.6 lb/MMBtuv. about 3.5 lb/MMBtu for diesels) (39). On theother hand, Fiat and Brooklyn Union Gas claimNOX rates of about 3 lb/MMBtu as well as extraor-dinarily high thermal efficiencies (91 percent) thatwould maximize the emission displacement ofthe cogenerator (6). Either emission level can pre-sent a problem, however, because the smallTOTEM engines would not be subject to the pro-posed NSPS for stationary internal combustionengines, and even the lower rate is quite high incomparison with competing combustion sources.

Alternate-Fuel DieselsAlthough natural gas/diesel fuel mixtures and

straight diesel fuel are used in stationary dieselstoday, residual fuel currently is used in largemarine diesel engines and will be available forstationary engines. Coal-derived fuels in the formof synthetic oil, coal slurry, and dry powderedcoal may be used in future engines (see ch. 4).

Use of residual oil in diesels should affect SOX

emission levels because residual oil generally hashigher sulfur levels than distillate fuels. Accordingto available data, however, levels of other emis-sions should not be affected significantly in com-parison to current diesels (27). Diesels using coal-derived synthetic residual oil exhibit similar char-acteristics, although synfueis that have not beenhydrotreated will contain levels of fuel-boundnitrogen that are generally higher than those innatural oils and consequently will cause elevatedNOX emissions (24).

The use of coal slurries and powdered fuelsshould adversely affect levels of NOX, SOX, andparticulate. Table 55 shows expected values of

Table 55.-Emissions From Oii- and Coai-Fired Dieseis

Emissions (lb/M MBtu)Fuel NO. so.. ParticulateDiesel Oila . . . . . . . . . . 3.46 0.2c 0.07Coal slurryb . . . . . . . . . 3.61 l .5d 3.26Coalb . . . . . . . . . . . . . . . 4.35 1 .5d 8.91aSource is app. A.bReference 47.cAssumes 0.2% sulfur distillate oil.dAssumes 2% sulfur coal, 25 MMBtu/ton.


these fuels compared to average emissions fromoil-fired diesels. The level of particulate emissionsis so high as to virtually guarantee that an uncon-trolled coal-fired engine would be environmen-tally unacceptable. Based on an extrapolationfrom ConEd modeling studies (19), it is possiblethat a proliferation of such diesels in urban areaswould create significant problems with all threepollutants unless emission controls were used.

Atmospheric Fiuidized Bed

Steam turbines using coal-fired atmosphericfluidized bed (AFB) boilers can achieve low SOX

emission rates without generating large amountsof scrubber sludge, and probably will have NOX

emissions below current NSPS for steam turbines.Although the action of the bed creates potentiallyhigh levels of particulate emissions, baghousecontrols should keep actual emissions to ve~ lowlevels. The AFB boiler at Georgetown Universi-ty in Washington, D.C. (which is a potentialcogenerator although it currently does notgenerate electricity) has now been operatingwithout environmental complaints for a fewyears.

Closed-Cycle Gas Turbines

Closed-cycle gas turbines use an external heatsource to produce high-temperature gas. Al-though emissions depend on the nature of theheat source and fuel used, emission controlshould present no unusual problems.

Methanol-Fired Gas TurbinesThere is a reasonable probability that signifi-

cant quantities of methanol from biomass andcoal resources may become available within afew decades. Methanol is a suitable fuel for gasturbines and might be an advantageous fuel inturbine cogenerators because of the expectedsubstantial drop in NOX emissions. Methanol hasachieved 76-percent reductions in NOX emis-sions from large turbines because it has a signifi-

cantly lower combustion temperature than dis-tillate fuels (28).

Policy Options: Removing Environment=Associated Regulatory Impediments

In general, Federal, State, and local authoritiestreat cogenerators in an identical fashion withother stationary combustion sources. For exam-ple, both Federal NSPS and local emission stand-ards for all combustion sources are tied to fuelinput rather than energy output, and thus do notconsider the energy efficiency of the system. Inother words, two diesel generators that use thesame amount of fuel are limited to the same levelsof emissions, even if one produces more usableenergy than the other. Also, facilities are desig-nated as “major sources” subject to PSD andnonattainment review only on the basis of theiremissions output, without consideration of anyemissions reductions their use might cause inother facilities. Finally, new sources locating innonattainment areas are awarded emission off-sets only to the extent that other sources withinthe same locale agree to reduce their emissionspermanently and transfer the pollution rights ob-tained by the reduction to the new source. Thus,cogenerators are not automatically given pre-ferred treatment to account for their increasedefficiency or their displacement of centrallygenerated electricity.

It has been suggested that cogenerators shouldbe given various types of preferred treatment withregard to air quality concerns to facilitate theirmarket entry (12, 16,22). Two basic changes thathave been recommended are:

That emissions standards account for highcogenerator efficiency, either by being tiedto the energy output rather than the fuel in-put of the source, or by having separate(more lenient) standards for cogenerators.That restrictions on new sources under PSDand nonattainment area provisions of theClean Air Act (see ch. 3) be reduced or elimi-nated for cogenerators. For example, the


250-tpy emissions trigger could be relaxedby allowing the cogenerator to subtract emis-sions that are eliminated at the central powerstation. Only if net emissions exceed the trig-ger levels would the provisions apply. An al-ternate or additional policy would be to shiftthe responsibility for obtaining emissions off-sets to the State, or to allow the cogeneratorto count any reduction in central stationpower generation as an offset.

Each of these policy alternatives is evaluatedbelow.

Emission Standards Based on OutputBecause cogenerators generally produce con-

siderably more useful thermal and electric energythan the same equipment generating only elec-tricity, basing emission standards on energy out-put rather than fuel input would significantlyreduce the emission control requirements for co-generators and should lower their overall costs.Thus, this policy would make cogeneration morecompetitive in the marketplace, although the ex-tent of any advantage will vary substantially fromcase to case.

The major environmental argument for this pol-icy alternative is that, for a given amount of usefulenergy, a cogenerator will produce less pollutionthan a separate generator and thermal energysource and thus should be rewarded for this ben-efit (4,41 ). This argument generally is valid onlywhen a cogenerator would replace an otherwiseidentical generator, using the same technologyand fuel. As discussed above, many cogeneratorapplications involve new technology or fuelsubstitutions (e.g., diesel cogenerators replacingsteam turbines and boilers or furnaces), as wellas changes in scale. As shown in the section onemissions balances, the net result is quite oftenan emissions increase. Furthermore, the pollu-tion impact of most concern often is the local airquality impact, and this may not be improved bythe reduced emissions at a distant powerplant asa result of the addition of cogeneration. Finally,the legislative philosophy associated with NSPSis that all important new stationary sources shouldapply the best control technology available tothem, taking into account energy, economic, and

non-air quality environmental factors. Somepotential cogenerators might try to argue thatthese energy and other considerations justify adifferent interpretation of “best technology” intheir case. Based on the analysis of the environ-mental costs and benefits of cogeneration in thisreport, however, it appears that such an argu-ment would not be valid for all cogenerators.Thus, cogeneration emission standards based onenergy output should only be applied on a case-by-case, or technology- and area-specific basis,if at all.

Changes in Offset Requirements

As shown in table 56, the costs incurred in be-ing designated a “major source” under eitherPSD or nonattainment area provisions are highand will affect the economic attractiveness ofcogeneration (17). In addition to the costs of per-forming the necessary environmental analyses,the added costs of obtaining emissions offsets (ifany are available) and installing lowest achievableemission rate (LAER) controls may effectivelyblock cogenerators (and most other types of sta-tionary sources) from locating in nonattainmentareas. Thus, policies that reduce or eliminate thereview requirements (and, for nonattainmentareas, the offset requirements) for cogeneratorswould be removing important impediments tothese technologies.

The major argument against automatically cred-iting the reduction in central station power re-quirements in applying PSD and nonattainment

Table 56.-Approximate Costs of Procedures RequiredUnder the Clean Air Act

cost toProcedure cogeneratorEngineering review . . . . . . . . . . . . . . . . . . . . . $100-500Stage 1 PSD review (attainment) . . . . . . . . . $1,000-2,000Monitoring—1 year

One pollutant . . . . . . . . . . . . . . . . . . . . . . . . $30,000Six pollutants. . . . . . . . . . . . . . . . . . . . . . . . $125,000

Stage 1 interpretive ruling(nonattainment) . . . . . . . . . . . . . . . . . . . . . . $2,000

TSP/S02 modeling . . . . . . . . . . . . . . . . . . . . . .$10,000-20,000NOTES: Any of these costs may or may not be incurred, depending on the in-

dividual case. These figures assume a simple, “major source” case.

SOURCE: Office of Technology Assessment, from Michael S, Dukakis, Gover-nor’s Commlss\on on Cogeneratlon, Cogeneration: Its Beneflts to NewEngland (Governor of Massachusetts, October 1978).


rules is that the benefit of this reduction to theairshed in question is often either illusory or verydifficult to calculate. As noted previously, the cor-responding emission reduction may be out of theairshed altogether, or the reduced power require-ments may be shifted among different plants atdifferent times according to the utility’s economicdispatch methods and the overall supply/demandbalance of the grid. Also, when the central pow-erplant has a very tall stack, its effect on the airquality of a particular airshed maybe far less, perunit of power, than the effect of cogenerators.Finally, in the case of a large new cogenerator,the “offset” utility emissions may be from a pro-jected powerplant rather than from an existingfacility. Because any future powerplant wouldhave to comply with PSD or nonattainment re-quirements if its emissions affected the airshed,it is not logical that the plant’s replacement or“offset” —the cogenerator—should be freed fromthese requirements.

To summarize, these policy alternatives do ap-pear to be attractive if the primary objective isto promote cogeneration. However, widespreadapplication of regulatory relief to cogeneratorsas a class is difficult to justify on environmentalgrounds. On the other hand, the existence ofsituations where air quality benefits and oil sav-ings will accrue from cogenerators may justifyawarding some relief on a case-by-case or tech-nology- and area-specific basis.

Other Potential Impacts

Although the potential air quality effects are themajor environmental concern associated with co-generation systems, potential impacts from waterdischarges, solid waste disposal, noise, and cool-ing tower drift are important and must be ad-dressed satisfactorily to avoid local opposition tothese cogenerators.

Water Quality

Water discharges are associated primarily withblowdown from boilers and wet cooling systems.Pollutants of concern are suspended solids, salts,chlorine, oil and grease, and chemical corrosioninhibitors. For large coal-fired steam turbinecogenerators, potential discharge sources include

runoff from coal storage piles, scrubber effluentfrom S02 control systems, and discharges fromash quenching. These discharges are the sameas would occur in conventional steam turbinecombustion systems, although any wet coolingsystems clearly would be smaller because muchof the waste heat is captured in a cogeneratorand need not be discharged to the environment.Some of the discharges may present special prob-lems, however, because the cogenerators maybe located in urban areas whose sewage treat-ment facilities are not designed to handle in-dustrial discharges. Onsite pretreatment (beforedischarge into the municipal system) may benecessary to avoid problems from these dis-charges.

Solid Waste Disposal

Disposal of ash and scrubber sludge could alsopresent some difficulties for urban and suburbancoal-fired cogenerators due to the lack of securelandfill areas. Municipal landfills may be inade-quate due to the toxic metals content of the ash,and long-distance and expensive shipping ofthese wastes might be necessary.

Noise

Operating cogenerators and trucks supplyingfuel to cogenerators may produce high noiselevels in urban areas. For example, a recent studyof the Jersey City Total Energy Demonstrationproject, which uses diesel cogeneration, meas-ured sound levels of 65 dB(A) (loud enough tointerfere with a normal conversation) at a distanceof 75 ft from the equipment building (1 3). Thismight be considered unacceptably loud for anight-time noise level in a residential area. Similar-ly, the noise from fuel trucks may be considereddisruptive, although the effect of supplying oil-fueled furnaces and boilers may be as disruptive,if not more so, because furnaces and boilers arelikely to require more frequent fuel deliveries thancogenerators. In any case, noise control measuresare readily available. These include careful sched-uling of fuel deliveries, installing mufflers, or add-ing sound absorbing materials to equipment andbuildings to reduce engine noise.


Cooling Tower DriftCooling tower drift-the discharge and disper-

sal of small droplets of water from wet coolingtowers—is a potential source of problems inurban areas. These droplets will contain anticor-rosion chemicals and biocides and will have ahigh salt content caused by the concentrating ef-fect of the evaporative cooling. In the Jersey City

quate maintenance of the system led to spottingof nearby automobiles and an annoying mistingof pedestrians (1 3). Although the effects in theJersey City case appear to represent a nuisancerather than a hazard, negative community reac-tion to this as well as other visible adverse effectsof cogenerators may play a significant role in theirfurther deployment.

demonstration project mentioned above, inade-

POTENTIAL REGULATORY BURDEN ON ENVIRONMENTAL AGENCIESCogeneration usually involves shifting environ-

mental impacts-primarily effects on air quality—away from a few central powerplants to a largernumber of small sources. Although cogenerationwill not be subject to as many permitting require-ments as large central generating plants (see ch.3), multiple installations could lead to increasedpermit applications and more sources that mustbe monitored and inspected. In some areas, Stateand local environmental protection agencies maynot have the resources to accommodate such anincrease in their workload. If this is the case,cogenerators could be inadequately monitoredand controlled, and substantial adverse impactscould occur (see discussion of environmental im-pacts, above). *

To determine whether cogeneration would sig-nificantly increase the workload of environmen-tal agencies, OTA first estimated current work-loads and resources of the various Federal andState permitting agencies in two States–Coloradoand California—based on interviews with agen-cy personnel.** Those interviews also revealedcurrent management concerns about existing andfuture caseloads. Then the increased permitting,monitoring, and enforcement responsibilities at-tributable to cogeneration were calculated fromState agency market penetration projections, andcompared to the existing workloads to determinethe potential regulatory burden.

*The analysis in this section is drawn from Energy and ResourceConsultants, Inc. (17)0

**In Colorado, the Department of Natural Resources, the Officeof Energy Conservation, and the Colorado Energy Research Institutewere contacted. In California, the California Energy Commissionand the Cogeneration Task Force were contacted.

The results of this analysis suggest that cogen-eration is likely to have a minimal impact on en-vironmental caseloads in these two States be-cause the increase in agency resources neededto regulate cogeneration is very small when com-pared to existing workloads. Possible exceptionswould be areas where agencies were already un-derstaffed prior to the Federal (and many State’s)budget reductions of 1981 and 1982–usuallywater quality and right-of-way programs, orwhere economic or other legislative incentiveprograms for cogeneration impose significantnew responsibilities on agency staff.

Environmental Permitting andEnforcement Agencies

Four regulatory agencies in Colorado havedirect jurisdiction over cogeneration facilities,while approximately seven others regulate asso-ciated facilities such as transmission and distribu-tion systems.

Permitting and enforcement of the Clean AirAct are shared by the region Vlll offices of EPAand the Air Pollution Control Division of the Col-orado Department of Health. The division admin-istered approximately 400 permits in 1980 andconducted approximately 4,900 inspections. Dis-cussions with agency personnel revealed nomajor enforcement problems in 1980. EPA regionVlll administers the PSD program in Colorado.They processed 40 to 50 permit applications in1980 and they typically conduct oversight inspec-tions of roughly 10 percent of the major sourcesin the State each year.

Ch. 6—Impacts of Cogeneratlon . 243

The water programs are administered by theWater Quality Control Division of the StateDepartment of Health and by the Army Corps ofEngineers. The Water Quality Control Divisionadministers the section 401 and the NationalPollution Discharge Elimination System (NPDES)permits. The section 401 program (primarily ap-plicable in this context to transmission anddistribution systems) had one staff member whoissued 200 water quality certificates in fiscal year1980. The NPDES program also suffers from in-sufficient manpower; almost 300 applications fornew permits or for amendments to existing per-mits were awaiting action at the end of 1980.Time pressures on the staff members are felt toimpair the quality of the reviews for permits be-ing issued, possibly resulting in inadequate con-trols. The Water Quality Control Division initiates30 to 45 enforcement actions per year, but manyviolations by minor sources are ignored due tolack of manpower.

The Army Corps of Engineers administers thesection 404 permits through their district officesin Sacramento and Omaha. The Sacramento Dis-trict maintains an area office in Grand Junction,Colo., with three full-time personnel. In 1980, thisoffice issued approximately 40 applications forsection 404 or section 10 permits in process,50 violations (generally involving unpermittedwork—their biggest problem), and 150 to 175 in-dividual permits (these have a normal term of 3years, with extensions available). They also super-vised approximately so operations under generalpermits.

Applications for rights-of-way in Colorado arehandled by the State Board of Land Commissions,the Bureau of Land Management (BLM), and theU.S. Forest Service. Right-of-way applicationshave been a bottleneck in the permitting process,with application processing lasting up to 1 year.

In summary, the programs concerned withwater quality (sec. 401, sec. 404, NPDES) are atpresent less effective than they might be, duelargely to manpower limitations. Delays in proc-essing right-of-way applications in the district of-fices of BLM and the Forest Service, which inlarge measure reflect manpower limitations,change from year to year and district to district,

reflecting the variability in applications filed andresources at each district. If dispersed facilitiessharply increased the number of right-of-way ap-plications, this permit could become a severe bot-tleneck.

California environmental agencies are sub-divided into numerous regional and district of-fices (see ch. 4). For example, 46 separate airpollution control districts (APCDS) are responsi-ble for administering air permits and each districthas different permitting requirements. As a result,only sampled agency districts or regions that areconsidered representative are discussed ex-plicitly.

The 46 APCDS in California vary from ruralcounties with one full-time employee, to the BayArea and South Coast Air Quality ManagementDistricts with over 200 and 400 full-timeemployees, respectively. The Sacramento CountyAPCD employs two people to permit 150 to 200sources per year. permits require up to 2 monthsto be processed. There are no sources in thedistrict with continuous monitoring, and one ofthree inspectors visits each major source fromtwo to five times per year. Telephone contactswith these and other APCDS revealed no majorenforcement concerns in 1980.

The nine Regional Water Resources ControlBoards administer the waste discharge require-ment program in California. Region 5, head-quartered in Sacramento, has approximately 20personnel to handle all phases of the program.Approximately 150 permits are issued each year,25 percent of which are NPDES permits. Majorsources are inspected twice a year, minor sourcesperhaps once every 3 years, and about 2,000sources maintain self-monitors and reportquarterly to the regional board. Telephone con-tacts with these and several other regional boardsrevealed no major management problems.

California is included in two Corps of EngineersDistricts, Los Angeles and Sacramento. The “nav-igation” branch of the LOS Angeles District is incharge of permitting and enforcement under thesection 404 program. The Corps presently suffersfrom a manpower shortage, as revealed by theincreased number of unresolved violations (from

244 ● industrial and Commercial Cogeneration

66 to 78); enforcement generally is the lowestpriority action for the district.

Rights-of-way for dispersed generating facilitiesin California will be sought from three agencies:the State Lands Commission, BLM, and the ForestService. Conversations with agency personnel in-dicated that at present they were adequatelystaffed in 1980, with the possible exception of theForest Service.

In summary, the information collected regard-ing the caseloads and personnel of California en-vironmental agencies showed them to be, in gen-eral, better staffed than their counterpart agen-cies in Colorado. However, legislation enactedin California in 1981 that requires the State AirResources Board and the APCDS to mitigate theair quality impacts of cogenerators smaller than50 MW, and to secure offsets for them, could taxthe resources of the APCDS. Also, as in Colorado,the agencies administering the water programs(NPDES, sec. 404 and sec. 401 programs) appearto suffer from manpower shortages that result inlax enforcement. Finally, the rights-of-way forfacilities on Federal lands administered by BLMor the Forest Service could be a bottleneck in thepermitting process if the number of applicationsincreased significantly or the number of person-nel to process them decreased.

Potential Impacts on Agency Caseloads

Few market penetration estimates are availablefor cogeneration (see ch. 5). Therefore, to gaugethe effects of cogeneration permitting and en-forcement on agency caseloads, State agenciesprimarily responsible for cogeneration’s develop-ment or regulation were contacted and asked toprovide their best estimates for potential develop-ment through 2000. The results of this informalsurvey are presented in table 57. It should be em-phasized that these are not official or preciseestimates based on any formalized methodology,but instead typically were the result of “brain-storming” sessions held by agency personnel. Todetermine the permit and other regulatory re-quirements of the amount of cogeneration capac-ity shown in table 57, assumptions were madeconcerning, among other things, the size andlocation of the facilities.

Table 57.—Penetration Scenario for Cogenerationin California and Coiorado

MW capacitv installedYear California Colorado

1,700 1701990 . . . . . . . . . . . . . . . . . . . . 2,300 2301995 . . . . . . . . . . . . . . . . . . . . 3,600 3602000 . . . . . . . . . . . . . . . . . . . . 6,000 600SOURCE: Energy and Resource Consultants, Inc., Federal and State Environ-

mental Permitting and Safety Regulations for Dispersed ElectricGeneration Technologies (contractor report to the Office of TechnologyAssessment, 1980).

First, it was assumed that, in Colorado, all newcogeneration units will file an Air Pollution Emis-sions Notice (APEN). Second, PSD permits wereassumed to be required under the Clean Air Actfor all sources over 10 MW and for one-half ofthe sources under 10 MW. Third, 25 percent ofcogeneration units were assumed to require anNPDES, section 401 or 404 permit under theClean Water Act. Fourth, 25 percent of cogenera-tion units would require State and/or Federalrights-of-way, and 25 percent also were assumedto require consultations with wildlife and histor-ical agencies.

The market penetration assumptions and theirassumed regulatory requirements were combinedto estimate the increased agency responsibilitiesfor permitting and enforcement due to cogenera-tion. The results of this analysis must be viewedas one possible scenario out of many plausiblefutures due to the large uncertainties in workingwith informal market penetration estimates. How-ever, it can be stated that the results presentedbelow are a high estimate of the increasedregulatory burden because the deployment as-sumptions described above are based on size orsiting conditions that would result in many co-generators being subject to the full range ofregulatory requirements. If cogenerators tend tobe smaller or located in different areas, then theincrease in permitting and enforcement respon-sibilities would be less than that shown below.

Colorado

The projected increases in agency workloadsin Colorado due to the future deployment of co-generation technologies are presented in table58. There is expected to be an increase of less


Table 58.—increase in Agency Workloads Due to the Deployment of Cogeneration Technologies in Colorado

Projected average increasesin cases per yearCurrent

Agencv staffCurrent

1981-85 1988-90 199; -95 1998-2000case load1. Air Pollution Control Division, Colorado

Department of Health:1. Air Pollution Emission Notices. . . . . . . . . 42. Inspections. . . . . . . . . . . . . . . . . . . . . . . . . . 20

Il. Region VIII–EPA:1. PSD permits . . . . . . . . . . . . . . . . . . . . . . . . . 52. Inspections. . . . . . . . . . . . . . . . . . . . . . . . . . 8

Ill. Water Quality Control Division,Colorado Department of Health:

1. NPDES permits . . . . . . . . . . . . . . . . . . . . . . 122. Sec. 401 certificates . . . . . . . . . . . . . . . . . . 13. inspections . . . . . . . . . . . . . . . . . . . . . . . . . . 12

IV. Army Corps of Engineers, Omaha District:404 applications . . . . . . . . . . . . . . . . . . . . . . . 20a

Sacramento District:404 applications (Colorado only) . . . . . . . . . 4

V. State Board of Land Commissioners(right-of-way applications andcommercial leases) . . . . . . . . . . . . . . . . . . . . . . . 1

VI. BLM-State Office (right-of-wayapplications) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12

VII. State Division of Wildlife (consultations) . . . . 18Vlll. Colorado Historical Society

(consultations) . . . . . . . . . . . . . . . . . . . . . . . . . . . 6

480 26

318

439

781

45300

13

29

318

739

300200

1,000

113

116

22

15

475a 1 1 1 2

40 1 1 1 2

75 1 1 1 2

18575

11

11

11

22

1,200 1 1 1 2a For the entire district.

SOURCE: Energy and Resource Consultants, Inc., Federal and State Environmental Permlttlng and Safety Regulations for Dispersed Electric Generation Technologies(contractor report to the Off Ice of Technology Assessment, 1980).

than 1 percent in annual APEN filings due to co-generation during the 1981-85 period, and onlya 3-percent increase (over the 1980 base year)during 1996-2000. Increases in other types of per-mits are even smaller.

The impact on the number of inspections canbe greater (depending on the current caseload)due to the fact that a permit is only granted once,whereas each facility must be inspected everyyear. Thus, inspections are cumulative and theagency must inspect not only the facilities per-mitted this year, but also all facilities permittedin previous years that are still operating. Still, onlya 10-percent increase in the number of requiredair pollution inspections is shown through 2000.

California

Table 59 presents a similar estimate of thepotential impacts of cogeneration on agencyworkloads in California. These impacts are moredifficult to quantify because data on air and waterpermit applications are tabulated on a regional

or district basis, and statewide totals were notavailable. Table 59 is based on data from selectedCalifornia air and water quality districts that tendto be representative of the potential statewideagency impact, but the table does not includethe impact of the 1981 legislation (mentioned pre-viously) that shifts the burden of attaining offsetsunder the nonattainment area provisions of theClean Air Act to the local APCDS.

Table 59 shows that the projected number ofair and water permit applications for cogeneratorsand the subsequent enforcement cases is greaterin California than in Colorado due to the largerassumed penetration of cogeneration in Califor-nia. However, California agencies tend to havemore staff and other resources and thus theoverall workload impact can be expected to beroughly similar. But, several of the California en-vironmental agencies already are overextendedand even a minor increase in the workload orreduction in staff may be difficult to accom-modate under present conditions.


Table 59.—increase In Agency Workloads Due to the Deployment ofCogeneration Technologies in Caiifomia

Projected average increasesCurrent Current in cases per year

Agency staff case load 1981-85 1986-90 1991-95 1996-20001. California Air Quality Division

State-wide total . . . . . . . . . . . . . . . . . . . . . . . . 1,000+ NA 20 17 37 41Sacramento District:

1. New Source Review . . . . . . . . . . . . . . . . . . 2 175 1 1 12. Inspections . . . . . . . . . . . . . . . . . . . . . . . . . 3 3 6 9 12

II. Water Resources Control BoardState-wide total . . . . . . . . . . . . . . . . . . . . . . . . NA NA 5 4 9 10

Region 5—Sacramento:1. Waste Discharge Requirementa . . . . . . . . 20 150 22.inspections . . . . . . . . . . . . . . . . . . . . . . . . . — 1,500 3 6 9 12

Region 9—San Diego:1. Waste Discharge Requirementa . . . . . . . . 2 8 1 2 22. Inspections . . . . . . . . . . . . . . . . . . . . . . . . . 17 1,000 3 6 12 18

Ill. Army Corps of EngineersLos Angeles District:

404 applications . . . . . . . . . . . . . . . . . . . . . . . 11 120 3 2 5 6IV. State Lands Commission

(rights-of-way) . . . . . . . . . . . . . . . . . . . . . . . . . 100 450 5 4 9 10V. BLM State Office

(rights-of-way) . . . . . . . . . . . . . . . . . . . . . . . . . 15 150 5 4 9 10VI. Fish and Game Department

(consultations) . . . . . . . . . . . . . . . . . . . . . . . . . 35 10,OOO 10 9 19 20VII. Office of Historic Preservations

(consultations) . . . . . . . . . . . . . . . . . . . . . . . . . 4 20 10 9 19 20NA - Not available.aThis encompassed both the 401 and NPDES permit programs.

SOURCE: Energy and Resource Consultants, Inc., Federal and State Environmental Permitting and Safety Regulations for Dispersed Electric Generation Technologies(contractor report to the OffIce of Technology Assessment, 1980).

Summary

The data in this discussion show that, in mostcases, the deployment of cogeneration shouldonly increase State and Federal agency caseloadsby a small percentage. The resulting increases instaff workloads vary depending on present loadand resources. But many of the agencies currentlyare understaffed and not able to handle their pres-ent caseload. Thus, even small percentage in-creases in workload would represent a substan-tial burden for these agencies. Moreover, under

current policies designed to reduce Federal agen-cy budgets and staff resources and turn over moreof the responsibility for permitting, monitoring,and enforcement to already understaffed Stateagencies, the impact of cogeneration may bemore significant than suggested by these data. Ifthis is the case, then cogeneration projects couldbe delayed in the permitting process, or couldbe reviewed inadequately resulting in insufficientcontrols and enforcement, and therefore a greaterpotential for adverse environmental impacts.

ECONOMIC AND SOCIAL IMPLICATIONS

Cogeneration (and other onsite generating institutions traditionally involved in the supplytechnologies) has attracted widespread attention and demand of electric and thermal energy.not only for its potential benefits and costs for Many analysts feel that, as global stocks of oil andenergy efficiency, the environment, and utility natural gas dwindle, major changes must occurplanning and operations, but also for its possi- in the technical, economic, and institutional con-ble implications for the economic and political text for energy supply and demand in industrial-


ized societies. Cogeneration and small powerproduction are likely to be a part of these energysystem changes. Moreover, many people ad-vocate the use of dispersed generating technol-ogies not solely because of the perceived tech-nical, economic, or environmental advantages,but also due to the belief that an energy systembased on these technologies will be more com-patible with traditional democratic, participatory,and pluralistic institutions than a strategy basedon continued reliance on large-scale centralizedtechnologies. Although a thorough assessment ofthese implications is beyond the scope of thisreport, some general considerations are discussedbelow.

In general, there are two ways in which tech-nological change can be associated with socialor political change: 1 ) a change in the number,type, or responsibilities of organizations asso-ciated with the production, distribution, and/oroperation of a technological system; and 2) themore general benefits and costs for individuals,groups, and society as a whole. In the contextof cogeneration, the first type of change relatesprimarily to those institutions described in chapter3–the traditional suppliers, users, and regulatorsof electric energy, while the second set of impactsconcerns the likelihood of cogeneration’s result-ing in greater centralization or decentralizationin social organization.

The general background for an analysis of thesocial and political implications of cogenerationis described in chapter 3, including the nationalenergy context, the current status of the electricutility industry, and the regulatory and institu-tional aspects of cogeneration. Clearly a funda-mental feature of the electric utility industry-itsability to provide a reliable supply of electricityat a relatively low price while maintaining itsfinancial health–has changed dramatically in re-cent years. Virtually all aspects of the technologi-cal and institutional context of the industry havecontributed to this change: capital and fuel costincreases and environmental concerns have lim-ited the choice of generating technologies andoperating conditions, and have increased theprice of electricity significantly. At the same time,the rate of demand growth has declined substan-tially, resulting in excess utility capacity in many

areas, which has contributed to utilities’ finan-cial problems. As a result of these recent changesin the status of electric utilities, the industry andits customers and regulators have sought alter-nate means of achieving the goal of reliable serv-ice at a low price. One such means is throughsmall-scale generating technologies such as co-generation.

The widespread use of cogeneration couldbring a wide array of changes to the contextdescribed in chapter 3. In general, these changescan affect the roles, responsibilities, or authorityof energy suppliers or consumers and the rela-tionships among them. Thus, with cogeneration,the traditional roles of utilities—as suppliers ofelectricity—and their customers would have tobe recast as former customers feed cogeneratedpower into the grid, and thus become suppliersof electricity themselves. Alternatively, electricutilities could own dispersed cogeneration ca-pacity and establish a new role for the industryas providing alternative energy supply options(and, in most cases, a new product–thermalenergy) rather than merely facilitating thedevelopment of those options by other parties.

This section focuses on the economic and so-cial implications of cogeneration for utilities andtheir customers. It begins with an analysis of thepotential capital cost and employment impactsof three scenarios for cogeneration market pen-etration, discusses the effects of the scenarioresults on utilities’ planning and operation, andthen briefly outlines some potential impacts inother economic sectors. The section concludeswith a review of cogeneration’s implications forthe centralization or decentralization of electricitygeneration.

Economic Impacts

Due to the large number of uncertainties aboutfuture energy development patterns, it is extreme-ly difficult to develop a quantitative—or evenqualitative—basis for comparing the economiccharacteristics of these different developmentscenarios. For example, the rate of growth in elec-tricity demand, the rate of inflation, future capitalcosts for powerplant construction, and changesin the regulatory climate all may affect the future

—


costs and deployment characteristics (e.g., plantsize) of utility generating capacity. Similarly,uncertainties about ownership, future capitalcosts, and the choice of technologies make it dif-ficult to project the economic effects of thewidespread use of cogeneration. Furthermore,due to the lack of recent cogeneration ex-perience, reliable data are not available for itemssuch as the operating and maintenance (O&M)labor required for cogenerators. Without a largecomputer modeling effort, clearly beyond thescope of this assessment, it is not possible todetermine the sensitivity of the economic impactsof cogeneration development to these uncertain-ties.

However, OTA wanted to be able to define theproblem areas in order to lay the groundwork forfuture impact assessments. Therefore, OTA de-veloped three rough market penetration esti-mates for cogeneration. The assumptions under-lying these rough estimates and their derivationare reviewed briefly, and then the ranges of im-pacts that could be associated with each estimateare discussed.

Market Penetration Scenarios

A wide range of penetration estimates are avail-able in the literature on cogeneration and aredisplayed in table 60. The highest estimate shownin the table—which represents 10 to 16 percentof total projected electricity generation capacity

Table 60.-Market Penetration Estimatesfor Cogeneration

Source MW QualificationsFERC 5,910 Estimate of the marginal increase in

cogeneration capacity caused byPURPA by 1995.

FERC 27,405 Estimate of the potential forcogeneration capacity in 1995.

ERA 1,312 Amount initially allowed under FUAregulations.

ERA 3,920 Likely cogeneration penetration by 1990.ERA 45,190 Maximum oil/gas-fired generating

capacity potentially displaceable bycogeneration.

SERI 93,000 Amount of central station baseloadcapacity potentially displaceable bycogeneration.

KEY: FERC—Federal Energy Regulatory Commlssion; ERA—Economic Regula-tory Admlnistration; and SERI—Solar Energy Research Instltute.


in the year 2000-is around 70 times larger thanthe smallest. To bracket the ranges of penetra-tion estimates, OTA chose three estimates. Thefirst, a penetration of 50,000 MW by 2000, is anapproximation of the Economic Regulatory Ad-ministration’s high estimate for the maximumoil/gas electric generating capacity potentiallydisplaced by cogeneration. The implementationof 50,000 MW of cogeneration would representapproximately 5 to 8 percent of total projectedinstalled generating capacity in 2000. Second, asthe middle range, OTA chose the high numberin table 60—approximately 100,000 MW of co-generation–which would represent 10 to 16 per-cent of potential installed generating capacity in2000. Finally, in order to gauge the impacts ofphenomenal success, OTA postulated a penetra-tion of 150,000 MW by 2000, which would be16 to 24 percent of total projected installedcapacity.

Once these three penetration estimates wereestablished, it was necessary to disaggregate forthe types of utility generating capacity that wouldbe backed out by cogeneration and in what partsof the country. In order to do this it was assumedthat:

●

●

●

●

●

●

30 percent of existing oil-fired steam gen-erating capacity would be converted to coalor permanently retired;oil-fired steam plants would be backed outbefore gas-fired steam plants;only oil- and gas-fueled capacity would bebacked out (i.e., no coal, nuclear, hydro, orother non-oil/gas capacity is replaced by co-generation);steam plants would be backed out beforecombustion turbines;oil-fired combustion turbines would bebacked out before gas-fired combustion tur-bines; andno utility region would replace all its com-


●

●

●

by 2000 and would not be available forreplacement by cogeneration;of the remaining 70 percent of oil steamcapacity, approximately 40 percent wouldbe replaced by cogeneration;approximately 40 percent of the gas steamcapacity would be replaced by cogenera-tion; andapproximately 1 percent of the oil-firedcombustion turbine capacity would bebacked out by cogeneration.

2. 100,000 MW penetration by 2000:● 30 percent of oil steam would be con-

verted or retired, and 75 percent of theremainder would become cogeneration;

. 75 percent of the gas steam capacitywould be backed out;

. 18 percent of the oil combustion turbinecapacity would be replaced by cogenera-tion; and

. 11 percent of the gas combustion turbinecapacity would be replaced by cogener-ation.

3. 150,000 MW penetration by 2000:●

●

●

●

30 percent of the oil steam capacity wouldbe converted or retired, and 100 percentof the remaining oil steam would becomecogeneration;100 percent of the steam gas capacitywould be backed out by cogeneration;70 percent of the oil combustion turbinecapacity would be replaced by cogenera-tion; and30 percent of the gas combustion turbinecapacity would become cogeneration.

These assumptions were applied to the nineNorth American Electric Reliability Council

regions based on 1981 regional oil and gas steamand combustion turbine capacity (i.e., theanalysis assumes no new oil/gas capacity will bebrought on-line after 1981, regardless of utilityannounced plans). Thus, these penetration esti-mates do no necessarily correspond to the re-gional cogeneration opportunities that have beenidentified in the literature. This is simultaneous-Iy a result of the linear approach to the analysisand a desire to gauge the impacts of overwhelmi-ng success for cogeneration policy and financialincentives. The results of this exercise are shownin detail in table 61.

Financial and Employment impacts

It has been claimed widely that investment insmaller capacity increments, such as cogenera-tion systems, would contribute to the improvedfinancial health of the electric utility industry.Therefore, OTA undertook a comparison of thecapital costs of the scenarios in table 61 with andwithout cogeneration. For the base case—utilitydevelopment of 50,000, 100,000, and 150,000MW of capacity without cogeneration—two setsof assumptions were used (see table 62). The first(Case A) uses coal-fired plants with scrubbers tomeet all the baseload capacity requirements. Thecapital cost for baseload coal was set at $1,014/kW (1980 dollars), the same figure used in model-ing commercial cogeneration opportunities (seech. 5). In the second base case (Case B), 50 per-cent of the baseload capacity was assumed to becoal-fired (at $1,01 4/kW) and the other 50 per-cent assumed to be nuclear powered (at $1,400/-kW, the average cost, including interest duringconstruction, for those plants that came on-linein 1979-80) (30). In both base cases, peaking

Table 61.—Scenarios for Cogeneration Implementation

50,000 MW 100,000 MW 150,000 MW

Steam oil Steam gas CT oil CT gas Total Steam oil Steam gee CT oit CT gas Total Steam 0il Steam gas CT Oil CT gas Total

ECAR . . . . . . . . . . . . . . . . . 1,190 60 21 – 1,271 2,170 120 360 115 2,765 2,66S 157 1,478 306 4,629ERCOT. . . . . . . . . . . . . . . . – 12,400 1 – 12,401 – 23,260 10 150 23,420 – 31,010 40 398MAAC . . . . . . . . . . . . . . . . 3,350 – 72 – 3,422 0,300

31,448— 1 , 3 0 0 7,625 8,366 – 5,054 68 13,510

MAIN . . . . . . . . . . . . . . . . . 1,210 200 18 – 1,428 2,275 390 320 125 3,110 3,033 514 1,245 329MARCA . . . . . . . . . . . . . . . 150

5,12165 31 – 266 285 160 565 10 1,020 376 213 2,196 21 2,806

NPCC . . . . . . . . . . . . . . . . . 7,210 10 47 — 7,267 13,526 20650 5 14,401 18,035 26 3,309 21,379SERC . . . . . . . . . . . . . . . . . 5,260 70 103 – 5,433 9,665 140 1,630 12 11,647 13,150 184 7,122 33 20,489SPP . . . . . . . . . . . . . . . . . . 2,050 2,870 15 – 10,935 3,650 16,635 265 120 20,870 5,130 22,179 1,031 322 28,662WSCCc . . . . . . . . . . . . . . . . 6,540 1,000 37 – 7,577 12,271 1,875 675 101 14,992 16,362NERC–U.S. totals. . . . . . 26,960

2,499 2,623 272 21,75622,695 345 – 50,000 50,542 42,600 6,195 663 100,OOO 67,362 56,782 24,098 1,758 150,000

CT - combustion turbine.



Table 62.—Assumptions Used to Compare Capitai Costs

Capital cost Amount installed (MW)Technology type ($/kW) 50,000 MW 100,000 MW 150,000 MW

Baseload:Coal-fired . . . . . . . . . . . .Nuclear . . . . . . . . . . . . . .

Peakload . . . . . . . . . . . . . . .

Diesels . . . . . . . . . . . . . . . .Gas turbines. . . . . . . . . . . .Steam turbines. . . . . . . . . .Combined cycle . . . . . . . . .

Case A Case B Case A Case B Case A— — —

$1,014 45,655 22,827.5 93,142 46,571 124,1441,400 0 22,827.5 0 46,571

200 345 345 6,858 6,858 25,85:Case C Case D Case C Case D Case C— — —

$350-800 12,500 2,500 25,000 5,000 37,500320-900 12,500 7,500 25,000 15,000 37,500

550-1,600 12,500 17,500 25,000 35,000 37,500$430-600 12.500 22.500 25.000 45.000 37.500


capacity was assumed to have a capital cost of$200/kW, the same figure used in the analysis inchapter 5.

Additional assumptions were needed to devel-op a capital cost comparison for meeting thesecapacity requirements with cogeneration. First,a mix of cogeneration technologies was estab-lished by selecting four mature systems–diesels,combustion turbines, steam turbines, and com-bined cycles–that represent a wide range of pos-sible cogeneration applications, and then choos-ing two sets of penetration mixes for the foursystems (see table 62). The first set (Case C)assumes that each of the technologies would con-tribute 25 percent of the capacity requirements.The second set (Case D) assumes that dieselswould contribute 5 percent, combustion turbines15 percent, steam turbines 35 percent, and com-bined cycles 45 percent. Capital costs for thesefour technologies vary widely depending on thesize of the system, the fuel used, and the in-dustrial or commercial application. Therefore, thefull range of costs given in chapter 4 was used(see table 18).

Table 63 shows the capital investment needsfor meeting the three capacity scenarios basedon these assumptions. As can be seen in table63, the assumptions used in estimating capitalcosts play a substantial role in determining theimpact of substituting cogeneration for central sta-tion capacity. For example, in the 50,000 MWscenario, the central station capital requirementsare as much as 90 percent higher than those forlower cost cogenerators, and up to 17 percentlower than those for higher cost cogenerators.

Case B

62,07262,07225,856

Case D

7,50022,50052,50067,500

Similarly, the mix of technologies affects the costcomparison, with Cases A and C having signifi-cantly lower capital requirements than Cases Band D. Equally wide ranges of results are shownfor the 100,000 and 150,000 MW scenarios.However, if the mean of the cogenerator casecosts is compared to the central station costs, thecogeneration cases require around 20 to 40 per-cent less capital than the central station cases.

Still greater uncertainties are introduced intothe capital cost comparison if one factors in in-terest costs and construction duration. The costof capital is heavily dependent on its source, in-cluding whether a project is financed throughdebt, equity, or internal funds; the source of debtor type of equity; and the interest rates and rateof return on equity. If one assumes that all fac-tors except construction duration are equal, thenthe cost of capital obviously would be lower forsmaller capacity increments such as cogenerationthan for large central station plants. However,high interest rates mean that the shorter Ieadtimefor cogenerators offers substantial short-termfinancing advantages over central station pow-erplants.

In addition to examining capital cost differ-ences, OTA also estimated differences in O&Mcosts for equal amounts of central station andcogeneration capacity. The same capacity as-sumptions as in the capital cost estimates wereused (see table 62), but additional assumptionshad to be made with regard to O&M costs andcapacity factors (see table 64). The results of theO&M cost comparison are shown in table 65. Ascan be seen in table 65, O&M costs show the

Ch. 6—impacts of Cogeneration .251

Table 63.—Comparison of Capitai Requirements (1980 dollars x 10°)

Without cogeneration With cogeneratlon Percent difference

Percent Percentdifference difference

Technology Case A Case B A-B Technology Case C Case D C-D A-C A-D B-C B-D

50,000 MW:Baseload. . . . . . . 46,294 54,106Peakload . . . . . . . 69 69

Total . . . . . . . . 46,363 54,175 15.5

100,000 MW:Baseload. . . . . . . 94,446 112,422Peakload . . . . . . . 1,372 1,372

Total . . . . . . . . 95,818 113,794 17.2

150,000 Mw:Baseload. . . . . . .125,680 149,642Peakload . . . . . . . 5,171 5,171

Total . . . . . . . . 131,051 155,013 16.8

50,000 MWDiesels . . . . . . . . . . . 4,375-10,000Gas turbines . . . . . . 4,000-11,250Steam turbines . . . . 6,875-20,000Combined cycle . . . . 5,375-10,000

Lowest total. . . . . 20,625Highest total . . . . 51,250Mean . . . . . . . . . . . 35,938

100,000 MW:Diesels . . . . . . . . . . . 8,750-20,000Gas turbines . . . . . . 8,000-22,500Steam turbines . ...13,750-40,000Combined cycle. . ..10,750-20,000

Lowest total. . . . . 41,250Highest total . . . . 102,500Mean . . . . . . . . . . . 71,875

150,000 MW:Diesels . ..........13,125-30,000Gas turbines . .....12,000-33,750Steam turbines . ...20,62540,000

875-2,0002,400-6,7509,625-28,0009,675-18,000

22,575 9 76.8 69.0 90.0 82.354,750 6.6 –10.0 –16.6 5.5 –1.138,663 7.3 25.3 18.1 40.5 33.4

1,750-4,0004,600-13,500

19,250-56,00019,350-36,000

45,150 9 79.6 71.9 93.6 66.4109,500 6.6 –6.7 –13.3 10.4 3.877,325 7.3 28.6 21.4 45.2 38.2

2,625-6,0007,200-20,250

28,875-64,000Combined cycle. . . . 16,125-30,000 29,025-54,000

Lowest total. . . . . 61,875 67,725 71.7 63.7 65.9 78.4Highest total . . . . 153,750 164,250 696 –15.9 – 2 2 . 5 0 . 8 – 5 . 8Mean . . . . . . . . . . . 107.813 115.988 7.3 19.5 12.2 35.9 28.8

aA negative percent difference means that cogeneratlon coats are higher, and a positive percent difference Indlcates that central station costs are higher.


Table 64.—Assumptions Used in Estimating Operating and Maintenance Costs

Annual fixed Variable ConsumableSize Capacity O&M cost O&M cost O&M cost

Type of equipment (MW) factor ($/kw) (mills/kWh) (mills/kWh)

Central station:Coal steam. . . . . . . . . . . . . . . 1,000 75% 12.9 0.90 2.6Light water reactor. . . . . . . . 1,000 75% 3.1 1.50 —Combustion turbine . . . . . . . 75 9% 0.275 2.925 —Cogeneration:Steam turbine . . . . . . . . . . . . 0.5-100 90%/45% 1.6-11.5 3.0-8.8 —Gas turbine . . . . . . . . . . . . . . 0.1-100 90%/45% 0.29-0.34 2.5-3.0 —Combined cycle. . . . . . . . . . . 4-100 90%/45% 5.0-5.5 3.0-5.1Diesel . . . . . . . . . . . . . . . . . . .0.075-30 90%/45% 6.0-8.0 5.0-10.0 –SOURCE: Off Ice of Technology Assessment.

same wide variation as capital costs, dependingon the mix of equipment types, sizes, and capaci-ty factors. In general, however, the figures in table65 suggest that O&M costs for cogeneration willbe lower than those for central station capacitywhen the cogenerators are larger units suitablefor industrial sites (i.e., steam turbines, combinedcycles), or when they are operating at a lowercapacity factor. Conversely, small cogeneratorswith a higher proportion of diesels and gas tur-bines, and those operating at a higher capacity

factor, tend to have higher O&M costs than cen-tral station capacity.

The labor requirements for construction andfor O&M of equivalent amounts of central stationand cogeneration capacity also were compared.This was extremely difficult due to a lack of con-sistent data. For example, estimated constructionwork-hour requirements by craft and region areavailable for central station capacity, but not forcogeneration. On the other hand, construction

Table 65.—Comparison of operating and Maintenance Costs (1978 dollars x 1Oa)

Without Cogeneration With cogeneration Percent differences

Percent Percentdifference

Percentdifference difference

Equipment Case A Case B A-B Equipment Case C90 Case D90 C90-D90 Case C45 Case D45 C45-D45 A-C90 A-D90 B-C90 B-D90 A-C45 A-D45 B-C45 B-D45

50,000 MW: 50,000 MW:Baseload . . . . . 16.388 11.151 Diesels . . . . . . . . 5.67&10.655 1.136-2.171 3.214-5.83 0.643-1.lWPeakload . . . . . 0.009 0.009 Gas turbines . . . 2.5-3.0 1.5-1.8 1.266-1.521 0.761-0.912

Total . . . . . . 16.397 11.180 36.0 Steam turbines . 3.156-10 .11 4.419-14.154 1.6705.774 2.350-8.063Combined cycle 3.58-5.714 6.447-10.285 2.103-3.2 3.786-5.761

Lowest total . 14.914 13.502 9.9 8.263 7.54 9.2 9.5 19.4 –28.8 –19.0Highest total . 29.679 28.410 4.4 16.425 15.942 3.0 –57.7 –53.6 –90.7 –87.2Mean. . . . . . . . 22.297 20.958 6.2 12.344 11.741 5.0 –30.5 –24.4 –88.6 –61.0

100,000 Mw: 100,000 MW:Baseload . . . . . 33.434 22.750 Diesels . . . . . . . . 11.36-21 .71 2.27434 6.43-11.88 1.266-2.37Peakload . . . . . 0.179 0.179 Gas turbines . . . 5.0-6.0 3.0-3.6 2.54-3.04 1.522-1.825

Total . . . . . . 33.613 22.929 37.8 Steam turbines . 6.313-20.22 8.636.28.31 3.36-11.55 4.7-16.185Combined cycle 7.163-11.425 12.89-20.57 4.2-6.4 7.57-11.52


150,000 MW: 150,000 MW:Baseload . . . . . 44.582 30.322 Diesels . .......17.03-32.6 3.414.513 9.64-17.78 1.93-3.58Peakload . . . . . 0.676 0.676 Gas turbines . . . 7.5-9.0 4.5-5.4 3.6-4.% 2.28-2.74

Total . . . . . . 45.236 30.996 37.4 Steam turbines . 9.47-30.33 13.26-42.46 5.035-17.32 7.05-24.25Combined cycle 10.7$17.14 19.34-30.85 6.31-9.6 11.36-17.28


aA negative percent difference means that cogeneratlon costs are higher, and a positive percent difference indicates that central~ station costs are higher.


88.0 74.0 29.8 36.7–0.2 2.8 –36.2 –35.328.2 33.1 –10.7 –5.1

88.1 76.1 32.4 41.32.3 5.3 –35.6 –32.7

30.6 35.5 –7.4 –2.4

58.4 88.7 22.3 31.3–8.5 –5.6 –45.5 –42.720.0 24.9 –17.7 –12.8

Ch. 6–Irnpacts of Cogeneration ● 253

labor costs are available for cogenerators, butusually are not broken out in surveys of centralstation installation costs. Moreover, labor re-quirements and costs for central station capaci-ty vary widely by region and type and size ofcapacity.

However, in order to derive broad estimatesfor comparison purposes, the available data wereapplied to the three scenarios described abovebased on the capital and O&M cost estimates intables 63 and 65. To estimate cogeneration con-struction labor requirements in work-hours, OTAused existing estimates of labor costs and dividedby the 1979 average cost per work-hour for con-struction labor. The results were then comparedto existing estimates of work-hour requirementsfor central station powerplants (see table 66).

As with the cost estimates in tables 63 and 65,the construction labor requirements in table 66vary widely due to the wide range in the under-lying assumptions. For example, for the 50,000MW scenario, cogeneration is shown as requir-ing from 40 percent fewer to as much as 70 per-cent more work-hours than central station plants,depending on the size, type, and location of the

central station capacity, and the size and type ofcogenerators. Similar wide ranges are shown forthe 100,000 and 150,000 MW scenarios. In gen-eral, construction labor needs for cogenerationare higher than those for an eqivalent amountof central station capacity when small-to medium-sized cogeneration units are installed, and lowerwhen large cogenerators are used.

Although it is not possible to project actual con-struction labor needs without additional informa-tion on the size and type of cogeneration capacityto be used, it is possible to qualitatively comparethe types of jobs that might result. Powerplantconstruction labor may be broken down into ap-proximately 15 different craft requirements (seetable 67). Not all of the skills listed in table 67would be needed for cogeneration installation,nor would the proportion of each craft be similar(although actual craft needs for installing cogen-eration have not been published).

The location and duration of labor needs alsowill be quite different for cogeneration and cen-tral powerplants. Central station capacity con-struction is likely to occur in larger capacity in-crements at relatively isolated rural sites, and to

Table 66.–Comparison of Construction Labor Requirements (WH x 106)

Without cogeneration With cogeneration Percent dlfferencea

Percent Percentdifference difference

Technology Case A Case B A-B Technology case c Case D C-D A-C A-D B-C B-D

50,000 MW:Baseload. . . . . . . . 389.8-452.0Peakload. . . . . . . . 0.88-1.24

Lowest total. . . 370.88Highest total . . 453.24Mean . . . . . . . . . 411.98

100,000 MW:Baseload. . . . . . . . 754.45-922.1Peakload. . . . . . . . 17.59-24.63

Lowest total . . 772.04Highest total . 946.73Mean . . . . . . . . 859.39

150,000 MW:Baseload, . . . . . . 1)005 .6-1,229.0Peakload. . . . . . . . 88.3-92.8

Lowest total. . 1,071.9Highest total 1,321.8Mean . . . . . . . . . 1,196.9

497.6-646.00.88-1.24

498.48

847.24572.88

1,015 .2-1,318.017.59-24.63

1,032.791,342.631,187.7

1,353 .2-1,758.566.3-92.81,419.51,849.31,634.4

29.435.332.7

28.934.632.1

27.933.330.9

50,000 MWDiesels . . . . . . . . . . . . 72.92-186.67Gee turbines . . . . . . . 46.15-129.81Steam turbines . . . . . 132.21484.62Combined cycle , . . . 82.69-153.85

Lowest total . . . . . 333.97Highest total . . . . . 834.96Mean. . . . . . . . . . . . 584.48

100,000 MW:Dlesels . . . . . . . . . . . . 145.84-333 .34Gas turbines . . . . . . . 92.30259.82Steam turbines . . . . . 264.42-789.24Combined cycle . . . . 185.38-307.70

Lowest total . . . . . 887.94Highest total . . . . . 1,689.90Mean . . . . . . . . . . . . 1,188.9

150,000 MW:Diesels . . . . . . . . . . . . 218.76-500.01Gas turbines . . . . . . . 138.45389.43Steam turbines . . . . . 396.63-1,153.86Combined cycle . . . . 248.07-481 .55

Lowest total . . . . . 1,001.9Highest total . . . . . 2,504.9Mean . . . . . . . . . . . . 1,753.4

14.58.33.3327.69-77.89

185.05-537.96148.85-276.95

378.17926.13661.15

29.18-86.6755.38-155.78370.1-1,075.92297.7-553.9

752.341,852,31,302.3

43.74-100.0083.07-233.67

555.15-1,613.88446.55-830.85

1,128.52,778.41,953.5

11.910.410.8

11.910.410.8

11,910.410.8

10.4 1.5 39.5 28.0– 5 9 . 3 – 6 8 , 6 – 2 5 . 3 – 3 5 . 5- 3 4 . 6 – 4 5 . 0 –2.0 –12.8

14.5 2.6 42.9 31.4– 5 5 . 3 – 6 4 . 7 – 2 1 . 7 – 3 1 . 9–30.5 –41.0 1.6 –9.2

6.8 –5.1 34.5 22.8- 6 1 . 8 – 7 1 . 1 - 3 0 . 1 - 4 0 . 2- 3 7 . 7 – 4 8 . 0 – 7 . 0 – 1 7 . 8

a A negative percent difference means that cogeneration labor requirements are higher, and a posltlve percent difference Indicates that central station Iabor requirementsare higher.


. —


Table 67.—Craft Requirements for Central StationPowerplant Construction

Table 68.—Estimated Operating andMaintenance Labor

Percent of total construction labor Capacity type Size (MW) WH/MWhCraft Nuclear Fossil

Asbestos workers/insulation. . 1.6 3.5Boilermakers . . . . . . . . . . . . . . . 3.3 15.0Bricklayers/stone masons . . . . 0.4 0.5Carpenters . . . . . . . . . . . . . . . . . 11.1 8.5Cement/concrete finishers . . . 1.4 1.1Electricians . . . . . . . . . . . . . . . . 16.3 14.3Ironworkers . . . . . . . . . . . . . . . . 7.7 9.0Laborers . . . . . . . . . . . . . . . . . . . 15.0 11.8Millwrights . . . . . . . . . . . . . . . . . 2.4 2.9Operating engineers. . . . . . . . . 6.2 7.6Painters . . . . . . . . . . . . . . . . . . . 2.5 1.5Pipefitters . . . . . . . . . . . . . . . . . 26.5 18.6Sheet metalworkers . . . . . . . . . 1.5 2.0Truck drivers . . . . . . . . . . . . . . . 3.2Other workers . . . . . . . . . . . . . . 0.5 0.4SOURCE: U.S. Department of Energy, Off Ice of Energy Research; and U.S. Depart-

ment of Labor, Employment Standards Administration, Projections ofCost Duratlon, and On-Site Manual Labor Requirements for Construct-ing Electric Generating Plants, 197~19&3 DOE/lFf-O 057 andDOUCLDS/PP2, September 1979.

entail large influxes of workers (either temporaryresidents or commuters) for several years. Thesocial and economic disruption that can resultfrom powerplant construction is well docu -mented in the literature. Cogenerators, on theother hand, are more likely to be installed at com-mercial or industrial sites, usually located nearpopulation centers. Moreover, because cogen-eration would be installed in smaller capacity in-crements, fewer workers would be required foreach installation. Although the installation jobswould be of much shorter duration, they wouldoccur more frequently, providing a steadier re-gional employment profile. Thus, the potentialfor adverse socioeconomic impacts would bemuch lower with cogeneration.

Estimated requirements for O&M labor arecompared in table 68. These were not translatedinto the three scenarios due to the large numberof uncertainties and gaps in the data. However,it is clear from table 68 that the labor re-quirements for cogeneration per megawatthourof output will be greater than those for centralstation capacity. How much greater will dependon the size, type, and operating characteristicsof the cogenerator. The crafts involved (engineer-ing, fuel handling, general labor) are likely to besimilar for cogeneration and coal-fired power-plants, but, as with construction labor, the loca-tion of the jobs will be very different.

Central station. a

Nuclear . . . . . . . . . . . . . . . . . 1,000-2,000Coal . . . . . . . . . . . . . . . . . . . . 1,000-2,000Diesel

C

b

o g e n e r a t i o n :

. . . . . . . . . . . . . . . . . . 0.240.71.1352.84

Gas turbineb . . . . . . . . . . . . . 0.510.050.0

Steam turbinec . . . . . . . . . . . 15-3045-70

140-190

0.0389-0.07610.0462-0.0793

27.8-55.69.5-19.05.9-11.72.1-4.7

12.6-26.70.63-1.30.13-0.27

1.114-1.9680.378-0.4640.136-0.159


The above comparisons of capital and O&Mcosts and labor requirements for equivalentamounts of central station and cogenerationcapacity indicate that cogeneration has the poten-tial to reduce the cost of supplying electric powerwhile increasing the number of jobs associatedwith electricity generation. * However, dependingon the size and type of cogenerators deployed,it could have the opposite effect-higher capitalcosts and/or lower labor requirements. That is,the financial and employment effects of cogen-eration are highly correlated with economies ofscale. Based on the mean values, however, it ismore likely that cogeneration costs will be lowerand labor needs higher than those for central sta-tion powerplants.

Utility Planning and Regulation

Where utilities face financial, fuel availability,or other constraints on capacity additions, orwhere they are heavily dependent on oil-firedcapacity that cannot be converted to coal, co-

*Note that this seemingly anomalous result is possible only if co-generation installation and operation/maintenance require lessskilled (and thus lower paid) labor than central station plants, whichis likely to be the case.

Ch, 6—impacts of Cogeneration 255

generation can benefit utility finance, planning,and operations. If utilities own cogenerationcapacity, the potentially lower capital costs—together with the lower cost of capital that resultsfrom short construction Ieadtimes and smallercapacity increments—will mean lower shortruncosts to be passed on to their customers. Otherfinancial characteristics also would be likely toimprove, including utilities’ ability to finance proj-ects internally and the amount of Allowance forFunds Used During Construction (AFUDC) (orConstruction Work In Progress–CWIP) and de-ferred taxes they carry on their books. All of thesefactors would tend to slow the rate of growth inretail electricity rates as well as make utilitiesmore attractive to investors.

The short construction Ieadtimes and small unitsize of cogenerators also can have important ben-efits for utility planning and operations. If the de-mand for electricity increases more rapidly thanutility planners project, smaller plants can bebrought on-line more quickly (i.e., a 2- to 3-yearIeadtime for cogenerators compared to an 8-to10-year leadtime for baseload coal plants and 10to 12 years for nuclear plants). Similarly, if de-mand grows more slowly than expected, smallercapacity increments can be deferred more easi-ly and inexpensively than large powerplants forwhich planning and construction must beginyears before the power is projected to be needed.In addition, small unit sizes will have loweroutage costs (less unserved energy) than largerunits, assuming that both sizes present approx-imately the same degree of reliability.

The potential for all of these benefits would beenhanced if utilities were allowed to own a 100percent interest in cogeneration capacity and stillreceive unregulated avoided cost rates underPURPA. That is, their qualifying cogenerationcapacity would be unregulated and the cogen-erated power could be valued at the avoided costrather than the average cost. Thus, the utilitycould earn a higher rate of return on it than ontheir regulated generating capacity. This higherreturn would compensate them more fully for theperceived risks of investment in “unconven-tional” technologies with relatively uncertainoperating characteristics, but probably would stillbe lower than the rate of return required by in-

dustrial or commercial owners. Similarly, thehigher return would increase the cost that wouldhave to be passed on to customers, but that costmight still be lower than under nonutility own-ership.

Utilities with long-term contracts for purchasesof cogenerated power could still use the smallercapacity increments to reduce the downside riskof sudden unexpected changes in demandgrowth. outage costs also would probably remainrelatively equal under either form of ownership,although utilities may consider cogenerators theyown to be more reliable due to perceived or ac-tual differences in dispatchability and other fac-tors affecting reliability. But these considerationsare tempered by the probability that cogenera-tion would supply more electricity to the gridunder utility ownership. Utilities typically requirea lower rate of return—even when unregulated—than private investors, and financially healthyutilities often have access to lower cost capital.Thus, cogeneration investments maybe econom-ic for utilities when they wouId not be for usersor third parties. Furthermore, except whereavoided costs are very high, utilities would bemore likely to invest in cogeneration systems witha high ratio of electricity-to-steam production (E/Sratio).

For nonutility ownership, the benefits from co-generation’s potentially lower power productioncosts would accrue to the cogenerator rather thanto the utility or its customers. Under the originalFERC rules implementing PURPA, the cogener-ator would be paid for power supplied to the gridbased on the utility’s avoided cost of alternativeenergy (or marginal cost), rather than on the aver-age energy cost (see ch. 3). This higher cost wouldbe passed on to the utility’s noncogenerating cus-tomers. Moreover, the utility would have ad-ministrative and other expenses related to capaci-ty that were not included in its rate base and onwhich it would not earn a rate of return.

Finally, utilities may be subject to planning andfinancial risks from the increased competitionposed by nonutility-owned cogenerators. Whencompetition takes away utility customers, thejoint or common costs get a reduced revenuecontribution. This reduction in fixed cost

256l Industrial and Commercial Cogeneration

coverage either endangers service to othercustomers or imposes a greater share of the costburden on them. This phenomenon is not uniqueto electric power. It has occurred in the transpor-tation industry, most dramatically with the com-petition between trucking and railroads, and thesame problems currently are being faced by thetelecommunications industry. It is essentially thesame as the issue of loss exposure raised by Con-Ed in the New York Public Service Commissionhearings on cogeneration (see ch. 3). Remediesfor such problems, insofar as they exist, must befound in the rate structure of the utility, orthrough changes in Federal policy that wouldequalize utilities’ competitive position in cogen-eration markets.

The following material analyzes the potentialeffects of competition on two utilities: Com-monwealth Edison (CWE), which is committedto major central station capacity construction,and Pacific Gas & Electric (PG&E), which is con-strained from adding large amounts of new cen-tral station capacity and has been ordered by theCalifornia Public Utilities Commission to ag-gressively seek cogeneration capacity. Back-ground information on the implementation ofPURPA in these utilities’ service areas may befound in chapter 3.

Current cost conditions in the electric powerindustry can give rise to reduced fixed costcoverage. These are illustrated for CWE in figure61, which shows the average fixed cost portionof CWE revenue requirements, based on theircurrent construction plans, for growth rates of 4,2, and O percent (CWE projects 4 percent loadgrowth). Any load growth lower than 4 percent–whether it is due to competition from onsite gen-eration or from conservation-will result in salesbelow CWE expectations and thus a rising burdenof fixed costs for remaining customers. As shownin figure 61, the larger the shortfall in sales, thefaster the fixed cost burden rises.

Turning to the California context, it is morereadily apparent that PURPA payments to cogen-erators can lead directly to reduced fixed costcoverage. PURPA payments for capacity are fixedcosts from the ratepayers’ point of view, even iftheir basis in value comes from fuel savings.

Figure 61 .—CWE Fixed Cost Structure as aFunction of Sales Growth

60

45

15

1980 1985 1988 88(A)

Year

SOURCE: Edward Kahn and Mlchael Merritt, Dispersed Electricity Generation:Planning and Regulation (contractor report to OTA, February 1981).

When a utility contracts to purchase energy froma private party, on an avoided cost basis, thePURPA payments should drop with decreasingdemand. However, this may not be the case, orat least not to any significant degree. To dem-onstrate this proposition, the cost structure ofPG&E is illustrated in table 69.

The differences between the base case and thePURPA case in table 69 are due to two factors.First, there is more than twice as much cogenera-tion in the PURPA case compared to the basecase (940 MW v. 2,000 MW). The larger amountof cogeneration represents a fulfillment of thegoal set for PG&E by the California public UtilitiesCommission. The second difference is that the

Table 69.—Pacific Gas & Electric Cost StructureAdjusted for PURPA, 1990

Base case PURPA caseFixed costs ... ... ... ... ... .$5.31 x 109

$8.58 x 109

Fuel . . . . . . . . . . . . . . . . . . . . . .. $5.22 x 109

$3.87 X 109

Sales to noncogenerators . . . . 87.4 X 10 kWh 80.8 X 109 kWhFixed cost/kWh to

noncogenerators . . . . . . . . . . 80.8 mills 81.4 millsSOURCE: Edward Kahn, and Michael Merritt, Dispersed Electricity Generation:

Plannlng and Regulation (contractor reporl to the Office of TechnologyAssessment, 1981).


base case assumes utility ownership while thePURPA case assumes private ownership.

Table 69 shows the same qualitative phenom-enon as figure 61—a rising burden of fixed orcommon costs to be borne by the nongeneratingcustomers remaining on the utility system. In thePG&E case, the shift is clearly due to the effectsof cogeneration. Moreover, a significant part ofthe increase in fixed cost comes from PURPA in-centives under the simultaneous purchase andsale provision—estimated at roughly $445 million,assuming that cogenerators will pay rates for theirown use that are roughly 70 percent of the aver-age price (18). The estimate may, of course, betoo high. If it is high, the net fixed costs wouldbe less and the risk less extreme. However, thesimultaneous purchase and sale incentive is onlyabout one-third of the fixed cost differential (445/1,270) in the two cases. Therefore, even a changein the rate structure to reduce that incentivewould not by itself eliminate the problem. Cus-tomers remaining on the utility system wouldhave fewer incentives to conserve electricity atthis point because reduced sales would only in-crease the fixed cost burden (29).

Thus, the increasing burden of fixed costs canresult from either excess capacity (CWE) or com-petition (PG&E). Of the two distinct routes to thehigh fixed cost situation, it is likely that the com-petition risk may be smaller than the excess ca-pacity risk. The reason for this is the potentialescalation in fuel costs. The calculations in table69 show fuel costs ranging from about 50 per-cent of total cost in the base case to about 37 per-cent of total cost in the PURPA case. The fuel costfraction would rise if fuel cost escalated fasterthan assumed (roughly 10 percent nominal an-nual rate). Although no one can predict futureoil prices (the dominant fuel in California), thetendency in the past has been to underpredictprice increases (29).

On the other hand, the excess capacity risk re-sults in part from the “lumpiness” of investmentin baseload facilities. New central station plantscome in large unit sizes and require long con-struction and licensing times. Further, accuratedemand forecasting is difficult, and the tenden-cy in the past has been to overestimate the future

size of the electricity market. However, demandgrowth is more sensitive to price increases thanpre-1 973 behavior seemed to indicate and largebaseload projects are difficult to adjust to reducedgrowth. Powerplant construction can be deferred(which means extra carrying cost) or canceled(which means losses). Thus, once large projectsare initiated there is a tendency to continue themregardless of changing circumstances.

Therefore, where construction commitmentsare large (as in the CWE case), the balance ofeconomic and institutional forces points towarda greater risk from excess capacity than fromcompetition. At the present time, however, therisks from cogeneration competition are morepotential than real due to its low market penetra-tion. One way utilities can deal with possiblefuture competitive threats is by trying to capturethe new markets with their own investment.

Other Economic and Social Impacts

OTA’s analysis focused on the economic andsocial impacts of cogeneration on electric utilitiesand their customers. However, cogeneration mayalso have important socioeconomic implicationsin other sectors, such as business developmentpatterns for fuel and technology suppliers andcapital markets, and the role of policy/politics inenergy supply. A detailed assessment of theseissues is beyond the scope of this report, butsome generaI considerations are outlined belowas a framework for future analysis.

PURPA’S partial deregulation of entry into theelectricity generation market has received a lotof attention for the opportunities it presents fornew and small businesses, and for the changesit may bring to existing economic sectors. For ex-ample, the primary sources of fuel for cogener-ators in the near term are not expected to be dif-ferent from the fuel sources for electric utilities(oil, gas, and coal). However, as advanced co-generation technologies with greater fuel flexibili-ty emerge, new opportunities should arise forsuppliers of alternate fuels such as municipal solidwaste (MSW), biomass, and synthetic liquids andgases. In some cases, these markets will be cap-tured by existing large energy companies seek-


Photo credit: Environmental ProtectIon Agency

Advanced cogeneration technologies with greater fuel flexibility may be able to burn municipal solid waste, contributing tothe solution of waste disposal problems and providing a new source of revenue for disposal collection agencies

i n g d i v e r s i f i c a t i o n o p p o r t u n i t i e s . B u t o t h e rmarkets may be served by local governments orprivate entrepreneurs (e.g., MSW), or suppliedonsite (biomass), or captured by utilities orcogenerators themselves. For instance, one prom-ising scheme for alternate-fueled cogenerationuses a centrally located gasifier that converts coal,biomass, petroleum coke (from refineries), orother nonpremium fuels to a low- or medium-Btu gas for distribution to cogenerators within alimited radius. The gasifier could be owned jointlyby the cogenerators (e.g., in an industrial park)or by the local utility as a means of diversifyingits energy supply business. A central gasifica-tion/remote cogeneration scheme proposed byArkansas Power & Light is described in detail inchapter 5. Such a scheme would enable cogen-erators who cannot use nonpremium fuels (e.g.,due to environmental, economic, or site limita-

tions) to centralize the costs of fuel conversionand distribution. Thus, economic and policy con-siderations that discourage the use of oil and gasin cogeneration also may help to create newbusiness opportunities for a wide range of fuelsuppliers. In many cases these opportunities willgo to local distribution companies, as opposedto the large producers or distributors that sup-ply central station powerplants.

Markets for technologies also could change asa result of the widespread use of cogeneration.Electric utilities or their construction contractorsgenerally interact directly with the major manu-facturers of powerplant equipment. Cogenera-tors, on the other hand, will be more likely topurchase a total system from vendors acting asmiddlemen between manufacturers and purchas-ers. Such vendors will be able to offer a wider

Ch. 6–impacts of Cogeneration .259

range of “package” systems than a single man-ufacturer, and to tailor the package more close-ly to a user’s specific needs. Moreover, whereasutilities generally perform their own maintenance,cogeneration vendors may evolve as total servicecompanies that offer repair and maintenance aspart of the sales contract. The potential role forsuch service companies in spreading the burdenof maintenance costs and labor requirementscontributes to the uncertainty (discussed earlierin this chapter) in assessing these factors. Alter-natively, if utilities own cogenerators, they maytend to continue to deal with the major manufac-turers with which they are familiar, and to pro-vide their own maintenance.

Similar changes might appear in capital marketswith widespread investment in cogeneration. Thesmall unit size of cogenerators will mean smallerbut more frequent investments in generating ca-pacity increments. If utilities are investing, thentheir capitalization is likely to shift away fromlong-term debt and equity to short-term debtorretained earnings. Alternatively, utilities mayestablish innovative low-interest loan programsfor cogenerators. Third-party investors may playa major role due to the tax incentives introducedby the Economic Recovery Tax Act of 1981. Orpotential cogenerators may shift their investmentpriorities from process equipment to cogenera-tion. As a result of all these types of owners, newcapital markets for energy projects will be in-troduced. Traditional lending institutions such asbanks could become financiers for energy proj-ects. Investment firms will have a new option forsheltering their clients’ income. A wide range oftraditional financiers may establish leasing sub-sidiaries.

The potential impacts on fuel, technology, andcapital markets outlined above will themselveshave far-reaching effects. For example, concernis frequently expressed about the anticompetitiveaspects of utility investment in cogeneration. Itis argued that utilities may favor their own sub-sidiaries in contracting for cogenerated power,or favor one or two manufacturers or vendors ofcogeneration systems, and thus foreclose smallbusiness opportunities and/or stifle the develop-ment of innovative technologies. Similarly, utili-ty loan programs have raised questions about

competition in the banking industry, wheremarket entry traditionally has been regulated.Although these concerns may be real, closingthese markets to utilities could also stifle thedevelopment of cogeneration capacity, and itmay be more sensible to resolve any questionsabout the competitive effects of utility investmentthrough carefully drafted legislation and regula-tions, and through established legal and admin-istrative remedies.

The introduction of new fuel supply configura-tions could have significant impacts on other fuelusers as well as on land use patterns and otherenvironmental factors. If oil- or gas-fired cogen-eration achieved a significant market penetration,changes could occur in the way these fuels areallocated among noncogenerating residential,commercial, and industrial customers. Cen-tralized fuel conversion systems such as gasifierswould require new dedicated distribution sys-tems, and would strongly influence the locationof new cogenerating industries. Where fuel con-version is not centralized, fuel delivery andstorage may pose substantial problems, especially

in urban areas. If the cogeneration site is not ableto accommodate large fuel storage facilities (e.g.,30 days’ supply), then frequent deliveries couldinvolve noise and/or air pollution as well as traf-fic congestion. As with the concerns about theanticompetitive aspects of utility ownership ofcogenerators, these potential land use problemsare probably best solved through careful designand siting of cogenerators and rational local plan-ning, rather than through general disincentivesto cogeneration.

Centralization and Decentralization ofElectricity Generation

In the two decades following World War II, theelectric power industry operated under a declin-ing production cost curve even during periodsof general increases in the cost of fuels and theoverall consumer price index. The primary con-tributor to these declining costs was the captureof significant economies of scale that allowedlarger powerplants to use fuel more efficiently(see ch. 3). At the same time, obvious cost sav-


ings became associated with the location of multi-ple units on single sites, and planning responsibil-ities, decisionmaking authority, and capital assetsbecame concentrated in a rapidly diminishingnumber of institutions—primarily investor-ownedutilities (32). The resulting combination of largepowerplants concentrated at a central locationand under the authority of a limited number oflarge organizations has become known as thecentralization of the utility industry.

When engineering economies of scale were nolonger able to offset other costs for larger power-plants, and the electric power industry’s declin-ing cost curve disappeared in the late 1960’s, thevalue of such centralization became increasinglydebated. Questions have been raised about therole of centralization in the adverse environmen-tal impacts of large powerplants, in utilities’ finan-cial deterioration, and in more qualitative con-cerns such as individual’s feelings that they havelost some control over important aspects of theirlives and livelihoods. As a result, it is frequentlysuggested that the electric power industry shouldbe restructured in favor of a decentralized systembased on small-scale technologies located at ornear the point of use and subject to local or indi-vidual control. This position is advocated by awide range of groups with varying goals, but thecentral features of the argument generally areconsidered to be embodied in the writings ofAmory Lovins and colleagues on the “soft energypath” (31).

This section reviews the context of the debateover centralized and decentralized electric ener-gy systems, then analyzes the role that cogenera-tion might play within that debate. *

Technology and Values

One of the critical features of the current ener-gy policy debate is the lack of consensus on boththe facts and the values surrounding energy pol-icy. Thus, there are radically different perceptionsabout the actual nature of the “energy problem”as well as disagreements about the role energyplays in structuring social organization. One ofthe most pervasive of these disputes is over the

*Much of the following discussion is from Hoberg (26).

centralization or decentralization of electricpower production.

The point of view that argues for “decentraliza-tion” is embodied in a number of separate move-ments (e.g., appropriate technology, environ-mentalist, antinuclear), each of which has its owncriteria for evaluating energy technologies. Butthey all tend to converge with regard to proposalsfor small-scale renewable energy technologies,as embodied in the “soft-path” future firstdescribed by Lovins.

The three primary components of Lovins’ softenergy path are:

●

●

●

prompt commitment to maximizing end-useefficiency;rapid development and deployment of small-scale renewable-fueled technologies whoseenergy quality closely matches the requiredservice; andspecial transitional fossil fuel technologies.

The first component would minimize the energyinput into a given end-use function. The secondwould accelerate reliance on renewable fuels andon energy technologies that contribute to self-reliance, and the third would “tide us over” un-til the system adjustments anticipated by the firsttwo can be made. Because of Lovins’ overridingconcern with thermodynamic efficiency, cogen-eration—primarily industrial cogeneration usingcoal-fired fluidized bed combustion systems—isviewed as a major contributor to the transitionalfossil fuel technologies.

Lovins’ writings have played a major role inwinning a place for alternative technologies inthe energy policy debate. However, as in otherenergy policy areas, the facts and values sur-rounding soft energy paths are subject to debate.With respect to the facts, the uncertainties in cap-ital and operating costs and in output characteris-tics are especially important. In regard to thevalues, there is disagreement not only betweensoft and hard path advocates, but also betweendifferent segments of the alternative energy move-ment.

For example, Lovins only applies soft energytechnologies at the margin; he does not advocatethe early replacement of existing central station

—

Ch. 6—impacts of Cogeneration 261

powerplants and their accompanying transmis-sion and distribution networks. Other “appropri-ate” technology advocates focus on stand-aloneapplications that are totally incompatible with theexisting electricity supply system (e.g., windmillsor photovoltaics coupled with battery storage).Moreover, there is no real consensus among softpath advocates as to which values should pre-dominate in such technological decisions. Someplace a great deal of emphasis on fostering decen-tralization in order to gain control over the tech-nologies that affect their lives, while others em-phasize economic efficiency.

The debate about the role of cogeneration inenergy policy typifies these fact and value dis-putes in several ways. It can be a small-scale tech-nology located at the point of use, or larger sys-tems can be centrally located and the energyproducts distributed among several co-owners orcustomers. Cogenerators can use coal or otheralternate fuels as their primary energy source, butthe most economic systems for some applicationswill rely on oil or gas in the near term (e.g., gasturbines, diesels). Cogeneration can present sig-nificant energy savings when compared to cen-tral station generation and separate thermal pow-er production, but it also will be competingagainst conservation, coal, and renewable fuelson many electric systems, and its electric poweroutput is less certain. Thus, whether cogenera-tion will be a favored technology to advocatesof decentralized energy systems will dependheavily on the technology and the mode of de-ployment chosen.

Centralization and Decentralization

The concepts of centralization and decentrali-zation are critical to an assessment of the socialand institutional impacts of dispersed electricitygeneration, but are all too often left undefined.In this discussion, these terms will be used todescribe a measure of the distribution of control,authority, or autonomy throughout a system (inthis case the energy and social systems), where“control” refers to the ability to affect thebehavior of others or of the system itself. A situa-tion in which a single component controls allothers and the system itself (e.g., a monopoly ormonopsony) defines the centralized extreme,

while at the decentralized extreme each individ-ual is autonomous and therefore cannot changethe system or its components (e.g., perfect com-petition). This concept of centralization is similarto that in organization and administration theory,where the concern is locating the decision mak-ing authority within an organization or institution.The concepts of centralization and decentraliza-tion of control are particularly important to thestructure of organizations because mismatchesbetween that structure and the task it is designedto accomplish can result in inefficiencies (7).

The centralization or decentralization of con-trol should be distinguished from other conceptsthat focus on size or geographical concentration.While these factors may influence the degree ofcentralization, they do not define it. Similarly, itis useful to distinguish technical from social cen-tralization. Thus, technical systems can be de-fined in terms of their dependence on one or afew components (e.g., central dispatch of an in-terconnected electric utility system) without nec-essarily implying an equal degree of authorityover a related social system.

Centralization/Decentralizationand Cogeneration

How cogeneration fits into this definition ofcentralization and decentralization will dependon its deployment and operating characteristics.Thus, the lower minimum efficient scale of cogen-eration relative to conventional powerplants cancontribute to decentralization because the small-er size and lower costs make the technology ac-cessible to more people. On the other hand, co-generators are more complex than traditional on-site thermal energy systems (e.g., boilers, fur-naces), and they are likely to require new tech-nical and managerial skills in industrial and com-mercial enterprises that own and operate them,or in utility companies that deploy them in theirservice areas. Whether a firm decides to train oracquire its own expertise or to rely on a vendor,utility, or other service company may determinethat firm’s perceptions of autonomy.

Similarly, the resource/demand characteristicsof cogeneration, including the type of primaryenergy source and its concentration or density,

.— —


the type of technology and its concentration, andthe actual number of components in the re-source, conversion, and demand categories willinfluence the degree of centralization. In general,decentralization might occur if the energy re-quired within a given area is approximately equalto the energy available in that area. If energy mustbe imported, the system will be more vulnerableto external control and thus relatively centralized.Similarly, where the energy can be exported ordistributed over a larger area, a relatively central-ized dependence of dispersed users on a concen-trated resource may result.

Finally, the amount of political or social impor-tance associated with cogeneration will be asignificant factor in determining centralizationand decentralization of control. For example,PURPA encourages grid-connected cogeneration,offering economic incentives for operating char-acteristics (such as central dispatch) that increaseutilities’ control over the deployment and use ofthe technology.

Because all these characteristics will vary wide-ly, it is clear that cogeneration cannot automatic-ally be considered a decentralized technologythat will lead to a decentralized social structure.Similarly, central station powerplants will not al-ways lead to centralized social organization, al-though this has been the predominant trend inthe electric power industry. Rather, it is possibleto envision centralized technologies that contrib-ute to a decentralized social or political system,as well as decentralized technologies leading tocentralization of control. For example, FranklinRoosevelt saw centralized generation of electrici-ty with transmission to outlying areas as the keyto a decentralized society:

Sheer inertia has caused us to neglect formulat-ing a public policy that would promote the op-portunity to take advantage of the flexibility ofelectricity; that would send it out wherever andwhenever wanted at the lowest possible cost. Weare continuing the forms of overcentralization ofindustry caused by the characteristics of thesteam engine, long after we have had technicallyavailable a form of energy which should promotedecentralization of industry (34).

The central theme underlying the possibility ofsuch a centralized energy system supplying a

decentralized society is the proposition that themost effective means of preserving diversity, flex-ibility, and freedom of choice in social structureis to ensure abundant supplies of energy at thelowest possible cost (termed the “cornucopiastrategy”). The less scarce the fundamental en-ergy input, the less influence energy would haveon the structure of social organization. Cogenera-tion (and other alternative technologies) wouldbe included in the cornucopia strategy to the ex-tent that they pose economic advantages overconventional technologies. Moreover, a recentanalysis suggests that cogeneration combinedwith the centralized electricity grid will contributeto decentralization in the economy(1). This anal-ysis argues that the lack of significant scale effectsassociated with connection to a centralized gridwill mean that large firms will not have competi-tive advantages over small firms in energy access(ignoring declining block rates or relative processefficiencies). Thus, diversity and decentralizationof organizational structure in industry and busi-ness might be promoted.

The idea of centralized energy systems leadingto decentralized social organization looks moreto fragmentation of power among interest groupsand various levels of government wherein free-dom and flexibility in lifestyles are fostered andpreserved, while the appropriate technologymovement embodies a notion of decentralizationthat consists of a loosely coupled system of nearlyautonomous and self-reliant communities. Assuch, the former view can accommodate a greatdeal of specialization and differentiation in soci-etal function, at aggregate levels, that the latterfundamentally opposes.

On the other hand, it is also possible to envi-sion a decentralized energy system in a central-ized political economy. This might come aboutin two ways. One analysis considers the casewhere some combination of a deterioration in theeconomics of utility generated electricity and anenhanced competitive position of cogenerationsystems brings about an industrywide movementtowards cogeneration as the source of electricpower and process heat/steam. Because there areeconomies of scale (in capital equipment, O&M,pollution control, etc.) inherent in cogenerationdevices, the larger firms in a certain industry


group will be able to produce energy morecheaply than the smaller firms, which would givethe larger firms a competitive advantage, contrib-uting to the elimination or absorption of smallerfirms by the larger firms. The end result is cen-tralization in industry (as measured by industrialconcentration) (26).

A second view of this configuration-decentral-ized energy systems in the context of centralizedcontrol—also could result from policy considera-tions. In fact, some commentators have suggestedthat this is the most likely result:

The most plausible vision of a renewable-en-ergy future is one that offers less freedom andless true diversity, more centralization of deci-sion, and more state (i.e., government) interfer-ence and corporate domination in our lives, thanis the case in the present society in the UnitedStates . . . (37).

Clearly, this combination of decentralized energyand centralized social organization dependsmore on policy orientations than on any of theother factors that influence the degree of central-ization/decentralization. Lovins terms this alter-native a coercive one in that it is most likely toresult from policies that mandate—rather than use

CHAPTER 61. Asbury, Joseph G., and Webb, Steven B., Central-

izing or Decentralizing: The Impact of Decentral-ized Electric Generation (Argonne, Ill.: ArgonneNational Laboratory, ANL/SPG-16, 1979).

2. Bell, Douglas, Standards Development Branch,U.S. Environmental Protection Agency, privatecommunication to OTA.

3. Bhargava, Vijay, California Air Resources Board,private communication to OTA, September 1981.

4. Bioenergy Bulletin, vol. 11, No. 3, published byU.S. DOE, Region X, Mar. 15, 1981.

5. Breitstein, L. and Gant, R. E., M/US Systems Anal-ysis–Effects of Unfavorable Meteorological Condi-tions and Buildings Configuration on Air Quality(Oak Ridge, Term.: Oak Ridge National Labora-tory, ORNL/HUD/MIUS-29, February 1976).

6. Brooklyn Union Gas/FIAT, TOTEM Technical De-scription, October 1978.

7. California Air Resources Board, Proposed Strategyfor the Control of Nitrogen Oxide Emissions from

market incentives for—a decentralized energysystem (or the proverbial distinction between thecarrot and the stick). Alternatively, such central-ization could result from demands for control ofthe impacts of decentralized technologies in thatit is easier to impose and enforce controls in acentralized manner (e.g., uniform Federal stand-ards for system design at the point of manufac-ture) than it is to monitor and enforce such con-trols at myriad points of use. At the extreme,authoritative solutions may be seen as necessaryto meet an industrial society’s need for adequateand reliable supplies of energy, or to allocatelosses in the event of an energy supply shortfall(37).

As has been seen above, cogeneration (andother dispersed generating systems) cannot nec-essarily be considered either a decentralized ora centralized energy system nor will they neces-sarily lead to either centralization or decentraliza-tion of social organization. Rather the degree ofcentralization/decentralization will depend onsite specific, market, and policy factors such asthe mode of operation, form of ownership, result-ing profit and competitive aspects, and relativepolicy emphasis on their deployment.

REFERENCESStationary Internal Combustion Engines (State ofCalifornia, October, 1979).

8. Casten, Thomas, Cogeneration DevelopmentCorp., private communication to OTA.

9. Chandler, Alfred D., Jr., Strategy and Structure:Chapters in the History of American Industrial En-terprise (Cambridge, Mass.: The MIT Press, 1962).

10. “Cogeneration Proponents Will Seek An Air ActChange Recognizing Greater Efficiencies,” InsideEPA, Apr. 3, 1981.

1 I, Consolidated Edison Co. of New York, written tes-timony before the New York State Department ofPublic Service, “Environmental Assessment of Co-generation in New York City,” Mar. 17, 1980, p.13.

12. Dadiani, John, Cogeneration—Status and Environ-mental Issues (contract 68-03-2560, draft report toEPA, 1980),

13. Davis, W. T., and Kolb, J. O., Environment/ As-sessment of Air Quality, Noise and Cooling Tower


140

15.

16.

17.

18,

19,

20.

21.

22.

23.

24.

25.

26,

27,

28.

29.

Drift From the Jersey City Total Energy Demonstra-tion (Oak Ridge, Term.: Oak Ridge National Lab-oratory, ORNUHUD/MlUS-52, June 1980).Domaracki, Alan J., and Sistla, Gopal, testimonybefore the State Department of Public Service be-fore the Commission, case No. 27574, July 1980.Dryer, Frederick, Princeton University, privatecommunication to OTA, October 1981.Dukakis, Michael S., Governor’s Commission onCogeneration, Cogeneration: Its Benefits to NewEng/and (Governor of Massachusetts, October1978).Energy and Resource Consultants, Inc., Federaland State Environmental Permitting and SafetyRegulations for Dispersed Electric GenerationTechnologies, contractor report to OTA, 1980.Environmental Defense Fund, An Alternative tothe Warner Va//ey Energy System (Berkeley, Calif.:EDF, Jlliy 1980).Environmental Research and Technology, Inc., AirQuality Impact of Diesel Cogeneration in NewYork City, Document P-A 302, November 1979.Ferris, B. G. Jr., “Health Effects of Exposure to LowLevels of Regulated Air Pollutants. A Critical Re-view,” 28J. Air Pollution Control Association 482,1978.Freudenthal, P. C., additional rebuttal testimony,New York Public Service Commission case No.27574, N O V. 13, 1980.Freudenthal, P., Consolidated Edison, privatecommunication to OTA.“General Discussion: Health Effects of Exposureto Low Levels of Regulated Air Pollutants,” J. AirPollution Control Association 28:891, 1978).Ghassemi, M. and Lyer, R., Environmental Aspectsof Synfue/ Utilization (EPA-600/7-81 -025, March1981).Griffin, H. E., et al., Health Eflects of Exposure toDiesel Exhaust (Washington, D. C.: National Acad-emy of Sciences, 1980).Hoberg, George, Electricity, Decentralization, andSociety: The Soci~Political Aspects of DispersedElectric Generating Technologies, contractor re-port to OTA, January 1981.ICF, Inc., A Technical and Economic Evaluationof Dispersed Electric Generation Technologies,contractor report to OTA, October 1980.Jarvis, P. M., “Methanol as Gas Turbine Fuel,”paper presented at the 1974 Engineering Founda-tion Conference, Methanol as an Alternate Fuel,Henneker, N. H., July 1974.Kahn, Edward, and Merritt, Michael, DispersedElectricity Generation: Planning and Regulation,contractor report to OTA, 1981.

30.

31.

32.

33.

34.

35.

36.

37.

38.

39.

40.

Komanoff, Charles, “Nuclear Costs Spiral AboveCoal,” Pub/ic Power, Sept. 10, 1981.Lovings, Amory, Sofi Energy Paths: TowardA Du-rab/e Peace (Cambridge, Mass.: Ballinger Press,1 977).Messing, Marc, Friesema, H. Paul, and Morrell,David, Centralized Power (Washington, D. C.: En-vironmental Policy Institute, 1979).Office of Technology Assessment, U.S. Congress,The Direct Use of CoaJ OTA-E-86 (Washington,D. C.: U.S. Government Printing Office, April1 979).President Franklin D. Roosevelt, speech before theWorld Power Conference, 1936, quoted in TheEnergy Controversy: Soii Path Questions and An-swens, Hugh Nash (cd.) (San Francisco: Friends ofthe Earth, 1979).Reese, R. E., and Nisenbaum, D., “Suggested Con-trol Measure for the Control of Nitrogen OxideEmissions From Stationary Internal CombustionEngines” (California Air Resources Board, May1980).Sheppard, D., et al., “Exercise Increases SulfurDioxide–induced Bronchoconstriction in Asth-matic Subjects,” Am. Rev. Resp. Dis., May 1981.Tugwell, Franklin, “Energy and Political Econ-omy,” Comparative Po/itics, October 1980.U.S. Environmental Protection Agency, Compila-tion of Air Pollutant Emission Factors (AP-42),1978.U.S. Environmental Protection Agency, StandardsSupport and Environmental Impact Statement forStationary Internal Combustion Engines (EPA-45012-78-125a, draft, July 1979).U.S. Environmental Protection Agency, StandardsSupport and Environmental Impact Statement forStationary Gas Turbines (EPA-450/2 -77-Ol 7a, Sep-tember 1977).

41. U.S. Department of Energy, Environmenta/Read-iness Document- Cogeneration (DOE/ERD-0003,1978).

42. U.S. General Accounting ~ce, /ndustria/ Cogen-eration— What It Is, How It Works, Its Potential(Washington, D.C.: U.S. Government Printing Of-fice, EMD-80-7, Apr. 29, 1980).

43. Wilson, R. P., et al, “Single-Cylinder Tests of Emis-sion Control Methods for Medium-Speed DieselEngines,” ASME paper 82-DGP-28, March 1982.

44.40 CFR 52.21, 52.24.45.40 CFR pt. 60, subpts. D,E.46.40 CFR pt. 60, subpt. GG.

Chapter 7

Policy Analysis

. ... .

Contents

Page

Cogeneration and Oil Savings. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 267

Economic incentives for Cogeneration . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 270

Utility ownership of Cogenerators. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 273

Interconnection Requirements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 275

Air Quality Impacts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 276

Research and Development . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 277

Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 278


Table

Table No.

70. Summary of Policy Considerations Related to Cogeneration . . .

Figure

Figure No.

Page. . . . . . . . . . . . . . . 279

Page

62. Cogeneration Development Under Low, Medium, and High Utility PurchaseRates: 1981-90 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 271

Chapter 7

Policy Analysis

A comprehensive Federal policy toward cogen-eration was established in 1978. In general, theelements of this policy, which are described indetail in chapter 3, offer economic and regulatoryincentives for cogeneration applications that willpromote the efficient use of energy, economic,and public utility resources. The major policy ini-tiatives include title II of the Public UtilityRegulatory Policies Act of 1978 (PURPA), thePowerplant and Industrial Fuel Use Act of 1978(FUA), and the Energy Tax Act of 1978 (asamended by the Windfall Profits Tax Act of 1980and the Economic Recovery Tax Act of 1981), aswell as provisions of the Clean Air Act, generalaspects of utility regulation, and Government sup-port for research and development (R&D) and fordemonstration projects.

Federal ratemaking, fuel use, R&D, and environ-mental policies are now shifting in focus; manyof the tax initiatives are too new for data on theireffects to be available; and court decisions arepending on the validity of the ratemaking and in-terconnection provisions of PURPA. Despitethese uncertainties, some aspects of Federal co-generation policy that may discourage the im-plementation of cogeneration projects, or thatmay result in adverse impacts from such projects,have been identified and are analyzed below.These include the use of oil by cogenerators, eco-nomic incentives for cogeneration, utility own-ership of cogeneration capacity, interconnectionrequirements for cogeneration systems, the ef-fects of cogeneration on air quality, and the focusof R&D.

It is difficult to predict what long-term effectsthese Federal policies will have on cogeneration.

COGENERATION AND OIL SAVINGSOne of the principal objectives of Federal pol-

icy toward cogeneration is to encourage the im-plementation of those projects that will reducenet oil consumption, particularly by electricutilities and industry. However, despite their in-herent energy efficiency, not all cogenerators willsave oil. Rather, cogeneration will result in netoil savings only if an alternate-fueled cogenerator(e.g., one that burns coal, biomass, wastes), dis-places either an electric generating plant or athermal energy system that uses oil, or if an oilburning cogenerator replaces separate electricand thermal energy systems that both use oil andwould continue to do so for most of the usefullife of the cogenerator. Thus, if an oil-fired co-generator is substituted for either an electric orthermal conversion technology that uses an alter-nate fuel, or that would have converted to an al-ternate fuel during the useful life of the cogener-ator, then cogeneration actually could increasenet oil consumption.

In general, Federal policies under PURPA, FUA,and the tax code are designed to discourage co-generation applications that would not offer netoil savings over the technology’s useful life. Therates for utility purchases of cogenerated electric-ity (and other incentives) under PURPA are onlyavailable to oil-fueled cogenerators if they meetthe efficiency and operating standards establishedby the Federal Energy Regulatory Commission(FERC) (see ch. 3). Moreover, the PURPA incen-tives are more economically advantageous tocogenerators in regions where utilities dependheavily on oil-fired generating capacity. In theseareas, the utilities’ purchase power rates are likelyto be based on the price of oil, and thus will behigher than the rates of utilities with primarilycoal, nuclear, or hydroelectric capacity. There-fore, oil-fired cogenerators that do achieve netoil savings usually will have higher purchasepower rates than those that do not. (Exceptionsinclude States where the utility regulatory com-

267


mission has set purchase power rates equal to theprice of oil while the purchasing utility actuallyuses a mix of fuels, or has established explicit sub-sidy rates for purchases of cogenerated power.)Similarly, oil burning cogenerators only can ob-tain an exemption from the FUA prohibitions onoil and natural gas use in powerplants and in-dustrial boilers if they can demonstrate net oil orgas savings. Finally, the energy tax credits general-ly are available only for energy property that usesfuels other than oil or gas.

When these policies were enacted, oil priceswere escalating rapidly. It was assumed that therising prices and uncertain availability of petro-leum fuels, when combined with Federal policy,would be sufficient to ensure that only those oil-fired cogenerators that could achieve net oil sav-ings would be worth the investment risk. How-ever, oil prices have leveled off recently, and,although most analysts project that prices will riseslowly through the end of the decade, futureprices will not be so high as projected when theNational Energy Act was passed.

Thus, oil-fueled cogeneration that does not of-fer net oil savings may be attractive in spite ofsupply and policy disincentives. For example,some cogenerators may not need high purchasepower rates under PURPA to be economicallyfeasible (e.g., where retail electricity rates are ex-ceptionally high), or may not wish to distributeelectricity to the utility grid (e.g., if onsite elec-tricity needs are large and retail rates are veryhigh, or if reliability of electricity supply is essen-tial). In addition, the FUA prohibitions only ap-ply to cogenerators larger than about 10 mega-watts (MW) (or a combined capacity of 25 MWper site) and those that sell more than half of theirelectric energy output. Furthermore, oil-fired co-generators may be eligible for the energy taxcredit if they consist of a retrofit at an existing in-dustrial or commercial facility that results in areduction in the amount of energy used onsite(e.g., adding a heat exchanger to an existingdiesel generator). Where these special circum-stances exist, oil-fired cogeneration could “slipthrough the cracks” in existing policies and resultin increased oil use.

If net oil savings is the desired policy goal,then a number of changes in Federal policy arepossible to close these gaps and further discour-age oil-fired cogeneration that would not offersuch savings. First, the FERC regulations imple-menting PURPA could be revised to includestandards for fuel use in qualifying facilities (e.g.,oil-fired cogenerators would not qualify for theeconomic and regulatory incentives offered byPURPA unless they could demonstrate a lifetimeoil savings). PURPA authorized the implementa-tion of fuel use standards, but FERC chose notto exercise its discretionary authority in this areain the belief that other provisions of the act (i. e.,the efficiency and operating standards and theavoided cost rate structure) would, when com-bined with market forces, be sufficient to discour-age oil-fired cogeneration. As stated in the in-troduction to the FERC rules implementing sec-tion 210 of PURPA:

Had Congress not intended that the benefitsof qualifying status be extended to oil- and nat-ural gas-fired cogeneration facilities, the statuteor [Conference Report] would have contained arestriction on fuel use similar to that which is pro-vided for small power producers. The Congressknew that cogeneration facilities typically usenatural gas and oil . . . the Congress enacted[FUA] at the same time as PURPA, [FUA] pro-vides authority to the Secretary of Energy to re-strict the use of oil and gas in cogeneration facil-ities. Therefore, [FERC] does not believe it neces-sary or appropriate to require an additional layerof fuel use regulation on technologies . . . forwhich another agency has authority to restrictfuel use. . . . To the extent that oil- and naturalgas-fired cogeneration facilities provide for moreefficient use of these resources, the Commissionbelieves that the benefits of qualifying statusshould be extended to them (4).

FERC’S decision not to require cogenerators tomeet fuel use requirements in order to qualifyunder PURPA was upheld in January 1982 by theU.S. Court of Appeals. The court agreed withFERC’S reasoning, and held that the regulationspromulgated by FERC were a reasoned and ade-quate response to the discretionary congressionalmandate.

Ch. 7—Policy Analysis ● 269

Adding fuel use restrictions to the PURPA regu-lations would not necessarily block those facilitiesfor which oil use may be economical even with-out the benefit of the PURPA incentives (i. e.,those systems that do not need to be intercon-nected with the grid). To reach these cogenera-tors, Congress could amend FUA to prohibit theuse of oil in all cogenerators, regardless of sizeor electricity sales, unless net oil savings aredemonstrated. The guidelines for such a demon-stration already are included in the EconomicRegulatory Administration regulations on largercogenerators, but extending them to coversmaller systems would require congressionalaction.

Finally, Congress could amend the energy taxcredit (and other advantageous tax code provi-sions such as accelerated cost recovery) to denycredits or deductions to oil-fired cogenerationsystems that cannot demonstrate net oil savings(regardless of reductions in onsite energy use).

However, each of these provisions would im-pose additional layers of regulation on an alreadycomplicated set of fuel use policies, and wouldonly affect a small portion of the cogenerationmarket. Perhaps as little as one-third of the indus-trial cogeneration market potential is at sites thatwould install less than 25 MW. As a result, evenif all the cogenerators that would be subject tothese regulations demonstrated net oil savingsand were installed, the resulting savings could beas low as 60,000 to 90,000 barrels of oil equiva-lent per day (bee/day) in 1990 (2). Moreover, thedifficulty of demonstrating net oil savings and thecumbersome paperwork involved in regulationsof this type could discourage even those oil burn-ing cogenerators that would pose net savings.

One alternative to imposing additional regula-tion of oil use would be to tax oil consumption(e.g., an oil import fee). This would be relativelysimple to administer, and would provide an ad-ditional Federal revenue stream. Although it hasbeen argued that such a tax would be infla-tionary, it also would be an effective conserva-tion measure because it would reach all users ofoil. Therefore, larger savings could be expectedthan if only cogeneration were targeted.

Another alternative to additional prohibitionson oil-fired cogeneration is to amend existingFederal laws and regulations to encourage thenear-term use of gas instead of oil. Natural gassupplies currently are more abundant and lessexpensive than oil, and over 90 percent of thenatural gas used in the United States is produceddomestically rather than imported. Where pur-chase power rates are set at or near the price ofoil-fired electricity and utilities have oil or gasburning capacity, natural gas fueled cogenerationwill be economically attractive even if natural gasprices approach those of distillate oil.

The use of natural gas in cogenerators alsowould complement the policies established un-der PURPA that encourage the export of cogen-erated electricity to the grid as an economicalalternative to building new central stationpowerplants, or as a form of insurance againstunexpected changes in electricity demand. Cur-rently available technologies that are likely to pro-duce more electricity than is needed onsite (i.e.,those with a high ratio of electricity-to-steam out-put–E/S ratio) cannot burn fuels other than oilor gas directly, and providing incentives (orremoving disincentives) for the use of gas couldautomatically discourage oil consumption.

The near-term use of natural gas in cogenera-tion systems also could be an integral part of anevolutionary fuels strategy, because syntheticgaseous fuels from coal, biomass, or wastes arelikely to be commercially feasible on a small ormedium scale (i.e., onsite gasification systems orthose with a limited distribution system) muchsooner than synthetic liquid fuels. Moreover,gaseous synfuels with a low- or medium-Btuvalue—which can be burned in cogenerators witha high E/S ratio—are likely to be produced morecheaply from alternate fuels (e.g., coal, biomass,solid waste) than liquid synfuels. The most prom-ising near-term liquid synthetic fuel that could beproduced on a relatively small scale is methanolfrom wood, which also could be used in com-bustion turbines.

The policy options that provide incentives (orremove disincentives) for the use of gas in cogen-

98-946 c1 - 93 - 19 : ,;1 !. 3


erators are similar to those described above fordiscouraging oil use:

●

●

●

FERC could amend the PURPA regulations(without further congressional action) todeny qualifying facility status to oil-fired sys-tems but specifically allow such status for gasburning cogenerators.Congress could amend FUA to extend theprohibitions to all oil-fired cogenerators re-gardless of size or electricity sales, while spe-cifically exempting natural gas-fired cogen-erators (or exempting those that would con-vert to synthetic gas or other fuels by 1990or 1995).Congress could amend the energy tax creditsto allow credits for gas-fired energy propertybut not oil-fired systems.

However, as noted above, each of these meas-ures would prevent or discourage the implemen-tation of those oil-fired systems that would posenet oil savings.

Encouraging gas-fired cogeneration in order todiscourage or prevent oil burning systems is acontroversial option. From a national fuels policyperspective, many analysts consider gas to beequivalent to oil in terms of its value as a premiumfuel and its future supply. If onsite or modulargasification systems do not become commercialas soon as their developers project, or if the costof synthetic low- or medium-Btu gas remains sig-nificantly higher than the cost of natural gas, thena strategy that encourages the near-term use ofnatural gas and a switch to synthetic gas in thelong run could fail, and thus lock cogeneratorsinto natural gas use for 10 to 20 years. Moreover,the potentially high cost of conversion to solidfuels where these fuels can be burned directly(e.g., fluidized bed), could cause cogeneratorsto stay on natural gas even if the solid fuel is muchcheaper in the long run. Thus, making cogenera-

tion with natural gas attractive eventually couldadd to supply pressures if future production andreserves are not so large as optimistic gas industryanalysts project.

Large established gas users (such as electric util-ites) understandably are concerned about the fu-ture uncertainty of their fuel supplies, and arguethat neither oil- nor gas-fired cogenerators shouldbe eligible for Government incentives underPURPA and the tax code. However, limiting ac-cess to, or otherwise discouraging the use of thesefuels could prevent cogenerators from taking ad-vantage of those savings that might be available.For example, a recent study that examined theeffects of an additional 10 percent investment taxcredit for cogeneration systems that used fuelsother than oil or natural gas found that such acredit would actually reduce both net energy andoil savings. The reduction occurred because theadditional credit would favor cogeneration tech-nologies that use coal or other alternative fuelsand thus, in the near term, would have a low E/Sratio and would not be able to displace utility oilfueled capacity (2). Therefore, measures that limitoil and gas use in cogeneration will not nec-essarily guarantee net oil/gas savings.

Some large established users also have arguedthat future supplies of high-Btu synthetic gas (thetype that would be produced in large centralizedfacilities and distributed in pipelines) should bereserved for such users because synthetic gas witha high energy content will be supply-limited forat least 20 years. OTA did not analyze the issueof allocating such gas to a particular class of users.Rather, the gasification schemes appropriate tocogeneration would produce low- or medium-Btu gas for onsite use or limited distribution, andthus would not compete in the same markets withpotential users of high-Btu synthetic gas.

ECONOMIC INCENTIVES FOR COGENERATIONBoth the amount of cogeneration capacity that sitive to economic considerations such as rates

will be considered an attractive investment, and for utility purchases of cogenerated power, taxthe amount of cogenerated electricity that may incentives, and other policy measures that reducebe available for export offsite, are extremely sen- either the capital or operating costs of cogenera-

Ch. 7—Policy Analysis . 271

tion systems. For example, a study of the poten-tial for cogeneration development by 1990 in thefive top steam-using industries under three levelsof utility purchase rates found that the amountof capacity that might be installed was almost sixtimes higher under the “high” purchase rates(ranging from 2.5cents to 7.5cents/kWh depending onthe geographic region —see table 36) than underthe “low” rates (1.0cents to 4.5cents/kWh). Moreover,under the higher assumed rates, a much greaterproportion of the installed capacity would be highE/S ratio technologies such as combined cyclesand combustion turbines that would be morelikely to make electricity available to the grid (seefig. 62). Under the lower assumed rates, theamount of cogenerated steam was reduced 11percent relative to the medium case, but theamount of cogenerated electricity was reducedby 50 percent (2). Analyses of tax provisions (e.g.,investment tax credits and accelerated deprecia-tion), and of subsidized financing (e.g., loan guar-antees, low interest loans) show a similar but lesssubstantial sensitivity of cogeneration installationand electric output to these economic incentives.

PURPA requires that purchase power rates bejust and reasonable to the electric utilities’ con-sumers and in the public interest, and that theynot exceed the incremental cost to the utility ofgenerating electricity itself or purchasing it fromthe grid (the “avoided cost”). FERC originally setrates for purchases of cogenerated power underPURPA equal to the utilities’ incremental cost,reasoning that only 100 percent avoided costrates would simultaneously encourage the fullestpossible development of the cogeneration marketand fuIfill the statutory requirements for just andreasonable rates. However, the FERC rules onpurchase rates were vacated by the U.S. Courtof Appeals in January 1982 on the grounds thatFERC had not adequately justified its choice ofthe “ceiling” rate established in the legislation,when a rate less than 100 percent of the avoidedcost would share the economic benefits of co-generation with the utilities’ noncogeneratingratepayers (see ch, 3). The U.S. Supreme COUrtwill review the appeals court decision, but finaldisposition of the case (either on appeal orthrough revised regulations, if necessary) may notoccur for a year or two.

Figure 62.—Cogeneration Development Under Low,Medium, and High Utiiity Purchase Rates: 1981.90

(MW)

6,200

6,280

1,170

2,100

3,250

32,500

1,650

1,300

1,450

Low Base Highbuyback buyback buyback

rates rates rates

‘Includes coal boilers and atmospherlc fluidized-bed boilers.b The high buyback rates and amount of MW development are considered infea-

sible, but are shown to demonstrate the sensitivity of cogeneration develop-ment to buyback rates.

SOURCE: Resource Planning Associates, The Potential for Cogeneration De-velopment by 1990 (Cambridge, Mass.: Resource Planning Asso-ciates, July 1981).

Although the full avoided cost rates remain ineffect pending a final decision, many potentialcogenerators (except where State legislatures orregulatory commissions have instituted fullavoided cost pricing independently of PURPA)have put their plans on hold as they wait to seewhether, in the long term, it will be economicallyfeasible for them to export power to the grid–and, if so, how much—or for them to cogenerateat all. Furthermore, the uncertainty about futurepurchase power rates has chilled the interest of

potential financial backers, who may not be will-ing to invest in cogeneration projects without firmlong-term purchase contracts with a utility until


after a ruling by the Supreme Court, and—possi-bly–then only if the full avoided cost regulationsare upheld.

Whether purchase power rates based on 100percent of the utility’s avoided cost are seen asdesirable depends on the policy goal. If the goalis to maximize cogeneration’s market potential,for whatever reason, then rates that reflect at leastthe full avoided cost are necessary (some Stateshave instituted even higher subsidy rates to en-courage cogeneration). In this case, cogenerationwould bean alternative (at least in the short term)to building new central station powerplants.However, if the goal is to provide the least costelectricity supply to the ratepayer, then purchasepower rates based on less than 100 percent ofthe avoided cost would share any economic sav-ings from cogeneration with the utilities’ otherconsumers.

As a compromise, the percentage of avoidedcost on which purchase power rates are basedcould be determined regionally. In areas whereutilities are heavily dependent on oil and/or areexperiencing demand growth (e.g., the Northeastand Pacific Coast), rates based on 100 percentof the short-term marginal cost (usually equivalentto the cost of oil—see ch. 3) could be institutedto encourage the fullest development of cogener-ation. These rates would share the benefits ofcogeneration’s potentially lower capital and inter-est costs with the ratepayers, but would not passon any of the cost benefits attributable to cogen-eration’s oil savings. Alternatively, rates based onthe full longrun marginal cost (equivalent to thecost of coal or nuclear capacity, or of advancedtechnologies) could share more of the cost sav-ings with noncogenerating customers. In regionswhere the utilities’ full avoided cost is very low,but cogeneration can provide insurance againstsudden changes in demand, full avoided costrates may be justified even though they wouldnot reduce rates for other customers. But whereutilities are dependent on alternate fuels andalready have substantial excess capacity, cogen-eration can increase rates to other consumers(through reduced fixed cost coverage–see ch.6), and rates at less than the full avoided cost–perhaps even equal to the cogeneration cost–may be justified.

A second source of uncertainty in Federal pol-icies that provide economic incentives for cogen-eration is the continued availability of tax provi-sions that reduce the capital cost of cogenera-tion. The special tax credit for investments inalternative energy property expires at the end of1982. A recent study of the economic incentivesfor cogeneration found that extending the 10 per-cent tax credit to 1990 (and making it applicableto oil- and natural gas-fired systems) could in-crease net oil savings attributable to cogenerationfrom 185,000 bee/day in 1990 to 210,000 bee/day. If all the fuel economically demanded by theincreased investment were natural gas, the directoil savings were estimated to increase from280,000 to 310,000 bee/day. In addition, theamount of cogeneration capacity was projectedto increase approximately 11 percent (from12,800 MW of installed capacity to 14,400 MW)in 1990. The resulting reduction in tax receipts(discounted at a 10 percent rate) was estimatedat $1.6 billion (equivalent, in this analysis, to$1.60/MMBtu, versus the saved oil cost of $5/MMBtu) (2).

The 1982 expiration of the energy tax credit willnot only reduce the available investment creditby half, but also may encourage investment incogeneration technologies “before their time. ”That is, advanced cogeneration technologies cur-rently under development (including evolu-tionary improvements in existing technologies)will have greater fuel flexibility, higher E/S ratios,better operating efficiency, and improved en-vironmental emissions. Many of these improve-ments will be ready by the mid-1980’s. Thus, thecontinued availability of the energy tax creditwould enable potential cogenerators to wait untilthey could select a technology that would max-imize the oil savings and other benefits of cogen-eration. In addition, extending the energy taxcredit to 1990 would enhance cogeneration’s rolein an evolutionary fuels strategy, in that a poten-tial cogenerator could invest in the basic tech-nology now and still receive the tax credit for alater addition of fuel flexibility (e.g., a gasifier orfluidized bed combustor). Finally, availability ofthe energy credit after 1982 would allow innova-tive financing mechanisms to be developed morefully.

Ch. 7—Policy Analysis 273

Similarly, the leasing provisions of the Eco-nomic Recovery Tax Act have been targeted forrepeal due to the loss in Federal revenues fromtheir widespread use by corporations seeking taxshelters. These provisions provide the primary in-centive for third-party investment in technologies(e.g., cogeneration) that will contribute to energyefficiency and increased productivity, and thatmay be economically attractive for the user butfor which the capital cost is prohibitive given theneed to invest in process improvements or con-servation measures. The uncertainty in their con-tinued availability is chilling third-party invest-ment, and thus the development of innovativeprivate financing arrangements, because potentialinvestors are chary of committing capital withouta guarantee that the needed tax incentives willbe available over the life of the investment. Ad-ditional analysis is needed to review the tradeoffbetween the degree to which tax leasing con-tributes to investments in increased energy effi-ciency and productivity, and its effects on Federalrevenues.

Other policy measures that would provide aneconomic incentive for cogeneration are optionsfor subsidized financing. High interest rates posea substantial disincentive to debt financing, whilerecessionary business trends inhibit equity andinternal financing. Subsidized financing optionssuch as low interest loans or loan guarantees canreduce the problems related to the cost and avail-

ability of capital. These options could be im-plemented through funding for existing programs.However, Government subsidies for financingwould be difficult to implement given the cur-rent Federal budget situation. The most effectiveway to enhance the investment climate is throughpolicies that promote general economic recovery,and which lower interest rates by reducinginflation.

As an alternative to Government financing sub-sidies, private subsidies could be offered. For ex-ample, Southern California Edison offers fundingassistance of up to $100,000 or 20 percent of thecapital cost (excluding installation labor) of theircustomers’ cogeneration systems. Similar pro-grams are offered by some utilities for solar orconservation investments. The utility’s investmentmight be included in the rate base, and the car-rying costs shared by all the utility’s customers.Utility involvement could encourage better in-tegration between cogenerators and utility sys-tems, and could increase the market potentialbecause utilities have a broader perspective onthe marginal costs of alternative energy suppliesand because’ subsidized financing could pose anincentive to more potential cogenerators than taxcredits. However, utility financing is subject tothe same potential drawbacks as utility owner-ship (see below), and may increase the capitalcost if the utility relies on equity capital for itsfinancing program.

UTILITY OWNERSHIP OF COGENERATORSThe economic and regulatory incentives estab-

lished under PURPA are granted only to “qualify-ing faciI it ies. ’ One of the statutory requirementsfor qualification is that the owner of a facility notbe “primarily engaged in the generation or saleof electric power” (other than electric powersolely from cogeneration or small power produc-tion facilities) (3). The FERC rules implementingthis requirement specify that if an electric utili-ty, a utility holding company, or a subsidiary ofeither holds more than a 50 percent interest ina cogeneration facility, that facility will not qualify

for the PURPA incentives. It is important to notethat PURPA only limits the extent to which utility-owned systems can receive an unregulated rateof return and can price cogenerated electricitybased on the cost of alternate power supplies.It does not prohibit or restrict electric utility own-ership or operation of cogenerators, and wherecogeneration is economically attractive relativeto conventional powerplants, utilities are, in somecases, making the investment. Utility-owned co-generators also are subject to less attractive treat-ment under the Energy Tax Act of 1978 because


public utility property (with the exception ofhydroelectric equipment) is not eligible for theenergy tax credit.

The ownership rule under PURPA and the un-equal tax treatment of utilities have become con-troversial for several reasons. Electric utilities ar-gue that the ownership rule discriminates againstthem because it does not apply equally to othertypes of utilities (e.g., gas utilities). When com-bined with the tax provisions, the 50 percentownership limitation also means that cogenera-tors owned by electric utilities may not be as eco-nomically competitive as facilities owned by otherparties. This is especially disturbing to the elec-tric utilities, because electricity generation is theirprimary business.

Furthermore, it is likely that cogeneration’smarket potential and electricity output would bemuch greater if utilities were allowed 100 per-cent unregulated ownership. A study of thecogeneration potential in five industries(representing 75 percent of U.S. industrial steamdemand) found that, of a total technical poten-tial of 12,800 MW by 1990, 4,000 MW would bestimulated solely by full utility ownership (2).Similarly, a study by Arkansas Power & Light(AP&L) concluded that the industrial cogenerationpotential among 35 high steam load factor cus-tomers would be approximately 100 MW of elec-tric capacity under industrial ownership, but upto 1,700 MW under utility ownership (l). Theprimary reasons for the differences in the amountof cogenerated electricity with utility and nonutili-ty ownership cited by these analyses are thatutilities would be more likely to choose technol-ogies with high E/S ratios, and that utilities mayrequire a lower rate of return and often have bet-ter access to capital markets than other investors.As a result of the higher electricity production(and thus more power available to the grid) andthe better financial position, utilities could findmore projects economically attractive. However,without the full PURPA benefits—especially anunregulated rate of return on cogenerated elec-tricity—utilities would not have so much of anincentive to invest.

Finally, allowing 100 percent electric utilityownership under PURPA would lessen utility con-

cerns about competition from cogenerators andthe resulting possibility of reduced fixed cost cov-erage (see ch. 6). AP&L found that if the 35 like-ly cogeneration candidates in their service areahad cogenerated in 1981 under industrial or third-party ownership, AP&L’s revenue loss wouldhave been almost $40 million in that year (1). Thiswould mean that rates for their remaining cus-tomers would have increased as AP&L’s fixedcosts would be spread over a smaller number ofcustomers while their income dropped substan-tially. Utility ownership would protect againstsuch revenue losses and rate increases, and couldprovide additional revenue streams from steamsales while reducing the rate of increase in retailelectricity rates.

As noted above, utility ownership of cogenera-tors is possible without changes in PURPA or thetax code. Thus, an electric utility could own reg-ulated cogeneration capacity, or it could partici-pate in a joint venture. In either case, some ofthe advantages of 100 percent unregulated util-ity ownership would be available, including thepotential for greater amounts of installed cogen-eration capacity and greater electricity outputfrom cogenerators than under industrial or otherprivate ownership arrangements, and protectionfrom the adverse effects of competition. How-ever, joint ventures may be difficult to arrange,while regulated ownership presents limited finan-cial incentives for investments in cogenerationcapacity. The regulated rate of return would, inmost States, be the same for cogeneration as forother types of new powerplants (e.g., coal or nu-clear) despite the potentially higher administrativecosts and investment risks. Allowing utilities tocompete for unregulated cogeneration capacityon the same basis as other potential investorswould provide utilities with stronger incentivesand ensure that the full range of benefits of util-ity ownership would be available. These incen-tives would be even greater if the tax treatmentwere equalized as well.

However, 100 percent utility ownership of co-generators under PURPA also could have disad-vantages. The PURPA ownership rule was en-acted in part out of concern that full utility owner-ship might have anticompetitive effects on the


development of and market for cogenerationtechnologies. That is, it has been suggested thatutilities could “capture” the cogeneration marketby favoring their own (or their subsidiaries’) proj-ects through more favorable contract terms, prior-ity in contracting (and thus potentially higher en-ergy and/or capacity credits), and less stringentinterconnection requirements. Moreover, due tothe potential for cross-subsidization, utilities’ re-quired rate of return–even if unregulated–couldbe sufficiently lower than other investors’ andthus allow the utilities a competitive advantage.In addition, some opponents of unregulated util-ity ownership have argued that utilities might tendto favor a limited number of large vendors andmanufacturers, with potentially adverse effects onsmall businesses and the development of ad-vanced technologies.

However, the implementation of cogenerationtechnologies by utilities can be protected fromsuch anticompetitive effects through carefullydrafted legislation and regulations (e.g., similarto the parts of the Energy Security Act thatamended the utility provisions of the National En-ergy Conservation Policy Act), and through tradi-tional administrative and legal remedies. Alterna-tively, the question of whether utilities should beallowed to own cogenerators under PURPA couIdbe left to the States, with requirements for case-by-case review of ownership schemes by the Stateregulatory commission prior to their implementa-tion. With carefully drafted legislation and/orState review programs, it is likely that the eco-nomic and other benefits of utility ownershipwould outweigh the potential for anticompetitiveeffects.

INTERCONNECTION REQUIREMENTSThe interconnection requirements for cogen-

eration have become an issue for two reasons:1 ) because of the procedures that may be neces-sary to obtain interconnection, and 2) becauseof the uncertainty about the amount and type ofequipment that will be necessary to protect utilitylineworkers and the utility system in general.

As discussed in chapter 3, the original FERC reg-ulations implementing PURPA required utilitiesto interconnect with cogenerators as part of thegeneral obligation to purchase power from andsell it to cogeneration facilities. This requirementwas overturned by the U.S. Court of Appeals onthe grounds that PURPA also included provisionsamending the Federal Power Act to establish pro-cedures for obtaining an interconnection order,and that PURPA did not exempt cogeneration sys-tems from this process. Thus, absent a legislativeamendment to PURPA, a cogenerator whose util-ity is unwilling to interconnect (or a utility whowants to interconnect with an unwilling cogener-ator) must apply for a FERC order.

FERC may not issue an interconnection orderunder the Federal Power Act unless the commis-sion determines that the order:

(1)(2)

(3)

(4

(5

(6)

is in the public interest, andwould (a) encourage the overall conserva-tion of energy or capital, or (b) optimize theefficiency of use of facilities or resources,or (c) improve the reliability of any electricutility system or Federal power marketingagency to which the order applies, andis not likely to result in a reasonably ascer-tainable uncompensated economic loss forany electric utility or qualifying cogeneratoraffected by the order, andwill not place an undue burden on an elec-tric utility or qualifying cogenerator affectedby the order, andwill not unreasonably impair the reliabilityof any electric utility affected by the order,andwill not impair the ability of any electric util-ity affected by the order-to render adequateservice to its customers.

Finally, in issuing an interconnection order, FERCmust issue notice to each affected party and af-ford an opportunity for a full evidentiary hearingunder the Administrative Procedure Act.

The requirements under the Federal Power Actwill be extremely difficult and expensive for a


cogenerator to meet. Even in well-understood sit-uations, full evidentiary administrative hearingsentail expenses and delays that can pose a sub-stantial disincentive to applying for an order. Butmost of the showings listed above are couchedin new, broad language that will have to be con-strued, first, by FERC and then, in all likelihood,by the courts. Moreover, in some cases, a cogen-erator will not have access to the data neededto make a particular showing, or only will be ableto acquire and analyze the data at great expense.Thus, these provisions of the Federal Power Act(as amended by PURPA) pose a substantial deter-rent to cogenerators that cannot get an electricutility to interconnect voluntarily—one of theprimary obstacles to cogeneration that PURPAwas intended to remedy.

in adopting revised regulations to implementthe interconnection provisions of the FederalPower Act, FERC can adopt streamlined proce-dures that minimize the administrative burden onthe cogenerator or shift that burden to the util-ity; the act only specifies that the necessary deter-minations “shall be based upon a showing of theparties.” However, full relief from the FederalPower Act procedures can only come throughlegislative amendment of the act to specify thatinterconnection is required in order to make pur-chases of power from, and sales of power to, co-generators, or through independent action byeach of the State legislatures.

The second area of controversy related to inter-connection is the amount and type of equipmentrequired. As discussed in chapter 4, specialequipment may be necessary in order to regulatepower quality, meter cogenerators’ power pro-duction and consumption properly, control utilitysystem operations, maintain system stability, andprotect utility lineworkers. Given the lack of ex-perience with power flows from cogenerators tothe grid, utilities are understandably concerned

about proper interconnection. But, with the pos-sible exception of maintaining system stability,the interconnection requirements are relativelywell understood, and OTA found no technicalobstacles to proper interconnection. However,the amount and type of equipment required bythe utility (or the State regulatory commission)can be a major economic issue, because suchequipment can add substantially to the capitalcost of a cogeneration system. Few guidelines forinterconnection are available (other than thoseset by utilities), but research is underway to pro-vide the needed information, and several groupsare working on interconnection standards (in-cluding the Institute of Electrical and ElectronicsEngineers’ Power System Relaying Committee,the Electric Power Research Institute, the Jet Pro-pulsion Laboratory, the Department of Energy’sElectrical Energy Systems Division, and the Na-tional Electrical Code). Research to date pointsout the need for performance-based standardsthat will allow cogenerators to meet functionalcriteria rather than requiring them to install partic-ular types of equipment that might later be foundu necessary.

Better data and additional analysis also areneeded to determine the actual costs of properinterconnection. Cost estimates obtained throughsimulation and other techniques must be verifiedon actual systems. The State regulatory commis-sions should encourage those utilities that havenot done so to prepare guidelines for intercon-nection, and to update those guidelines as newdata are made available. However, until betterdata are available, it is likely that both utilities andState regulatory commissions will have to reviewinterconnections on a case-by-case basis to en-sure that both the potential hazards to the utilitysystem and the costs to the cogenerator are mini-mized.

AIR QUALITY IMPACTSAdvocates of cogeneration argue that special by many potential cogenerators as a major im-

treatment for cogeneration under the Clean Air pediment. Suggested changes that would removeAct would enhance its market potential, because this impediment include, first, setting emissionscompliance with air quality regulations is cited standards that account for cogenerators’ effi-


ciency—either by tying the standards to energyoutput rather than fuel input or by having sepa-rate and more lenient standards for cogenerators;and second, revising new source review proce-dures under the prevention of significant deterior-ation and nonattainment area provisions of theClean Air Act to automatically credit cogeneratorsfor reductions in emissions from the separate ther-mal and electric energy systems they would re-place. The costs of complying with current airquality regulations and the potential impacts ofthese proposed changes are discussed in detailin chapter 6 and reviewed briefly here.

Both of these policy changes would significantlyreduce the costs of pollution control for cogener-ators and thus would increase their economic at-tractiveness. However, cogeneration’s fuel effi-ciency does not always lead to reduced emis-sions, nor does its substitution for two separateenergy systems always produce a net air qualitybenefit.

In general, improved fuel efficiency will leadto reduced emissions from electricity generationonly when a cogenerator replaces an electric gen-erator of the same size and type. Thus, if the co-generator involves new technology or fuel substi-tutions, or a change in scale, the net result maybe an emissions increase. Even if emissions arereduced, that reduction may occur at a differentlocation and the cogenerator could still have anegative impact on local air quality (e.g., reducedemissions at a rural powerplant but higher ambi-ent concentrations around an urban cogenera-tor). Finally, cogenerators may involve a changein the type of emissions (e.g., reduced sulfur

RESEARCH ANDFederal R&D support for energy technologies

is in a state of flux and OTA was not able to ana-lyze the direction of current research and devel-opment (R&D) efforts for cogeneration and re-lated combustion systems. Based on OTA’s as-sessment of cogeneration technologies and op-portunities, however, it is believed that highpriority should be given to funding or encourag-ing the development of systems with a low capitalcost and a high E/S ratio that can burn fuels other

oxide emissions from a coal burning facility butincreased emissions of potentially toxic dieselparticulate).

Moreover, those technologies that are mostlikely to contribute to air quality problems–smallsteam and combustion turbines and diesel andspark-ignition engines—are the least likely to becontrolled. At present, Federal New Source Per-formance Standards only apply to steam turbineslarger than about 25 MW and gas turbines largerthan around 10 MW. Standards for diesel nitro-gen oxide emissions were proposed, but with-drawn. The emissions characteristics of unregu-lated technologies vary widely among differentengine models, and cogeneration systems mustbe carefully designed, sited, and controlled toavoid adverse air quality impacts. Control tech-nologies do exist for smaller steam and gas tur-bines and for diesels, but their effectiveness andcosts also vary widely, and their use currently isnot mandated by Federal law.

As a result of these considerations, there ap-pears to be little public health or environmentaljustification for automatically granting cogenera-tors relief from air quality regulations. Rather,such relief might be afforded on a case-by-casebasis to those cogenerators that can demonstrateair quality benefits. Moreover, the special air pol-lution problems posed by cogenerators that arenot regulated under the Clean Air Act (either be-cause of their size or the type of technology) mayrequire more stringent review by State or localagencies—a task those agencies may be ill--equipped to handle.

than oil and natural gas cleanly. The promisingapplications identified in chapter 4 include thegasification of coal, biomass, or wastes for usein combustion turbines or combined cycles; fluid-ized bed combustion systems that can be usedin conjunction with steam or combustion tur-bines; direct-fired combustion turbines using solidfuels (pulverized coal or wood); and advancedtechnologies such as fuel cells, organic Rankinebottoming cycles, and Stirling engines.


Additional R&D also is needed on the effects ment of low-cost effective emission controls forof a large number of dispersed generating sources smaller cogeneration systems.on utility system stability, and for

Federal policy on cogeneration

the develop-

SUMMARY

generally en-courages grid-connected applications that cansave oil or natural gas while promoting the effi-cient use of economic and electric utility re-sources and protecting public health and the en-vironment. In most cases, these policies will havethe intended effects. However, special circum-stances may mean that some cogeneration appli-cations could increase oil use, or have adverseeconomic impacts on already financially troubledelectric utilities, or lead to local air quality prob-lems. options for closing these gaps in currentFederal policy initiatives are summarized in table70. Although some of these options would re-quire congressional action, most are relativelyeasy to implement (i.e., low administrative costs,few additional regulations).

Cogeneration can make an important contribu-tion to the Nation’s transition to the efficient useof fuels other than oil and gas while providingimportant economic benefits. But achieving themaximum benefits from cogeneration—and

avoiding its potential drawbacks—will require in-novation in technologies, financial markets, andutility management. And, until more experienceis gained with cogeneration under the currentenergy, economic, and environmental context,it will require careful planning. This includes care-ful selection of cogeneration technologies as wellas careful design and siting to ensure that theneeds of both the thermal energy user and thelocal utility are met at an attractive cost and withminimum environmental impacts. In most cases,such planning can be achieved easily if early co-operation among all concerned parties-potentialcogenerators, utilities, and Government agencies—is secured. Some utilities and State and localagencies already have initiated cooperative plan-ning programs designed to maximize cogenera-tion’s market potential and energy and economicbenefits. Others are bound to follow as soon asthey recognize that such planning is in their inter-ests.

Ch. 7–Policy Analysis ● 279

Table 70.—Summary of Policy Considerations Related to Cogeneration

Government action requiredOptions to implement options Potential impact of options Administrative cost

Policy Issue 1: Posslbillty that oil-fired cogeneration would increase Oil useA.

B.

c.

D.

E.

Require oil-fired cogenerators Amend FERC regulations Would not block all of theto demonstrate net oilsavings in order to qualifyfor PURPA benefits

Prohibit the use of oil in allcogenerators unless net oilsavings are demonstrated

Deny energy tax credits foroil-fired cogenerators

Encourage use of naturalgas instead of oil

Oil tax (e.g., import taxor user fee)

implementing PURPA

Congressional action toamend FUA, plus agencyimplementation

Congressional action toamend tax code plus IRSimplementation

Same as 1A-C, but in eachcase specifically allowingnatural gas-firedcogeneration

Congressional actionamend tax code

oil-fired cogeneratorsthat could increase oiluse; may discouragesome that would save oil

Would block all cogeneratorsthat could increase oil use;may discourage some thatwould save oil

Would provide furthereconomic disincentive tooil-fired cogeneration,even when it would saveoil

Would effectively blockoil-fired cogenerationwhile providing marketincentives to gas-fired;would complementexisting policies thatencourage conversion toalternate fuels; couldlock cogenerators intonatural gas use,increasing supplypressure over time

to Would encourage oilconservation in, allmarkets, provideadditional Federalrevenues

Policy issue 2 Denial of equal benefits for utiiity-owned cogenerators under PURPA and theA. Allow 100 percent utility- Congressional action to Could: increase cogeneration

owned cogenerators to amend PURPA plus market penetration andqualify for PURPA benefits FERC implementation electricity production;

reduce rate of growth inelectric rates; improvefinancial health ofelectric utilities; provideinsurance againstunexpected changes indemand growth. Alsocould have anticompetitiveeffects on thecogeneration market andon technologydevelopment andimplementation, unlesslegislation were draftedcarefully and/or Statereview programs weremandated

B. Allow energy tax credit for Congressional action to Could stimulate utilityutility-owned cogenerators amend tax code plus IRS investment with same

implementation effects as 2A

Policy issue 3: Tax incentive for investment in cogeneration expires in 1932A. Extend energy tax credit to Congressional action to Would provide continued

1990 amend tax code plus IRS stimulus to investment;implementation allow time for advanced

technologies to becomecommercial

Potentially high for bothFERC and oil-firedcogenerators

Potentially low forimplementing agency andhigh for oil-firedcogenerators

Low for both IRS andcogenerators

Agency costs same as1A-C, oil-firedcogenerator costs high;gas-fired low

Relatively low

tax codeLow for implementation.

Possibly high formonitoring potentialanticompetitive effects

No greater than for existingenergy tax credit

Continuation of workloadunder present tax credit


Table 70.—Summary of Policy Considerations Related to Cogeneration—Continued

Government action requiredOptions to implement options Potential impact of options Administrative cost

Policy issue 4- Compliance with air quality regulations is a major impediment to cogeneration developmentA. Set emissions standards

that account forcogenerators’ greater fuelefficiency

B. Revise new source reviewprocedures to automaticallycredit cogenerators forreductions in emissionsfrom the separatetechnologies they woulddisplace

Congressional action toamend Clean Air Act plusEPA and Stateimplementation

Congressional action toamend Clean Air Act plusEPA and Stateimplementation

Would reduce costs-of Possibly lower than underemissions control. Couldresult in net emissionsincrease, especially inurban areas

Would reduce costs tocogenerator of performingair quality modeling andsecuring offsets. Couldresult in net emissionsincrease at cogenerationsite

Policy issue 5: Rates for purchases of cogenerated power are uncertainA. Amend PURPA to set rates Congressional action to Would provide major

at 100 percent of utilities’ amend PURPA economic incentive toavoided cost cogeneration without

reducing rates to otherutility customers

B. Revise FERC regulations to FERC implementation In some areas wouldset rates according to provide less economicregional opportunities for incentive than 5A, butoil/gas and cost savings would share economic

benefits with ratepayers

Policy Issue 6: Interconnection procedures can pose substantial disincentiveA. Redraft FERC regulations FERC implementation Would minimize procedural

to shift evidentiary burden burden on cogeneratorsto utilities to obtain interconnection

B. Amend Federal Power Act Congressional action to Would eliminate proceduralto require interconnection amend Federal Power Act burden

existing regulations

Would shift costs previouslyborne by cogenerators toalready understaffedState agencies

Same as under presentregulations

Initially slightly higher thanpresent regulations

Costly for FERC,cogenerators, and utilities

Minimal

Policy issue 7: Interconnection requirements can substantially increase cogeneration capital costsA. Accelerate research and More aggressive FERC Will reduce uncertainty for Minimal

encourage utilities and implementation cogeneratorState regulatorycommissions to establishperformance-basedstandards


CHAPTER 7 REFERENCES1. Mitchell, Ralph C, Ill, Arkansas Power& Light, pri- 3.16 U.S.C. 796 (Public Law 95-61 7).

vate communication to OTA, Nov. 19, 1981. 4.45 Fed. Reg. 17959, at 17963 (Mar. 20, 1980).2. Resource Planning Associates, The Potential for Co-

generation Development by 1990 (RPA ReferenceNo: RA-81 -1455; July 31, 1981).

Appendixes

Appendix ADispersed Electricity Technology

Assessment (DELTA) Model

The DELTA model is a linear programing mathemat-ical model used to calculate the costs of satisfying elec-tric, heating, and cooling demands of a particular elec-tric utility, given the capital equipment in operationin 1980. The model computes a capacity expansionplan that minimizes the time-discounted sum of capi-tal, operating, and fuel costs.

This appendix is divided into three sections: first,a description of the major assumptions used in the for-mulation of the model; second, a list of all the vari-ables and notations used in the model equation set;and third, the equation-by-equation description.

Major Assumptions and ModelFormulation

All of the major assumptions used in the DELTAmodel are described in chapter 5. They are summar-ized below:

First, the model uses the linear programing type ofmathematical programing in its representation of theutility system. Second, the model only simulates co-generation that is connected to the grid. Third, themodel divides the entire commercial sector into threesubsectors corresponding to three types of demandpatterns: multifamily, hospitals/hotels, and 9-to-5 officebuildings. Fourth, the model uses the eight differenttypes of daily load cycles in its representation of elec-trical, heating, and cooling demands, Fifth, the modelhas two different types of fuel price paths. Sixth, threedifferent sample utility systems were used. Seventh,different assumptions were made to represent the vari-ous technologies, the way they operate, and the finan-cial structure of the utility region.

As mentioned in chapter 5, the model uses threetypes of energy demands—electrical, thermal heating,and cooling—that must be met by a combination ofelectrical and thermal generation. A schematic for thegeneral structure of the model (for a particular subsec-tor) is given in figure A-1.

Notation And Variables Used

Each variable (representing particular activities of autility) may have up to five subscripts for its mathemat-ical shorthand. The subscripts are:

n— for each centralized technology type [e.g., n = 1(baseload), n=2 (intermediate), n=3 (peak-ing)];

Figure A-1 .—DELTA Model Structure

Supply Demand.

I *

THG

Thermalstorage

COG

SOURCE: Office of Technology Assessment,

s– for subsector (multifamily, hospitals/hotels,9-to-S office buildings);

y– for time period (O is 1980, 1 is 1990, 2 is 2000);d– for the day type (eight different ones, e.g., peak

summer weekend day); andh– for the hour of the day represented.For each individual dispersed type of technology

represented and each subsectors and year, day, andhour y, d, h, we represent the various activities withthe following mathematical shorthand. Power outputis measured in megawatt hours, while capacity ismeasured in megawatts. One thermal megawatt isequal to 3.412 million Btu/hr.

COGsydh

cocsy

T H Gs y d h

T H Csy

E C Dsydh

is the cogeneration electrical power out-put in subsector s at time y, d, h.is the cogeneration power capacity in sub-sector s at year y.is the electrical heating power generationin subsector s at time y, d, h.is the electrical heating power capacity insubsector s at year y.is the electric air conditioning output insubsector s at time y, d, h.

283


ECCsy is the electric air conditioning capacity insubsector s at year y.

TCDsydh is the thermal (absorptive) air condition-ing output in subsector s at time y, d, h.

TCCsy is the thermal (absorptive) air condition-ing capacity in subsector s at year y.

SPHsydh is the thermal heating output in subsec-tor s in time y, d, h.

There are also the electrical generation variables,that are represented for the different types of central-ized technologies n and time y, d, h:

ELGnydh is the central electric power generation fortechnology n and time y, d, h (measuredin MWh).

ELCnY is the central electric power capacity fortechnology n and year y (measured inMW).

Finally, there are three variables that represent thethermal storage activities for each subsectors and timey, d, h:

TOTsydh

TINsydh

TECsy

is the dispersed thermal storage output forsubsectors and time y, d, h (measured inMWh).is the dispersed thermal storage input forsubsectors and time y,d, h (measured inMWh).is the dispersed thermal storage energycapacity for subsectors and year y (meas-ured in MW).

The input and output variables are measured inmegawatts, while the capacity is measured inmegawatt-hours.

The various technological characteristics are abbre-viated mathematically with the following shorthand:

An is the availability of equipment of technol-ogy type n to provide power.

MANnYd is the amount of time that technology typen is out of service for maintenance in yeary and day d.

C(.) is the annual capital cost or operating costfor each capacity activity variable (.)

DISCY is the real discount factor for both capitaland operating costs.

The three types of energy demands are abbreviated:ELDydh is electrical demand in time y, d, h.

CLDsydh is the thermal cooling demand for subsec-tor s in time y, d, h.

HTDsydh is the thermal heating demand for subsec-tor s in time y, d, h.

The DELTA model is fixed for certain time periods,with NDd being the number of days per year of daytype d.

Equation Description

As in standard with linear programing-type of for-mulations, we divide our description of the equationsinto two parts: first a description of the objective func-tion and then the constraints.

Objective Function

The objective function is to minimize the sum of dis-counted (over the time period of the model back to1980 dollars) the annual costs of operation and capac-ity of electric generation, cooling, heating, and thecosts of thermal storage. The mathematical descrip-tion

min

Appendix A—Dispersed Electricity Technology Assessment (DELTA) Model ● 285

puts to thermal storage (TIN) plus heating demands and thermal cooling devices (TCD). The cogeneration output is multiplied by the ratio of steam to electricity (1.29) and the thermal cooling output is multiplied by its coefficient of performance (.67):

THGsydh + (COGsydh .. 1.29) + TOTsydh ~ T1Nsydh + HTDsydh +

(TCDsydg/O.67) for all s, y, d, h.

CAPACITY AVAILABILITY

The output of each electrical and thermal generator must not exceed its available capacity. This available capacity is defined as 1980 capacity plus additions in future years minus the amount of capacity removed for maintenance (MAN). In order to sum up all capacity additions, the mathematical shorthand uses the subscript i, ranging from 0 to the value of the year subscript y. There are five types of equations for capacity:

Electric capacity: y

ELGnydh S An • r=o (ELCni - MANnyd) for all n, y, d, h

ELCnO is set at initial 1980 capacity (input)

Thermal capacity: Y

THGsydh S (0.95) .. r=o THCsi for all s, y, d, h

THCsa = 0 for all 5 (Initial 1980 capacity i5 5et at zero)

Cogeneration capacity: Y

COGsydh S (0.95) .. r=o COCsi for all 5, y, d, h

COCsO = 0 for all 5 (Initial 1980 capacity i5 5et at zero)

Electric cooling capacity: y

ECDsydh S (0.95) .. r=o ECC5i for all 5, y, d, h ECCsO ., 0 for all 5

Thermal cooling capacity: y

TCDsydh S (0.95) .. r=o TCCsi for all 5, y, d, h

TCCsO = 0 for all 5

THERMAL STORAGE CAPACITY

Thermal storage capacity (TEC) equals or exceeds dai Iy storage multi plied by the efficiency of the storage (0.90) for each subsector s:

y (0.90)" E TINsydh S ~ TECsi for all 5, y, d

h 1=0

THERMAL STORAGE AVAIALBILITY

Thermal energy output must not exceed storage during that particular day multiplied by the storage efficiency (0.90):

E TOT dh S (0.90)" E TINsydh for all 5, y, d h ~ h

RESERVE MARGIN

Centralized electric capacity plus cogeneration capacity equals or exceeds peak demands times 1.20 (a 20 percent reserve margin):

y y ~ r=o (ELCni - MANnyd) + f r=o COCsi ~ (1.20) ..

F (ECDsydh/3.0) + ELDydh for peak hours, peak days, and all y

MAINTENANCE SCHEDULING

The scheduled maintenance of baseload and intermediate generation capacity equals or exceeds the scheduled maintenance required annually. Each capacity type needs to be maintained for 10 percent of the year, or 876 hours:

Y 24" J (NDd .. MANnyd) ~ 876 .. r=o ELCni for all y and n = 1, 2

Appendix BEmissions Changes

A number of analyses of emissions changes causedby cogeneration have been conducted. All of theseanalyses, however, are site-specific and do not illus-trate the effects of changing critical assumptions, orthey have extrapolated to regional or national emis-sions changes by using simplifying assumptions aboutcritical parameters (e.g., the type of fuels “backedout” of the utilities’ centralized systems) that may besignificantly in error.

The following tables display the emissions attribut-able to each component in a possible switch from asystem using central station-generated electricity anda local heat source to a system using cogeneration.A number of options for the central plant, cogenerator,and heat source are shown in order to allow a rangeof circumstances to be evaluated. Because of the sig-nificant variation possible in each of the components(for example, the thermal efficiencies and emissions

Table B-l.—Emissions From Cogenerator Options

Emissions (lb/100 kWh)

Type Fuel Input Heat captureda Thermal efficiency NOX Particulate CO HC Soxb Comment

Diesel . . . . . . . . . . . . . . . . . . 990,000 C 350,000 C 0 . 7 0d 3.43° 0.07f owe O.l0e 0.29 Oil, Uric.2.49e ND 0.64* 0.87e 0.02g Dual Fuel, Uric.2.20h NS NS NS NS NSPS

Gas turbine . . . . . . . . . . . . . 1,365,000 610,000 0.70k .8 0.03m 0.15m 0.05m O.0lm Gas, Unc.1.2 0.08” 0.03 0.05 0=2

g

0il, Unc.0.4° NS NS NS 1.09 NSPS

NSPS steam turbine. . . . . . 2,970,000P 2,000,000P 0.79P 2.08 q 0.30 q

0.12 0.03 3.56 q

Coal0.89 q 0.30q NEG 0.03 2.38q oil0.59q 0.03 NEG 0.12 0.21 Gas

ND - No data foundNS - No standardNEG - NegligibleaUnless the cogeneratlng system has heat storage capability and/or very careful balancing of heat production and actual need, less heat than this will be usefullycaptured, the system efficiency will decrease, and the overall emissions balance between cogeneratlon end the central station power/local heating source will worsen.

b values for SOX are entirely fuel dependent, Essentially 100 percent of the sulfur contained in the fuel is transformed into S0x upon combustion.c Based on fuel rate data in Environment Protection Agency, Standards Support and Environmental Impact Statement for Stationary Internal Combustion Engines,

draft, EPA-450/2-78-125a July 1979, assuming 95 percent generator efficiency.dTh data sources did not converW on any efficiency v~ue as ‘!best,!J but values ranged from 62 to ~ percent. The fnajw source Of VariSb’lltY appearS to be the WflOUllt

of heat captured rather than the total fuel input.eB~~ on s~es.weighted Werages for large-bore diesels, data in EPA, oP. cit. (note c).fEnvironmentai pmt=tlon A~ncY, m~pllation of Ah pollutant Ef?lhSh ~ectof’e V@@, 1978.gAssumes 0.2 percent sulfur diesel fuel or distillate oil.hTh e New $jOurce peflommce Standti for diesels burning oil or oil/natur~ g= combinations iS ~ ppm of Nox. This iS rOt/gh/y trSllSldSble ifltO about 7 gramS

per horsepower hour, or about 2.2 lb/MMBtu, personal communication from Douglas Salt, Office of Air Quality Planning and Standards, Research Triangle Park, N.C.iThe application of NOx emission controls may have an effect on emissions of other pollutants. Because efficiency may decrease somewhat with such controls the

effect on CO and HC may be adverse.jTot~ fuel input and heat captured in a gss turbine cogenerator are extremely variable. Data shown are from ICF, Inc., A Techn/ca/ and Ecorrorn/c Eva/uat/on of D/s-persed Electric Geoeratlon Technologies, draft final report to OTA, October 19S0, table 3-3, simple-cycle turbine.

klbid agrws With the ,,typical,, tu~ine in General Accounting Office, /n~str/a/ ~generat/on_What /t /s, HOW /t wor~s, /ts /%@/7t/a/, 13vfD-60-7, Apr. 29, 1960.IEnvi~onmentd protwtion Awncy, Sfmdads Supwfi ~~ Env/~rrmerrta/ lm~t statement for Stationary Gas Turbines, EPA40/2-77-017% SePtemkr 1977, PP. 3-110,

for “typicaJ,” uncontrolled turbines.mEnvironmentaj protection Agency, Ap42, Op, cit. (note f). Note that the AP-42 value for NO is 0,4 lb/MMBtu V. 0.6 lb/MMBtu fOr EPA, OP. cit. (note 1).nFew data were found. This Vaiue applies to ~ GE 7921 B combustion turbine, cited in J. A, ?aylOr, An A/r @@/~ Assessment for /CES ~pt/OrrS, Argonne National

Laboratory, September 1960, draft.~he New Source Performance Standard for gas turbines is 75 ppm of NOX, roughly translatable into about 0.225 to 0.3 lb/MMBtu, personal communication from Dougias

Bell, OAQPS, RTP, N.C. Table 3-11 in EPA, op. cit. (note 1) equates 75 pm at 15 percent oxygen to 0.3 lb/MMBtu, but the significant variability in fuel rates of geeturbines implies a range of “lb/MMBtu” rates.

pFrom General Accounting Office, lw, op. cit., (note k), p. 92. Because a steam turbine may be designed to convert anywhere from zero to over 30 percent of itsfuel energy to electricity, these vaiues represent only one possible combination in an extremely broad range.

qa CFR ~ Subpt. D, Nsps for steem generators Other thm utility Over 73 MW input. Generators smailer than this size are subject to State implementation plan regulations.


Appendix B—Emission Charges “ 287

from a gas turbine or diesel can vary over a fairly wide tions of cogenerator, central power facility, and localrange), however, the tables capture only a portion of heat source can be calculated by using the formula:the potential variability in emissions balances. (net emissions in lbs/100 kWh

The values of energy flow and emissions displayed of cogenerated power) = (cogenerator emissions, table B-1)

are normalized to an ”electrical output of 100 kiloWatt-hours. Emission “balances” for particular combina-

– (central station power emis-sions, table B-2) – (hot water andsteam emission factor, table B-3)*

(heat captured, table B-l/l O,)

Table B-2.—Emissions From Central Station Power Stations(to provide 100 kWh of delivered power)

Emissions a, lb/100 kWh

Type Fuel input NOX Part CO HC SOX

Coal-fired powerpiant, NSPS,scrubber . . . . . . . . . . . . . . . . . . . . . . . 1,1OO,000 b 0.55 0.03 0.04 0.01 1.32’

Oider coal-fired plant, 3°/0 sulfurIO% ash with 95% control,13,000 Btu/lb . . . . . . . . . . . . . . . . . . . 1,000,000 0.69 0,31 0.04 0.01 4.38

Oil-fired plant, NSPS, low sulfur oii. . 1,000,000 0.30 0.03 0.04 0.01 0.80Older oii-fired plant, 1 % sulfur. . . . . . 1,000,000 0.70 0.05 0.04 0.01 1.05Older natural gas-fired plant . . . . . . . . 1,000,000 0.67 0.01 0.02 0.04 NEG.Existing gas turbine peaking plants . l,lOO,OOO d 0.43 (.66)e 0.01 0.12 NEG. NEG. GasExisting gas turbine peaking plants . l,lOO,OOO d 0.53 (.99)e 0.04 0.12 0.04 0.03 OiiNSPS gas turbine . . . . . . . . . . . . . . . . . 0.3aErnissiOns from the following source: I) Compilation of Air Pollutant Emission Fsctom, Thkd EditIon, Environmental protection

Agency, August 1977; and 2) Federal Regulations 40 CFR, Part 60, defining New Source Performance Standards for Fossil-fuelad steam-electric powerplants.

hhe higher heat rate is accounted for by the efficiency loss caused by the scrubber.cAssumes high sulfur coal. Requirement for continuous control systems achieving 70 to ~ percent efficiency would reduce

SOX emissions to as low as 0.6 lb/MMBtu for low to medium sulfur coals.dAlthou@ 9ss turbine rates are quite variable, the larger GE and Westinghouse turbines (over W MW) tend to have fuei rates

between 10,500 and and 12,000 Btu/kWh, Environmental Protection Agency, Standards Support and Envkonmental ImpactsStatement for Stationary Gas Turbines, EPA-45W77-017aj September 1977, pp. 3-46.

~he first vaiues are those given in footnote al. above, the second are “typical” values for a range of turbines given in EPA,1977, op. cit. (footnote d). An examination of turbine data (Ibid., pp. 346) indicates that the larger utility turbines do not appear to emit nitrogen oxides at a lower unit rate than smaller industrial turbines. The larger emissions value is used to con-struct the emission balances.


Table B-3.—Emissions From Hot Water and Steam Systems (to provide 1,000,000 Btu of usable heat energy)

Emissions, lb/lOa Btu usable heat

Heat source Fuel input NOX Particulate CO HC SOX

Furnace and hot water heater . . . . . . . . . . . . . . . . 1,250,000 Btu 0.12 0.01 0.02 0.01 NEG. Gas0.16 0.02 0.04 0.01 0.24 Oil (.2%S)

NSPS steam boilers. . . . . . . . . . . . . . . . . . . . . . . . . 1,250,000 Btu 0.13 0.05 0.01 1.50 Coal0.37 0.13 0.04 0.01 1.00 Oil0.25 0.01 0 .02 NEG. NEG. Gas

Small (<250 x 10° Btu/hr) industrial boiler . . . . 1,250,000 Btu 0.72 0.63 0.10 0.05 3.65 Coal a

0.50 0.19 0.04 0.01 1.31 Oil (1%S)0.21 0.02 0.02 NEG. NEG. Gas

a 10 percent ash, 2 percent sulfur, 13,000 Btu/lb, 90 percent particulate control.


Appendix C

Acronyms, Abbreviations, and Glossary

ACACRSAEPAFBAFUDC

AGAAPCDAP&LAPPAbblboeBtuCAQCACARBCECCEQACFC

c oConEdCPUCCWECWIPDCDELTA

DOEEIAEIR

EISEPAEPRIERTAE/S ratioFERCFFBFGDFUA

gG WGWhHChphIEEE

I o u1PIRSITC

288

alternating currentaccelerated cost recovery systemAmerican Electric Power Service Corp.atmospheric fluidized bedallowance for funds used during

constructionAmerican Gas Associationair pollution control districtArkansas Power & Light Co,American public Power Associationbarrelbarrels of oil equivalentBritish thermal unitColorado Air Quality Control ActCalifornia Air Resources BoardCalifornia Energy CommissionCalifornia Environmental Quality ActNational Rural Utilities Cooperative

Finance Corp.carbon monoxideConsolidated Edison Co. of New YorkCalifornia Public Utilities CommissionCommonwealth Edison Co,construction work in progressdirect currentDispersed Electricity Technology

Assessment modelDepartment of EnergyEnergy Information Administrationenvironmental impact report (required

under CEQA)environmental impact statementEnvironmental Protection AgencyElectric Power Research InstituteEconomic Recovery Tax Act of 1981electricity-to-steam ratioFederal Energy Regulatory CommissionFederal Financing Bankflue gas desulfurizationPowerplant and Industrial Fuel Use Act

of 1978gramgigawattgigawatthourhydrocarbonhorsepowerhourInstitute of Electrical and Electronics

Engineersinvestor-owned utilityIllinois Power Co.Internal Revenue Serviceinvestment tax credit

JPLkvkVARkwfkwhLAERlbLRMC

; C FMFBIMMBDMMBtuMSWM WMWhNAAQSNECPA

NEESNEPA

NEPOOLNERC

NGPAN ON 02

N OX

NPDES

NSPSO&MOSHA

PFBPG&EppmPscPSD

psipsiapsigPucPUHCA

PURPA

QFREArpm

Jet Propulsion Laboratorykilovoltkilovolt-amperes-reactivekillowattkilowatthourlowest achievable emission ratepoundIongrun marginal costmetermillion cubic feetmajor fuel burning installationmillion barrels per daymillion Btumunicipal solid wastemegawattmegawatthournational ambient air quality standardsNational Energy Conservation Policy

Act of 1978New England Electric SystemNational Environmental Policy Act

of 1969New England Power PoolNorth American Electric Reliability

CouncilNatural Gas Policy Act of 1978nitrous oxidenitrogen dioxidenitrogen oxidesNational Pollutant Discharge

Elimination Systemnew source performance standardoperation and maintenanceOccupational Safety and Health

Administrationpressurized fluidized bedPacific Gas & Electric Co,parts per millionpublic service commissionprevention of significant deterioration

(of air quality)pounds per square inchpsi absolutepsi gaugepublic utilities commissionPublic Utility Holding Company Act

of 1935Public Utility Regulatory Policies Act

of 1978qualifying facilityRural Electrification Administrationrevolutions per minute

App. C—Acronymns, Abbreviations, and Glossary 289

SCFSECSERIso,Sox

SRMCSRPTCFtpyTSPTVA

g

standard cubic footSecurities and Exchange CommissionSolar Energy Research Institutesulfur dioxidesulfur oxidesshortrun marginal costSalt River Projecttrillion cubic feettons per yeartotal suspended particulateTennessee Valley Authoritymicrogram

Glossary

Availability: A measure of the frequency of scheduledoutages for generating unit (e.g., for mainte-nance).

Avoided Cost: The incremental cost to an electric util-ity of electric energy or capacity or both which,but for the purchase from a cogenerator or smallpower producer, the utility would generate itselfor purchase from another source.

Back-Up Power: Electricity sold to a cogenerator bya utility during unscheduled outages of the cogen-erator (e.g., during equipment failure).

Balance of System: The equipment required for a co-generation system excluding the prime mover(e.g., combustion chamber, environmental con-trols, fuel handling equipment).

Blowdown: The effluent from boilers and wet cool-ing systems.

Bottoming Cycle: A cogeneration system in whichhigh-temperature thermal energy is produced first,and then the waste heat is recovered and usedto generate electricity or mechanical power plusadditional, lower temperature thermal energy,

Capacity Factor: The percent of a year that a generatoractually supplies power.

Cooling Tower Drift: The discharge and dispersal ofsmall droplets of water from wet cooling towers.

Dispatching: Control by a utility from a central loca-tion of the amount of electricity generated by apowerplant and of its distribution to the point ofuse.

Diversity: The difference in electricity usage patternsamong customers.

Downwash: An aerodynamic wind action that causesstack plumes to be caught around the stack oraround neighboring buildings.

Dry Controls: Technological air pollution controls thatuse a nonliquid control medium.

Dual Fuel System: An engine or boiler that can switchback and forth from one fuel (e.g., coal) to another(e.g., oil) with no technological modification andminimal downtime.

Efficiency: A measure of the amount of energy whichis converted to useful work versus how much iswasted.Fuel Use Efficiency for a cogenerator credits the

thermal as well as electric output and is ex-pressed as the ratio of electric output plusheat recovered in Btu to fuel input in Btu.

First Law Efficiency reflects the simple percentageof fuel input energy that is actually used toproduce useful thermal and electric energy,but does not distinguish the relative value ofthe two outputs.

Second Law Efficiency recognizes that electricityis a much higher quality form of energy thanheat or steam.

Full-Load Electric Etliciency is measured when themaximum possible amount of electricity isbeing produced.

Part-Load Electric Eiliciency is measured when lessthan the maximum possible amount of elec-tricity is being produced.

Electricity-to-Steam Ratio: The proportions of elec-tric and thermal energy produced by a cogenera-tor, measured in kilowatthours per million Btu ofuseful thermal energy.

Fumigation: When plumes from either tall or shortstacks are forced to ground level by meteorologi-cal conditions.

Harmonic Distortion: The production in a power sys-tem of one or several frequencies that are multi-ples of the basic power frequency of 60 cycles persecond.

Heat Exchanger: A mechanical device that transferswaste heat from one part of a system (e.g., theturbine) to another medium (e.g., water) for proc-ess use.

Heat Rate: A measure of the amount of fuel used toproduce electric and/or thermal energy.Total Heat Rate refers to the total amount of fuel

(in Btu) required to produce 1 kilowatthourof electricity with no credit given for wasteheat use,

Incremental Heat Rate is calculated as the addi-tional (or saved) Btu to produce (or not pro-duce) the next kilowatthour of electricity.

Net F/eat Rate (also measured in Btu/kWh) creditsthe thermal output and denotes the energyrequired to produce electricity, beyond whatwould be needed to produce a given quanti-


ty of thermal energy in a separate facility (e.g.,a boiler).

induction Generator: A rotating machine in whichcurrent supplied by an external alternating cur-rent source such as the electric power grid, in-duces a voltage and current in the rotating partof the machine.

Interest Coverage Ratio: The ratio of a firm’s earningsto its current interest obligations.

Interruptible Power: Energy or capacity supplied bya utility to a cogenerator that is subject to inter-ruption by the utility under specified conditionsand is normally provided at a lower rate than non-interruptible service if it enables the utility to re-duce peakloads.

Inverter: A device for converting direct current to al-ternating current.

Load: The demand for electric or thermal energy atany particular time.Base Load is the normal, relatively constant de-

mand for energy on a given system.Peakload is the highest demand for energy from

a supplying system, measured either daily,seasonally, or annually.

Intermediate Load falls between the base andpeak.

Load Factor is the ratio of the average load overa designated time period to the peak load oc-curring during that period.

Load Cycle Pattern is the variation in demand overa specified period of time.

Maintenance Power: Energy or capacity supplied bya utility during scheduled outages of a cogenera-tor or small power producer–presumably sched-uled when the utility’s other load is low.

Market Potential: The number of instances in whicha technology will be sufficiently attractive-allthings considered—that the investment is likely tobe made.

Market-to-Book Ratio: The ratio of the market priceof a firm’s stock to its book value,

Negative Load: A technique by which utility systemcontrollers subtract the power supplied to the gridby customer-operated generating equipment fromthe overall system demand and dispatch the util-ity’s generating units to meet the remainder of thedemand, rather than dispatching customers’equipment.

Parallel Operation: The automatic export to the utilitygrid of customer-generated electricity not con-sumed by the customer’s load, such that the samecircuits can be served simultaneously by custo-mer—and utility-generated electricity.

Payout Ratio: The ratio of a firm’s earnings to its divi-dends.

Power Factor: A measure of the phase difference be-tween the voltage and current maximums on anelectrical circuit.

Prime Mover: The turbine, engine, or other sourceof mechanical power that is used to turn the rotorof a generator.

Purchase Power: Customer-generated electricity sup-plied to the grid and purchased by a utility.

Quad: One quadrillion British thermal units (Btu) (ap-proximately 500,000 barrels of oil per day for 1year, or 50,000,000 tons of coal).

Qualifying Facility: A cogenerator or small power pro-ducer that meets the requirements specified in thePublic Utility Regulatory Policies Act of 1978–inthe case of a cogenerator, one that produces elec-tricity and useful thermal energy for industrial,commercial, heating, or cooling purposes; thatmeets the operating requirements specified by theFederal Energy Regulatory Commission with re-spect to such factors as size, fuel use, and fuel effi-ciency); and that is owned by a person not primar-ily engaged in the generation or sale of electricpower (other than cogenerated power).

Rankine Cycle: The thermodynamic cycle which de-scribes the operating cycle of an actual steamengine.

Rate Base: The net valuation of utility property in serv-ice, consisting of the gross valuation minus ac-crued depreciation.

Regenerator: A device used in a turbine or engine topreheat incoming air or gas by exposing it to theheat of exhaust gases.

Relays: Devices by means of which a change of cur-rent or a variation in conditions of an electric cir-cuit causes a change in conditions of or operatesanother circuit.Over/Under Relays are used to disconnect a gen-

erator if its voltage falls outside of a certainrange.

Reliability: A measure of the frequency of scheduledand unscheduled outages of a generating unit(e.g., due to equipment failure).

Self-Excitation: The continued operation of inductiongenerators when disconnected from the outsidepower source.

Simultaneous Purchase and Sale: When a utility pur-chases all of the electricity generated by a cus-tomer at avoided cost rates and sells power to thecustomer at retail rates; in practice, no actualtransmission of power to or from the customermay take place and the amounts “purchased”

App. C—Acronymns, Abbreviations, and Glossary . 291

and “sold” are calculated from the customer’smeter.

Supplementary Power: Capacity required by a cogen-erator or small power producer in addition to itsown.

Switchgear: All of the necessary relays, wiring, andswitches that are used in interconnection equip-ment.

Synchronous Generator: A prime mover (e.g., tur-bine, engine) in which the rotor current comesfrom a separate direct current source on the gen-erator.

Synthesis Gas: A synthetic gas created from a solidor liquid fuel with an energy content of 300 to 400Btu/SCF.

System Stability: The ability of all generators supply-ing power to a utility system to stay synchronizedafter a disturbance (e.g., a fault on part of thepower system).

Technical Potential: The number of instances inwhich a technology is technically suitable or ap-propriate.

Telemetry Equipment: Used in dispatching to transmitsignals from a control center to electrical equip-

ment (e.g. a generator) in the field in order to re-motely operate that equipment.

Topping Cycle: A cogenerator in which the electricor mechanical power is produced first, and thenthe thermal energy exhausted from power pro-duction is captured and used.

Transformer: A device for increasing or decreasingthe voltage of an alternating electric current.

Dedicated Distribution Transformers: These unitsconnect a single large utility customer directly toa higher voltage distribution line, substation, ortransmission network in order to confine voltageflicker problems to the customer’s own system.

Urban Meteorology: The conditions surrounding ur-ban buildings that alter normal dispersion of emis-sions.

Voltage Flicker: Very brief (less than 1 minute)changes power system voltages.

Waste Heat: Thermal energy that is exhausted ratherthan being captured and used.

Wet Controls: Technological air pollution controlsthat operate through the injection of water orsome other liquid.

Index

Index

Aerospace Research Corp., 145, 207air-conditioning demand, 54air pollution control districts (APCDs), 102, 103, 104,

243, 244, 245Air Pollution Emission Notice (APEN), 101, 102, 244, 245Alabama, 41, 86, 177, 182Alaska, 57, 182Alaska Power Administration, 57American Electric Power Service Corp. (AEP), 80, 83,

84, 85, 178American Gas Association (AGA), 189, 190, 196American Public Power Association (APPA), 150, 159anaerobic digestion, 13, 215Arizona, 41, 182Arkansas, 40, 41, 57, 86, 177, 182Arkansas Power & Light Co. (AP&L), 109, 183, 258, 274avoided cost, 39, 40, 41, 79, 80, 81, 82, 98, 99

Babcock & Wilcox, Ltd., 178Bonneville Power Administration, 56Bureau of Land Management (BLM), 243, 244Bureau of Reclamation, 56, 57

California, 12, 32, 33, 40, 41, 81, 86, 90-94, 95, 96, 97,101, 102, 103, 104, 111, 174, 182, 189, 190, 191,205, 214, 242, 243, 244, 245, 256, 257

California Air Resources Board (CARB), 102, 104, 235, 244California Energy Commission (CEC), 90, 91, 104California Office of Permit Assistance, 102, 104California Public Utilities Commission (CPUC, 90, 91,

92, 93, 94, 104, 154, 156, 256California State Clearing House, 103California Water Resources Control Board, 102capital requirements, 33, 42, 65, 106carbon monoxide (CO), 223, 224, 230, 237Celanese Chemical Co., Pampa, Tex., 172, 173coal, 144cogeneration technologies

air quality considerations, 17, 21, 43, 44, 70, 100,101, 102, 103, 221, 222-246, 276-277

bottoming cycles, 6,8,9,25,27,29,30,33, 77, 122, 175capacity, 199capital requirements, 33, 42, 65, 106centralization and decentralization, 261choice of equipment, considerations of, 8classification, 6closed-cycle gas turbine, 6, 8, 9, 30, 120, 121, 122,

127-129, 239combined gas turbine/steam turbine, 8, 9, 28, 120,

121, 122, 129-131, 235competition with alternate systems, 31-32, 35construction labor requirements, 42definition, 25diesel, 8, 9, 28, 44, 77, 120, 121, 122, 131-133, 225,

230, 237, 238,digesters, 13, 215economic considerations, 19, 27, 38, 40, 67, 181,

246-259, 270-273efficiency and operating standards, 77

electric storage, 161-163electricity-to-steam (E/S) ratio, 8, 11, 21, 28, 117,

120, 124environmental considerations, 16-17, 21, 35, 43-44,

70, 77, 100, 101, 102, 103, 221, 222-246environmental permit enforcement, 242-246equipment needed, consideration of, 8Federal and State regulation, 76-104final environmental impact statement (FEIS), 78financing and ownership, 104-112, 182-183fluidized bed combustion, 31, 32, 35, 142-143, 177, 239four general questions, 5fuel cell, 6, 8, 9, 30, 120, 121, 122, 137-139fuel use, 8, 10, 11, 13, 15, 19, 25, 27, 28, 29, 31, 33,

34, 43, 44, 71, 72, 77, 99, 123, 130, 142-146, 171,172, 173, 174, 175, 182, 194-196, 206, 213, 223,238, 258, 259

gasifiers, 13, 21, 31, 32, 143-144, 175-177, 214, 258grain drying, 211impacts of, 15-18, 40-42, 43-44incentives, 10, 19, 20, 35, 38, 39, 40, 41, 67, 107in commercial buildings, 12, 32, 34, 189-210industrial applications, 171-178industrial opportunities, 32-34, 171-188investment competition, 10joint ventures, 39labor requirements, 17, 42, 251, 253market potential, 10, 38, 184-188, 248, 272municipal solar utility (MSU), 111municipal solid waste (MSW), 110, 144, 241, 257obligation to purchase power, 78oil savings, 18-19, 25, 267-270old and proven technology, 3open-cycle gas turbine, 8, 9, 28, 30, 120, 121, 122,

124, 125, 145operation and maintenance (O&M) costs, 9, 17, 18,

42, 121, 124, 127, 132, 133, 136, 139, 142, 250,251, 252, 254

opportunities, 11-13, 34, 198-208policy considerations, summary of, 18, 279potential for, 10, 29-31, 178-184, 211previous studies, 189-190principal technical advantage, 6qualifying facilities, 78-85Rankine cycle, 6, 8, 9, 28, 29, 30, 32, 117, 120, 121,

122, 133-137regulation of fuel use, 99relative efficiencies (fig. 2), 7research and development (R&D), 21, 29, 31, 277resurgence of interest, 3, 25retrofits, 33, 202-205rural opportunities, 13, 210-216steam turbine, 8, 9, 10, 27, 28, 32, 120, 121, 122,

123, 124, 171, 174Stirling engine, 6, 8, 9, 30, 31, 120, 121, 139-142summary of, 8, 120tax credit and incentives, 19, 20, 34, 38, 67, 68, 69,

105, 106, 109, 183, 272

295

296 Industrial and Commercial @generation

thermal storage, 159-161thermodynamic efficiency of, 118-119topping cycles, 6, 9, 25, 26, 29, 30, 31, 77, 122use of thermal energy, 25, 31, 32, 33

Colorado, 41, 101, 102, 103, 104, 182, 242, 243, 244, 245Colorado Department of Health, 242, 243Columbia River Basin, 56Commonwealth Edison (CWE), 94-95, 256, 257comparison of energy demand projections (table 8), 50ConEd (see Consolidated Edison Co.)Congress

House of RepresentativesBanking, Finance, and Urban Affairs Committee, 5Energy and Commerce Committee, 5Science and Technology Committee, 5

SenateEnergy and Natural Resources Committee, 5

Connecticut, 40, 41, 86, 98, 182conservation, 33, 35, 50, 70considerations in determining avoided costs under

PURPA, by State (table 4), 41Consolidated Edison Co, (ConEd), 93, 94, 189, 190,

231, 232, 233, 256Curtiss-Wright Corp., 178

Delaware, 40, 41, 182DELTA (see Dispersed Electricity Technology Assessment

model)Department of Commerce, 188Department of Energy (DOE), 99, 159, 178, 185, 187

Secretary of, 71Electrical Energy Systems Division, 156, 276

Department of Housing and Urban Development(HUD), 105

Dispersed Electricity Technology Assessment (DELTA)model, 190, 191, 192, 193, 196, 197, 198, 201,209, 283-285

district heating, 163-165District of Columbia, 41, 182Dow Chemical Co., 185, 186

economic impact, 40-42Economic Regulatory Administration, 269Edison Electric Institute, 50effects on fuel use, 15electricity

baseload, 60costs, 63, 73, 79, 80, 81, 82, 83, 85, 96, 97, 98, 214distribution system (fig. 11), 62generating, historical overview, 4harmonic distortion, 150peakloads, 60power demand, 52, 53, 54power factor correction, 147power quality, 146power system statistics (table 10), 55rates, 62rates for power purchased from QFs by State-

regulated utilities (table 19), 86-89storage, 161-163system reliability, 61

U.S. generating capacity, 60, 61voltage regulation, 148

Electric Power Research Institute (EPRI), 150, 154, 156,159, 177, 276

electric reliability councils, 57Electric Reliability Council of Texas, 198electric utility systems, 55, 56, 59, 61

accelerated cost recovery system (ACRS), 67, 68capital recovery factor, 106cooperative utilities, 56, 66, 69, 111current status, 72-74economic and regulatory aspects, 62-66

State regulations, 62, 66, 70Federal regulations, 63, 67, 70

Federal jurisdiction, 67financing, 64-69, 104future options, 74-75generation and transmission co-ops (G&Ts), 56, 64, 66industrial development bonds (IDBs), 110investment tax credit (ITC), 67, 68, 69, 109investor-owned utilities (IOUS), 55, 56, 57, 61, 62, 64,

65, 67, 69, 73, 74, 104, 106, 108, 111joint action agency, 57municipal, 61, 64, 65, 67, 109planning and regulation of, 254-257power pools, 57private utilities, 55, 65, 106public health and welfare regulations, 70publicly owned utilities, 56, 57, 61, 65, 69PURPA requirements, 39-40rate schedule, 63regulation of fuel use, 71revenue requirement, 63rural co-ops, 56, 61, 111service regulation, 69taxation, 67, 106

Energy Information Administration (EIA), 50,51,53,54, 196environmental impact report (EIR), 103Environmental Protection Agency (EPA), 100, 225, 230,

233, 236, 238, 242ERTA (see legislation, Economic Recovery Tax Act of 1981)ethanol, 211Exxon, 50, 173, 174, 196

Federal Energy Regulatory Commission (FERC), 19, 20,37, 39, 64, 67, 69, 70, 76, 77, 78, 79, 80, 81, 82,83, 84, 85, 86, 90, 91, 92, 93, 97, 98, 119, 146,181, 182, 184, 189, 255, 267, 268, 270, 271, 273,275, 276

Federal Financing Bank, 66, 112Federal new source performance standards (NSPSS), 225Federal Power Commission (FPC), 57, 64, 69Federal power marketing agencies, 56, 57FERC (see Federal Energy Regulatory Commission)Fish and Wildlife Service, Department of the Interior, 71Florida, 40, 41, 182

General Public Utilities, 74Georgetown University, Washington, D. C., 239Georgia, 41, 182

Index . 297

Georgia Power, 151German Babcock Co., 178Governor’s Task Force on Cogeneration, State of

California, 104Great Britain, 143, 145, 178gross national product (GNP), 49, 50Gulf States Utility Co., Baton Rouge, La., 173 174, 188

Holly Sugar Corp., Brawley, Calif., 174, 175

Idaho, 41, 86, 172, 182Illinois, 41, 86, 90, 94-95, 182Illinois Commerce Commission (ICC), 94, 95Illinois Power (1P), 94, 95implementation of section 210 of PURPA, 86-98

California, 90Colorado, 101Illinois, 94-95Massachusetts, 97New England, 96-98New Hampshire, 96, 97Vermont, 97Indiana, 41, 87, 182

installed industrial capacitychemical industry, 11, 172, 174, 179food processing industry, 12, 33, 174petroleum refining, 11, 12, 173, 179pulp and paper industry, 11, 13, 172, 178steel industry, 11, 179

Institute of Electrical and Electronics Engineers (IEEE),156, 159, 276

interconnection, 13, 14, 20, 35, 36, 37, 70, 76, 84, 85,146-159, 275-276

cost, 14, 37, 85, 157, 158generation dispatch, 152guidelines, 155liability, 154metering, 151power factor correction, 147power quality, 146power regulation problems, 151quality of equipment, 154regulation, 76safety of workers, 14, 36, 153system stability, 152technical aspects, 36voltage regulations, 148

Iowa, 41, 182

Jersey City Total Energy Demonstration Project, 241Jet Propulsion Laboratory (JPL), 156, 276Journal of the Air Pollution Control Association (JAPCA),

236, 237

Kansas, 41, 87, 182Kentucky, 41, 182Kern County, Calif., 91, 180

legislationAdministrative Procedure Act, 84, 85, 275Atomic Energy Act, 70California Environmental Quality Act (CEQA),

103, 104Clean Air Act, 18, 21, 70, 100, 101, 102, 225, 239,

240, 242, 244, 245, 267, 276, 277Clean Water Act, 70, 101, 102, 103, 244Coastal Zone Management Act, 71Colorado Air Quality Control Act (CAQCA), 101Economic Recovery Tax Act of 1981 (ERTA), 68, 104,

105, 106, 107, 188, 259, 267, 273Endangered Species Act of 1973, 70Energy Security Act of 1980, 104, 105, 275Energy Supply and Environmental Coordination Act

of 1974, 71Energy Tax Act of 1978, 68, 267, 273Federal Power Act, 20, 37, 63, 64, 67, 69, 76, 84, 85,

97, 146, 275, 276Fish and Wildlife Coordination Act of 1970, 71FUA (see Powerplant and Industrial Fuel Use Act

of 1978)Internal Revenue Code, 68, 105, 109National Ambient Air Quality Standards (NAAQS),

100, 101, 225, 236, 237National Electrical Code, 156National Energy Act of 1978, 5, 71, 76, 104, 268National Energy Conservation Policy Act of 1978

(NECPA), 104, 105, 275National Environmental Policy Act of 1969 (NEPA),

70, 103, 104National Historic Preservation Act of 1970, 70National Gas Policy Act (NGPA), 34, 71, 72, 78, 85,

99, 100New Hampshire Limited Electrical Energy Producers

Act, 97Occupational Safety and Health Act (OSHA), 70,

101, 153Powerplant and Industrial Fuel Use Act of 1978

(FUA), 18, 19, 27, 34, 71, 72, 78, 85, 99, 100, 102,184, 206, 267, 268, 269, 270

Public Utility Holding Company Act of 1935(PUHCA), 67, 76, 85

Public Utility Regulatory Policies Act of 1978(PURPA), 10, 13, 15, 16, 18, 19, 20, 21, 34, 37, 38,39, 40, 41, 51, 64, 70, 72, 76, 77, 78, 80, 81, 83,84, 85, 86, 90, 92, 93, 95, 96, 97, 98, 99, 100, 102,104, 105, 106, 107, 108, 109, 119, 146, 147, 154,183, 184, 185, 186, 189, 192, 204, 205, 206, 232,255, 256, 257, 262, 267, 268, 269, 270, 271, 273,274, 275, 276

Reclamation Act of 1906, 56Resource Conservation and Recovery Act of 1976, 70Securities and Exchange Commission Act of 1935, 67Windfall Profits Tax Act, 104, 110, 267

Louisiana, 40, 41, 171, 173, 182Lovins, Amory, 260lowest achievable emission rate (LAER), 101, 103, 240

latent-heat storage, 159


Maine, 41, 182Maryland, 41, 182Massachusetts, 40, 41, 87, 96, 97, 182Massachusetts Department of Public Utilities (DPU), 97methanol, 239Michigan, 41, 87, 182Michigan State University, 152Mid-America Interpool Network, 198Minnesota, 41, 57, 182Mississippi, 40, 41, 171, 182Missouri, 41, 57, 96, 182Missouri Basin Municipal Power Agency, 57Montana, 41, 88, 182Municipal Electric Authority of Georgia, 57

National Academy of Sciences, 237national energy context, 49-54National Energy Policy Plan, projection, 50National Pollutant Discharge Elimination System

(NPDES), 101, 102, 103, 243National Register, 71National Rural Electric Cooperative Association, 151National Rural Utilities Cooperative Finance Corp.

(CFC), 66Natural Resources Defense Council, 90Nebraska, 41, 56, 62, 88, 182NEPA (see legislation, National Environmental Act

of 1969)Netherlands, Rotterdam, 178Nevada, 41, 88, 182New England Electric System (NEES), 97New England Power, 97, 98New England Power Pool (NEPOOL), 96, 97, 98New Hampshire, 40, 41, 88, 96, 97, 98, 182New Jersey, 40, 41, 88, 178, 179, 182, 187, 189New Mexico, 41, 182new source performance standards (NSPSs), 100New York, 40, 41, 56, 88, 93, 101, 179, 182, 187,

189, 231New York Public Service Commission (NYPSC), 94, 154,

231, 256NGPA (see legislation, Natural Gas Policy Act

of 1978)nitrogen oxide (NOX), 17, 44, 100, 102, 103, 223, 224,

225, 228, 230, 231, 232, 233, 235, 237, 238North American Electric Reliability Council (NERC), 52,

57, 58, 59, 198North Carolina, 41, 57, 88, 182North Dakota, 41, 88, 182Northeast Power Coordinating Council, 198

Occupational Safety and Health Administration(OSHA), 153

Office of Technology Assessment (OTA), 5, 6, 12, 13,15, 17, 18, 21, 35, 37, 40, 42, 51, 157, 163, 175,183, 189, 190, 192, 193, 194, 196, 197, 198, 199,201, 205, 206, 209, 214, 230, 233, 242, 248, 249,250, 257, 270, 276, 277

Ohio, 41, 178, 182Oklahoma, 41, 57, 89, 182Oregon, 41, 89, 182ownership of cogenerators, 16, 38-39, 77, 106-112

Pacific Gas & Electric (PG&E), 90, 91, 95, 96, 256, 257Pennsylvania, 41, 171, 182, 189Philips, N. V., Einhoven, Netherlands, 178platinum, 138Potlatch Corp., Lewiston, Idaho, 172, 173public service commissions (PSCs), 62, 63, 64, 66,

69, 85public utility commissions (PUCs), 86, 96, 97PURPA (see legislation, Public Utility Regulatory Policies

Act of 1978)

qualifying facilities, 78-98

Radian Corp., 233references, 21, 44-45, 112-114, 165-167, 216-217,

263-264, 278Resource Planning Associates, 185Rhode island, 40, 41, 89, 182Riverside Cement Co., Oro Grande, Calif., 175Roosevelt, Franklin, 262Ruhr Chimie, Oberhausen, Germany, 177Rural Electrification Administration (REA), 66, 111,

112, 150

Salt River Project (SRP), 148, 149, 150, 151Seabrook 1, 97Security and Exchange Commission (SEC), 67Shell Oil Co., ,178socioeconomic impacts, 17-18Solar Energy and Energy Conservation Bank, 105Solar Energy Research Institute (SERI), 52, 53, 54,

186, 187South Carolina, 41, 89, 182South Dakota, 41, 182Southeastern Power Administration, 57Southern California Edison, 148, 151, 153, 154, 155,

156, 177, 207, 273Southern California Gas Co., 108Southwestern Power Administration, 56Southwestern Public Service Co., 173SRI International, 186Stal-Laval Turbin AB, Sweden, 178Standard and Poor’s, 94sulfur dioxide (SO2), 101, 102, 103, 223, 224, 225, 230,

231, 237, 238Sweden, 178

Tennessee, 41, 182Tennessee Valley Authority (TVA), 56, 143, 177Texaco, 177Texas, 40, 41, 57, 172, 174, 182Thermo Electron Corp., 178, 185, 186Three Mile Island (TMl), 74

Index . 299

Union Carbide Corp., Texas City, Tex., 174U.S. Army Corps of Engineers, 56, 57, 71, 243U.S. Court of Appeals, 20, 37, 76, 78, 81, 82, 83, 84,

85, 90, 93, 105, 268, 271, 275U.S. energy demand, 1980, 49-54

electricity, 52, 53natural gas, 51, 52oil, 51, 52thermal, 53, 54

U.S. Forest Service, 243, 244U.S. Supreme Court, 76, 82, 85, 105, 271, 272Urban Development Action Grant (UDAG), 110urban meteorology, 44, 228Utah, 41, 89, 182utility obligations to qualifying facilities

to interconnect, 84to operate in parallel, 84to purchase, 78-82

to sell, 83simultaneous purchase and sale, 83

utility ownership, 20, 35, 38, 39, 55, 56, 57, 61, 64, 65,104, 106-111, 273-275

Vermont, 41, 89, 96, 97, 98, 182Vermont Public Service Board, 97Virginia, 41, 145, 182

Washington, 41, 182Water quality, 17, 241Western Area Power Administration, 57West Virginia, 41, 182Williams, Robert H., 185, 186, 187Wisconsin, 41, 89, 182Wood, 144, 171, 213Wyoming, 41, 89, 172, 182