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 for

an evaluation of the economic, regulatory, and institutional barriers to the development of cogeneration systems by utilities, industries, and businesses. This report complements a forthcoming OTA analysis of Industrial Energy Use in evaluating the potential for onsite energy production in industry. The findings also will serve as part of the

material to be used in future OTA assessments of other electricity-generating technologies.

The report describes the available and promising future cogeneration technologies,

including their likely costs and operating characteristics, and reviews the potential applications for these technologies in industry, commercial buildings, and rural/agricultural

areas. It also describes the technical requirements for interconnecting cogeneration

systems with the utility grid, and discusses advanced combustion and conversion technologies (fluidized bed and gasification systems) that will enable cogenerators to use

fuels other than oil and natural gas. The analysis of cogeneration’s market potential

focuses on the competitiveness of cogeneration when compared to investments in conservation or in conventional separate thermal and electric energy systems (e.g., an industrial boiler and a central station utility powerplant). In addition, the report examines

the possible effects of the widespread use of cogeneration systems on utilities and their

ratepayers, and on air quality. Several options for changes in Federal policy in order

to enhance cogeneration’s market potential, to optimize its ability to displace oil and

natural gas, and to mitigate its possible adverse economic and environmental impacts

are discussed.

We are grateful for the assistance of the project advisory panel and the advice of

numerous individuals in utilities, industry, State governments, trade associations, and

universities. Also the contributions of several contractors, who performed background

analyses, are gratefully acknowledged.

. Ill
Industrial and Commercial Cogeneration

James J. Stukel, Chairman

University of Illinois

Roger Blobaum

Roger Blobaum & Associates

William H. Corkran

American Public Power Association

Claire T. Dedrick*

California Land Commission

Steven Ferrey

National Consumer Law Center

Todd La Porte

University of California at Berkeley

Evelyn Murphy

The Evelyn Murphy Committee

Advisory PaneI

Theodore J. Nagel

American Electric Power Service Corp.

Thomas W. Reddoch

University of Tennessee

Bertram Schwartz

Consolidated Edison Co. of New York

Harry M. Trebing

Michigan State University

Thomas F. Widmer

Thermo Electron Corp.

Robert H. Williams

Princeton 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, OTA

Energy, 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 Casten

Decision Focus, Inc.

Energy and Resource Consultants, Inc.

ICF, inc.

Edward Kahn

L. 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 Abbott

Aerospace Corp.

Weible Alley

Arkansas Power & Light Co.

Douglas Bell

U.S. Environmental Protection Agency

Ben Blaney

U.S. Environmental Protection Agency

Merrilee Bonney

U.S. Environmental Protection Agency

Josh Bowen

U.S. Environmental Protection Agency

Joel P. Brainerd

New York Public Service Commission

John Dadiani

TRW Corp.

Douglas C. Dawson

Southern California Edison Co.

Fred 1. Denny

Edison Electric Institute

Richard Donovan

National Aeronautics and Space Administration

Fred Dryer

Princeton University

Lowell J. Endahl

National Rural Electric Cooperative Association

Peter Freudenthal

Consolidated Edison Co. of New York

Howard Geller

American Council for an Energy Efficient Economy

Marty Gordon

Edison Electric Institute

Tom Grahame

U.S. Department of Energy

J. Steven Herod

U.S. Department of Energy

Ronald Johnson

Aerospace Corp.

R. Eric Leber

American Public Power Association

Tom Lepley

Arizona Public Service Co.

Elliot Levine

Argonne National Laboratory

Glenn Lovin

International Cogeneration Society

Frederic March

Consultant

Tom Marciniak

Argonne National Laboratory

Alan S. Miller

Natural Resources Defense Council

Ralph C. Mitchell, Ill

Arkansas Power & Light Co.

David Morris

Institute for Local Self-Reliance

Dale Pahl

U.S. Environmental Protection Agency

Robert Podlasek

Illinois Commerce Commission

Wilson Pritchett

National Rural Electric Cooperative Association

Arnold Rosenthal

Consolidated Edison Co. of New York

Blair A. Ross

American Electric Power Service Corp.

Barry Saitman

California Energy Commission

Fred Sissine

Congressional Research Service

Elinor Schwartz

State of California, Washington Office

Walt Stephenson

U.S. Environmental Protection Agency

John Williams

U.S. Department of Energy

L. J. Williams

Electric Power Research Institute

R. L. Williams

EBASCO Services Inc.

Mike Zimmer

Cogeneration 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

Appendixes

A. 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

Page

Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3

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

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

Cogeneration Opportunities .. .. ... ... . . . . . . . . . . . . . . . . . . . . . . . . . . 11

industrial Cogeneration . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . 11

Commercial Building Cogeneration . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12

Rural Cogeneration Opportunities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13

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

impacts of Cogeneration . . . . . . . . . . . . . . . . . . . . . . . .. .. .. .. .. ... ... ..... . . . . . 15

Effects on Fuel Use..... . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15

impacts on Utility Planning and Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15

Environmental Impacts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16

Socioeconomic Impacts. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17

Policy Considerations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18

Oil Savings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18

Economic incentives for Cogeneration . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19

Utility Ownership . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20

Interconnection Requirements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20

Air Quality Considerations. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21

Research and Development. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21

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

Tables

Table No. Page

l. Summary of Cogeneration Technologies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8

2. lnstalled lndustriaI Cogeneration Capacity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11

Figures

Figure No. Page

I. Historical Overview of Electricity-Generating Capacity, Consumption, and

Price, 1902-80 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4

2. Conventional Electrica! and Process Steam Systems Compared With a

Cogeneration System . . . . . . .. .. .. .. .. .. ... ... ......O . . . . . . . . . . . . . . . . . . . . . 7
Chapter 1

Overview

INTRODUCTION

A major focus of the current energy debate is

how to meet the future demand for electricity

while reducing the Nation’s dependence on imported oil. Conservation in buildings and industry, and conversion of utility central station

capacity to alternate fuels will play a major role

in reducing oil use in these sectors. But costeffective conservation measures can only go so

far, and the industrial and commercial sectors

ultimately will have to seek alternative sources

of energy. Moreover, electric utilities may face

financial, environmental, or other constraints on

the conversion of their existing capacity to fuels

other than oil, or on the construction of new alternate-fueled capacity.

A wide range of alternate fuels and conversion

technologies have been proposed for the industrial, commercial, and electric utility sectors. One

of the most promising commercially available

technologies is cogeneration. Cogeneration systems produce both electrical (or mechanical)

energy and thermal energy from the same primary energy source. Cogeneration systems

recapture otherwise wasted thermal energy, usually from a heat engine producing electric power

(i.e., a steam or combustion turbine or diesel engine), and use it for applications such as space

conditioning, industrial process needs, or water

heating, or use it as an energy source for another

system component. This “cascading” of energy

use is what distinguishes cogeneration systems

from conventional separate electric and thermal

energy systems (e.g., a powerplant and a lowpressure boiler), and from simple heat recovery

strategies. Thus, conventional energy systems

supply either electricity or thermal energy while

a cogeneration system produces both. The automobile engine is a familiar cogeneration system

as it provides mechanical shaft power to move

the car, produces electric power with the alternator to run the electrical system, and uses the

engine’s otherwise wasted heat to provide comfort conditioning in the winter.

Cogeneration is an old and proven practice.

Between the late 1880’s and early 1900’s, oil- and

gas-fired cogeneration technologies were increasingly used throughout Europe and the United

States. In 1900, over 59 percent of total U.S. electric generating capacity was located at industrial

sites (not necessarily cogenerators) (see fig. 1).

Because electric utility service during this period

was limited in availability, unreliable, unregulated, and usually expensive, this onsite generation provided a cheaper and more reliable source

of power. However, as the demand for electricity increased rapidly and reliable electric service

was extended to more and more areas in the early

1900’s, as the price of utility-generated electricity declined, and as electric generation became

a regulated activity, industry gradually began to

shift away from generating electric energy onsite.

By 1950, onsite industrial generating capacity accounted for only about 17 percent of total U.S.

capacity, and by 1980 this figure had declined

to about 3 percent. At the same time, cogeneration’s technical potential (the number of sites with

a thermal load suitable for cogeneration) has

been increasing steadily.

There has been a resurgence of interest in recent years in cogeneration for industrial sites,

commercial buildings, and rural applications. A

cogenerator could provide enough thermal energy to meet many types of industrial process

needs, or to supply space heating and cooling

and water heating for a variety of different commercial applications, while supplying significant

amounts of electricity to the utility grid. Because

cogenerators produce two forms of energy in one

process, they will provide substantial energy savings relative to conventional separate electric and

thermal energy technologies. Because cogenerators can be built in small unit size (less than 1

megawatt (MW)) and at relatively low capital cost,

they could alleviate many of the current problems faced by electric utilities, including the difficulty 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 generation

becomes a regulated

industry

106

105

104

103

SOURCE: Office of Technology Assessment from Edison Electric Institute, Statistical Yearbook of the Electric Utility

Industry: 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 with

financing large powerplants. The small size of

cogeneration systems also may be attractive as

a form of insurance against short-term fluctuations

in electricity demand growth (in lieu of the costly overbuilding of central station powerplants).

However, if cogenerators are not designed and

sited carefully, and if their operation is not coordinated with that of the electric utilities, they also

have 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 interest

in decentralized energy systems and in cogeneration. Cogeneration is a major issue in the National

Energy Act of 1978, parts of which were designed

to remove existing regulatory and institutional ob

stacles to cogeneration and to provide economic

incentives for its implementation. In addition, the

House Energy and Commerce Committee, the

House Science and Technology Committee, and

the Senate Energy and Natural Resources Committee have held hearings on cogeneration, and

several committees in both Houses of Congress

have held hearings on the general concept of

decentralized energy systems.

The House Committee on Banking, Finance,

and Urban Affairs requested that OTA undertake

a study of small electricity-generating equipment.

The request expressed concern that “considerations of energy policy have not taken adequately

into account the possibilities for decentralizing

part of America’s electrical generating capabilities

by distributing them within urban and other communities.” Citing the financial problems currently

faced by electric utilities and the availability of

a wide range of new generating technologies, the

committee requested “a careful examination of

the role that small generating equipment could

play and the economic, environmental, social,

political, and institutional prerequisites and implications of greater utilization of such equipmerit. ” In 1981, the House Energy and Commerce, and Science and Technology Committees

wrote letters to OTA reaffirming congressional interest in a study that would provide a better

understanding of the economic, regulatory, and

institutional barriers to the development of cogeneration and small power production by utilities,

industries, and businesses.

In response to these requests, OTA undertook

this assessment of cogeneration technologies. The

assessment was designed to answer four general

questions:

1.

2.

3.

4.

In

Under what circumstances are cogeneration

technologies likely to be economically attractive and on what scale, and what is the

potential for new technologies in the future?

How much electric power is economically

or technically feasible for cogeneration to

contribute to the Nation’s energy supply?

What are the economic, environmental, social, and institutional impacts of cogeneration?

What policy measures would accelerate or

retard the use of cogeneration systems?

order to answer these questions, this report

reviews the features of the Nation’s energy picture (e.g., supply of and demand for fuels and

electricity) and of the electric power industry that

may affect decisions to invest in cogeneration

systems; describes the major technologies suitable for cogeneration applications; analyzes the

impacts of industrial and commercial cogeneration on utility planning and operations, on fuel

use, and on environmental quality; and discusses

the policy issues arising from existing legislation

or regulations related to cogeneration. Because

electric utilities are most likely to be affected

strongly by onsite generation, the technical, institutional, and policy analyses focus on the role

of utilities in such generation, and its effects on

their future planning and operations.

The main focus of the report is the use of cogeneration equipment in the industrial and commercial sectors; promising rural applications are

discussed briefly. The cogeneration technologies

addressed in detail include steam and combustion turbine topping cycle equipment as well as

combined-cycle systems, diesel topping cycles,

Rankine bottoming cycles, Stirling engines, and

fuel cells. Other small power production technologies (wind, solar electric, small-scale hydro)

originally were included in the scope of this

study. However, OTA found that reliable data on
6 ● Industrial and Commercial Cogeneration

these technologies’ potential to produce electricity are not yet available. Moreover, the inclusion

of four separate types of technologies made the

scope of the study too broad. Therefore, analysis of these small power production systems has

been reserved for a subsequent OTA assessment

of electricity supply and demand in general.

Volume I of this report is organized as follows:

●

●

●

chapter 2 highlights the central issues surrounding cogeneration and summarizes

OTA’S findings on those issues;

chapter 3 reviews the context in which

cogenerators will operate, including the national energy situation, current electric utility

operations, and the regulation and financing of cogeneration systems;

chapter 4 presents an overview of the cogeneration technologies, including their operating and fuel use characteristics, projected

costs, and requirements for interconnection

with the utility grid;

chapters analyzes the opportunities for cogeneration in industry, commercial buildings, and rural areas;

chapter 6 assesses the impacts of cogeneration on electric utilities’ planning and operations and on the environment, as well as on

general economic and institutional factors

such as capital requirements, employment,

and the decentralization of energy supply;

and

chapter 7 discusses policy considerations for

the use of cogeneration technologies.

The appendices to volume I include a description of the model used to analyze commercial

cogeneration (ch. 5) and of the methods used to

calculate emissions balances for the air quality

analysis in chapter 6, as well as a glossary of terms

and a list of abbreviations used in the report.

Selected reports by contractors in support of

OTA’S assessment are presented in volume Il.

COGENERATION TECHNOLOGIES

The principal technical advantage of cogeneration systems is their ability to improve the

efficiency of fuel use. A cogeneration facility, in

producing both electric and thermal energy, usually consumes more fuel than is required to produce either form of energy alone. However, the

total fuel required to produce both electric and

thermal energy in a cogeneration system is less

than the total fuel required to produce the same

amount of power and heat in separate systems.

Relative efficiencies are portrayed graphically in

figure 2 for an oil-fired steam electric plant, an

oil burning process steam system, and an oil-fired

steam turbine cogenerator with a high-pressure

boiler. It should be noted, that despite its relative

efficiency in fuel use, the fuel saved in cogeneration will not always be oil. Only if a cogenerator

replaces separate technologies that burn oil and

would continue to do so for most of the useful

life of the cogenerator, will the fuel saved with

cogeneration be oil.

A wide range of technologies can be used to

cogenerate electric and thermal energy. Commercially available technologies are steam turbines, open-cycle combustion turbines, combined-cycle systems, diesels, and steam Rankine

bottoming cycles. Advanced technologies that

may become commercially available within the

nexts to 1s years include closed-cycle combustion turbines, organic Rankine bottoming cycles,

fuel cells, and Stirling engines. Solar cogenerators

(e.g., the therm ionic topping system) also are under development, but are not discussed in this

report.

Cogeneration technologies are classified either

as “topping” or “bottoming” systems, depending

on whether electric or thermal energy is produced first. in a topping system–the most common cogeneration mode—electricity is produced

first, and then the remaining thermal energy is

used for such purposes as industrial processes,

space heating and cooling, water heating, or even

the production of more electricity. Topping systems would form the basis for residential/commercial, rural/agricultural, and most industrial

cogeneration 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

Water ~ High-pressure boiler

Mechanical Inefficiency Generator Inefficiency

Electricity

Generator Turbine

(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 A

and 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. Heat

is extracted from the hot exhaust waste stream ●

and transferred to a fluid (generally through a

waste heat recovery boiler), which is then vaporized by the waste heat to drive a turbine that pro- ●

duces electricity. The primary advantage of bottoming cycles is that they produce electricity with

waste heat (i.e., no fuel is consumed beyond that

needed in the industrial process), but their use ●

is limited to industries that need high-temperature

heat.

Cogeneration technologies vary widely in their ●

cost, energy output, efficiency, and other characteristics (see table 1). The choice of cogeneration equipment for a particular application will

depend on a number of considerations, includ-

●

Electric energy needs: How much electricity is needed onsite and how much is to be

distributed to the grid?

Operating characteristics: Will the cogenerator be operating all the time or only at certain times of the day or year?

Physical site /imitations: How much space

is available for the cogenerator and its auxiliary equipment (e.g., fuel handling and

storage)?

Air quality considerations: What are the

emission limitations onsite and can they be

accommodated through pollution controls

and stack height?

Fuel availabillty: Which fuels are readily

available, and will the cogenerator displace

oil or some other fuel?

Energy costs: What are the relative prices of

fuels for cogeneration (primarily natural gas

in the near term, but also coal, biomass, and

Thermal energy needs: How much heat/ synthetic fuels) and of retail electricity?

steam is needed onsite and at what temper- ●

ature and pressure?

Capital availability and costs: Will the

cogenerator be able to find attractive financTable I.—Summary of Cogeneration Technologies

Part-load

Full-load (at 50% load)

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

Technology Unit size

steam ratio

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

A. Steam turbine

topping

500 kW-100 MW Natural gas, distillate,

residual, coal, wood,

solid waste/coal- or biomass-derived gases and

liquids.

Naturai gas, distillate,

treatad residual/coal- or

biomass-derived gases

and liquids.

Externally fired—can use

most fuels.

Naturai gas, distillate,

residual/coal- or biomassderived gases and liquids,

Natural gas, distillate,

treated residual/coal- or

biomass-derived gases

and liquids, slurry or

powdered 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

240-300

340-500

B. Open-cycle gas

turbine topping

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

C. Ciosed-cycle gas

turbine topping

D. Combined gas

turbine/steem

turbine 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 cycle

bottoming:

Steam 500 kW-10 MW Waste heat. 90 10-20 Comparable

to full load

Comparable

to full load

37-45

34-40

17,000-34,100 N A

Organic 2 kW-2 MW Waste heat. 60-90 10-20 17,000-34,100 N A

G. Fuel cell topping

H, Stirling engine

topping

40 kW-25 MW

3-100 kW

(expect

1.5 MW by

1990)

Hydrogen, distillate/coal.

Externally fired—can use

most fuels.

90-92 37-45

Not known— 35-41

expected to be

similar to gas turbines and diesels.

7,500-9,300 4,300-5,500

8,300-9,750 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 lifetime

Technology 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 1-3

topping

25-35 Mature technology —commercially available in large

quantities.

This is the most commonly

used cogeneratlon technology. Generally used in

industry and utility applications. Best suited for

where electric/thermal

ratio is low.

Potential for use in residential, commercial, and

industrial sectors if fuel

is available and cost

effective.

Best suited to larger scale

utility and Industrial applications. Potential for

coal use is excellent.

Most attractive where

power requirements are

high and process heat requirements are lower,

Used in large industrial

applications such as

steel, chemical, and

petroleum refining

industries.

Reliable and available, can

be used in hospitals,

apartment complexes,

shopping centers, hotels,

industrial centers if fuel is

available and cost effective, and if can meet environmental requirements,

B. Open-cycle gas 320-700

turbine topping

0.29-0.34 2.5-3.0 0.75-2 20 natural gas

15 distillate

Mature technology —commercially available in large

quantities.

C. Closed-cycle gas 450-900 5 percent of Included in

turbine topping acquisition fixed cost

cost per year

2-5 20 Not commercial In the

United States; is well developed in several European countries.

Commercially available;

advanced systems by

1985.

D. Combined gas 430-800 5.0-5.5 3.0-5.1

turbine/steam

turbine 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 —commercially available in large

quantities.

F. Rankine cycle

bottoming:

Steam 550-1,100 1,6 3.7-6.9 1-3 20 Commercially available. Industrial and utility use

almost exclusively. Although efficiency is low,

since it runs on waste

heat no additional fuel

is consumed. Can reduce

overall fuel use.

Organic 800-1,500 2.8 4,9-7.5 1-2 20 Some units are commercially Same benefits/limitations

available but technology

is still in its infancy.

as steam Rankine bottoming except that it can use

lower-grade waste heat.

Organic Rankine bottoming is one of the few

engines that can use

waste heat in the 200°

600o

F range,

Modular nature, low emissions, excellent part-load

characteristics allow for

utility load foliowing as

well as applications in

commercial and industrial

sectors.

High efficiency and fuel

flexibility contribute to a

large range of applications. Couid be used in

residential, commercial,

and industrial applications. Industrial use

depends on development

of 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 and

experimental stage. phosphoric acid expected by

1985, moiten carbonate by

1990.

Reasonably mature technology up to 100-kW capacity

but not readily available.

Larger sizes being

developed.

H. Stirling engine 420-960 C

topping

5.0 8.0 2-5

“NA” means not applicable.

a

1980 dollars,

bDepends on system size and heat source. C

Cost 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 improvements have priority for available capital?

At present, significant uncertainties about the

types of cogeneration technologies that will be

installed and their location, costs, and operating

characteristics, and about general financial and

economic conditions make it difficult to analyze

the market potential for cogeneration or its impacts on electric utilities, fuel use, and the environment. However, general trends in the national

energy, electric utility, and policy context in

which cogenerators would be deployed can be

discerned, and analyses of these trends can be

used to evaluate existing policy incentives.

THE POTENTIAL FOR COGENERATION

Cogeneration could have a very large technical

potential in the United States–perhaps as much

as 200 gigawatts (GW) of electrical capacity by

2000 in the industrial sector alone, with a much

lower potential (3 to 5 GW) in the commercial,

residential, and agricultural sectors. (Total U.S.

installed generating capacity in 1980 was approximately 619 GW.) However, cogeneration’s market potential (the amount of cogeneration capacity that might be considered sufficiently economic

for an investment to be made) will be much smaller than this for several reasons.

First, cogeneration investments will have to

compete with conservation in industries and

buildings. Conservation investments usually are

less costly than cogeneration and have a shorter

payback period, and thus are likely to receive priority over cogeneration in most cases. As a result

of conservation measures, thermal energy demand is likely to grow much more slowly than

it has in the past (some sources project a zero

or negative rate of growth in industrial thermal

demand through 2000), and could present a declining opportunity for cogeneration.

In addition, cogeneration will compete in the

long term (beyond 1990) with electricity supplied by coal, nuclear, hydroelectric, and other

types of alternate-fueled electric utility generating capacity. Some cogeneration applications

may not be economically competitive where utilities have relatively low retail electricity rates or

are planning to replace existing powerplants with

ones that will generate electricity more economically (e.g., replacing intermediate-load oil-fired

generators with baseload coal plants).

Cogeneration’s market potential also will be

limited by the inability of most technologies—

especially smaller scale systems—to use fuels

other than oil or natural gas. At present, only

steam turbine cogenerators can accommodate

solid fuels. Advanced technologies now under

development will have greater fuel flexibility, as

well as better fuel efficiency and lower emissions.

In addition, advanced fuel combustion or conversion systems such as fluidized beds and gasifiers

can be used to improve the fuel flexibility of existing cogeneration technologies. More development is needed, however, to make these technologies commercially attractive, and they are not

likely to contribute significantly for 5 to 10 years.

Cogeneration’s ability to supply electricity to

the utility grid also will affect its market potential. Under the Public Utility Regulatory Policies

Act of 1978 (PURPA), economic and regulatory

incentives are offered to cogenerated power that

reduces utility costs for capacity, energy, or transmission and distribution, or that contributes to

power supply or load reduction during daily or

seasonal peak demands. These incentives are reflected in the price that utilities must pay for power purchased from a cogenerator, which is determined by a utility’s incremental costs, or the costs

avoided in not generating and distributing the

power itself or purchasing bulk power from the

grid. In many parts of the country, shortrun

avoided energy costs will be based on the price

the utility pays for oil or natural gas, and capacity costs on the operating cost of a peakload powerplant (e.g., a combustion turbine). In these

cases, the greater efficiency of cogeneration systems—even those burning distillate oil or natural

gas–often can make cogeneration the economically preferable means of generating electricity.

However, if the utility relies primarily on coal or

nuclear fuel and has excess capacity, then the
Ch. l—Overview ● 17

shortrun avoided energy cost (determined by offsetting coal or nuclear fuel) would be much lower

and there may be no shortrun avoided capacity

cost. In these cases, shortrun avoided cost payments may not be sufficient to make cogeneration an attractive investment. Longrun avoided

costs would be based on a utility’s resource plan,

and would raise the issue noted above of competition with coal and other non premium fuels.

Furthermore, the choice of technology will affect a cogenerator’s ability to supply power to the

grid. In general, technologies with a high ratio

of electricity-to-steam production (E/S ratio) will

be favored when onsite electric power needs are

large 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 or

natural gas. Steam turbines, the only commercially available technology that can burn solid fuels

directly, have a relatively low E/S ratio. For example, a large industrial installation that uses

500,000 lb/hr of steam would cogenerate 30 to

40 MW of electricity with steam turbines, and 120

to 150 MW with combustion turbines. Therefore,

where onsite electricity needs are high, or the

project’s economic feasibility depends on supplying electricity to the grid, a technology with

a higher E/S ratio (e.g combustion turbines,

diesels, combined cycles) would be favored, but

could not use fuels other than oil/gas in the short

term.

COGENERATION OPPORTUNITIES

Although the factors discussed above make

cogeneration’s overall market potential highly uncertain, it is possible to identify promising cogeneration opportunities in the industrial and commercial sectors and in rural areas.

Industrial Cogeneration

Today, industrial cogeneration has an estimated

installed capacity of 14,858 MW (see table 2). *

An additional 3,300 MW is reported to be in the

planning stages or under construction. The largest

number of industrial cogenerators are in the pulp

and paper industry, which has large amounts of

burnable wastes (process wastes, bark, scraps,

and forestry residues unsuitable for pulp) that can

be 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 assume

the distribution would be similar to that given in table 2.

ades this industry has considered electricity generation to be an integral part of its production

process and new pulp and paper plants are likely candidates for cogeneration.

The chemical industry uses about as much

steam annually as the pulp and paper industry

and historically has ranked third in industrial

cogeneration capacity. Chemical plants also will

represent a promising source of new cogenerators. Conservation opportunities, however, will

strongly dampen growth in steam demand if not

cause it to decline.

Another major cogenerator is the steel industry, because the off-gases from the open-hearth

steelmaking process provide a ready source of

fuel to produce steam for driving blast furnace

air compressors and other uses. But new cogenerTable 2.–installed Industrial Cogeneration Capacity

Capacity Capacity Number of Plants

Sector (SIC code) (MW) (percent) plants (percent)

Food (20) . . . . . . . . . . . . . . . . . . . . . . . . 398 3 42 11

Pulp and paper (26) . . . . . . . . . . . . . . . 4,246 29 136 37

Chemicals (28) . . . . . . . . . . . . . . . . . . . 3,438 23 62 17

Petroleum refining (29) . . . . . . . . . . . . 1,244 8 24 6

Primary metals (33) . . . . . . . . . . . . . . . 3,589 24 39 11

Other . . . . . . . .’. .’. . . . . . . . . . . . . . . . 1,943 13 68 18

Total . . . . . . . . . . . . . . . . . . . . . . . . . 14,858 371

SOURCE: General Energy Associates, Industrial Cogeneration Potential: Targeting of Opportunities at the Plant Site(Waahington,

D. C.: U.S. Department of Energy, 1982).
12 ● Industrial and Commercial Cogeneration

ation capacity is not likely to be installed in this

industry because new steel mills probably will be

minimills that use electric arcs and have little or

no thermal demand. However, if a market for the

thermal output could be found, an electric arc

minim ill could use the cogenerated electricity

and sell the heat/steam.

petroleum refining also is well suited to

cogeneration, but significant new refinery capacity is not expected to be built in the near future,

except in connection with heavy oil recovery in

California. However, some cogeneration capacity

could be installed when existing refineries are

upgraded.

Finally, the food processing industry currently has a small amount of cogeneration capacity

which could more than double by 1990. Here

the primary limit on the cogeneration potential

is the low thermal load factor that results from

the seasonal nature of the steam demand.

Commercial Building Cogeneration

Cogeneration in commercial buildings has a

much smaller potential for growth than industrial cogeneration, primarily due to the low thermal load factors in those buildings. Additional

constraints on commercial building cogeneration opportunities include the difficulty of

handling and storing solid fuels (coal, biomass)

in and around buildings; competition with conservation for energy investment funds, and with

coal or other baseload capacity additions for

economic electricity generation; and the special

air quality considerations in urban areas.

The disadvantages presented by the low thermal load factors in commercial buildings can be

overcome to some extent by undersizing the cogenerator and operating it at a high capacity factor to meet the baseload thermal needs, and using

conventional thermal conversion systems to supplement the cogenerator’s output. Alternatively,

several buildings could share a cogenerator and

use the diversity in their energy demand to improve the thermal load factor.

Moreover, commercial building cogeneration fueled with natural gas may have a promising market in the near term (up to 1990), especially where rates for utility purchases of cogenerated

power are based on the price of oil-fired electricity generation and utilities have substantial

amounts of oil burning capacity. In these cases,

cogeneration can allow rapid development of capacity to meet new electricity demand and/or reduce utility oil use. However, as noted previously, in the long term, cogeneration will have to

compete economically with coal and other alternate-fueled utility capacity.

The probable low market penetration of commercial sector cogeneration means that it usually will have a low potential for displacing the

fuel used by utility generating capacity. However, where electricity prices are high or utility

capacity additions are limited, cogeneration may

have a greater market potential and could displace utility intermediate oil or gas capacity. If

both the cogenerator and the capacity it displaces

use oil, the result usually would be a decrease

in utility use of residual fuel oil and a corresponding increase in distillate use by commercial cogenerators, but an overall reduction in total oil

use. Relatively small systems with good part-load

characteristics (e.g., diesels and spark-ignition

engines) are likely to be favored in urban residential/commercial applications where there are

physical site limitations and low capacity factors,

and these systems are limited to the use of oil or

natural gas in the near term.

In summary, OTA found that commercial

building cogeneration would be economically

attractive where there is a moderate rate of

growth in electricity demand (2 percent or more

annually), where electric utilities are caught in

a capacity shortfall, or where the utility has a

high percentage of oil-fired capacity; where

there is a high heating demand (about 6,000

heating degree days per year); and where cogenerators can use a fuel that is significantly less

costly than oil. However, even if these advantages are available, cogeneration’s competitiveness in the commercial sector will be subject to

the same limiting factors as in the industrial sector—competition with conservation measures that

have a lower capital cost and shorter payback

period, the ability to supply significant amounts

of power to the grid, and economic and regulatory uncertainties.
C.+. I—Overview ● 13

Rural Cogeneration Opportunities

Rural cogeneration opportunities arise where

there are existing small community powerplants

that could recover and market their waste heat,

and/or where alternate fuels (such as biomass)

are readily available. Promising rural cogeneration applications include producing ethanol, drying crops or wood, and heating greenhouses, animal shelters, or homes.

A large number of small rural powerplants are

standing idle due to the high cost of premium

fuels. Generally these are dual-fuel engines burning natural gas plus small amounts of fuel oil to

facilitate combustion; diesel engines and naturalgas-fueled spark-ignition engines are also common. The waste heat from these engines could

be recovered and use directly (in the case of

natural-gas-fired systems) or used in heat exchangers to provide hot water or steam. If only

half of the waste heat were used, a powerplant’s

energy output would double, providing a new

revenue stream for the community and enabling

the engines to be operated economically. These

potential benefits would be weighed against the

cost of installing and operating the heat recovery

system.

However, cogeneration at an existing rural

powerplant could increase oil use if it is substituted for grid-supplied electricity generated with

alternate fuels. Therefore, rural communities

should focus on technologies that can use locally

available biomass fuels such as crop residues,

wood, and animal wastes. Gasifiers that convert

crop residues or wood to low- or medium-Btu

gas can be connected with internal combustion

engines, although the engines will need some

modification for trouble-free operation over long

periods of time. Such gasifiers are commercially

available in Europe and are being demonstrated

in the United States. Anaerobic digestion of animal wastes from confined livestock operations

also could be used to produce biogas (a mixture

of 40 percent carbon dioxide and 60 percent

methane) to fuel an internal combustion engine.

Anaerobic digestion has the advantages of solving a waste disposal problem, while producing

not only biogas but also an effluent that can be

used directly as a soil conditioner, dried and used

as animal bedding, or possibly treated and used

as livestock feed. Digesters for use in cattle, hog,

dairy, and poultry operations are commercially

available in the United States and are being demonstrated at several rural sites. Wastes from ruralbased industries, such as whey from cheese

plants, also are being used as a feedstock for farmbased digesters.

Cogeneration can have significant economic

and fuel savings advantages in rural communities

and on farms. The rural cogeneration potential

is not so large as that in industrial and urban applications, but the advantages can be very important in allowing significant local economic expansion—from new jobs and from increased revenues due to steam/heat sales—by using local resources without increasing the base demand for

energy.

INTERCONNECTION REQUIREMENTS

The economic and other incentives offered to

cogeneration under PURPA assume that cogenerators will be interconnected with the electric

utility grid. Such interconnections may require

special measures to maintain power quality, to

control utility system operations, to protect the

safety of lineworkers, and to meter cogenerators’

power production and consumption properly.

OTA found that most of the technical aspects

of interconnection are well understood, and the

primary issues related to interconnection are the

lack of uniform guidelines and the cost of the

equipment.

The characteristics of cogenerated electricity

that is distributed to the grid must be within certain tolerances so that utilities’ and customers’

equipment will function properly and not be

damaged. Thus, grid-connected cogenerators

may need capacitors to keep voltage and current

in phase; over/under relays to disconnect the generator automatically if its voltage goes outside a
14 ● Industrial and Commercial Cogeneration

certain range; and a dedicated distribution transformer to isolate voltage flicker problems. Because the power quality impacts of cogenerators

are technology- and/or site-specific, not all systems will need all of this equipment. In particular, very small cogenerators (under 20 kW) may

have few or no adverse effects on grid power

quality and may not require any extra interconnection equipment. Moreover, larger systems

probably will already have dedicated transformers, and may only need power factor correcting

capacitors if they use induction (as opposed to

synchronous) generators.

Proper interconnection is necessary to ensure

the safety of utility workers during repairs to

transmission and distribution lines. First, cogenerators should locate their disconnect switches

in specified areas in order to simplify lineworkers’

disconnect procedures. In addition, induction

generators (and, very occasionally, synchronous

generators) must use voltage and frequency relays

and automatic disconnect circuit breakers to protect against self-excitation of the generator. Alternatively, the power factor correcting capacitors

can be located where they will be disconnected

along with the cogenerator (and thus prevent selfexcitation) or where they can be isolated easily

by lineworkers.

Large numbers of grid-connected cogenerators

that are dispatched by the electric utility may require expensive telemetry equipment and could

overload utility system dispatch capabilities.

However, these problems can be avoided if utilities treat cogenerators as “negative loads” by

subtracting the power produced by the generators from total system demand and then dispatching the central generating capacity to meet

the reduced load. Most utilities currently use

negative load scheduling with cogenerators (and

small power producers), and some studies indicate that it may work well even with large

numbers of cogenerators. However, some utilities

question whether the system would continue to

function properly if a significant percentage of

total system capacity were undispatched cogenerators being treated as negative loads. Additional research is needed to determine whether

undispatched cogenerators will cause problems

for a utility system and, if so, at what degree

of system penetration such problems would

arise.

Finally, cogenerators’ power production and

consumption must be metered accurately in order to provide better data on their output characteristics (and thus facilitate utility system planning), and to ensure proper pricing for buyback

and backup power. Cogenerators can be metered inexpensively with two standard watt-hour

meters—one operating normally to measure consumption and the other running backwards to indicate production. Alternatively, advanced meters can be installed that indicate not only kilowatthours used/produced but also power factor

correction and time-of-use. These advanced meters provide better data about cogeneration’s

contribution to utility system loads, and they facilitate accurate accounting (and thus pricing) of

power purchased and sold. However, advanced

meters also cost about five times more than two

standard watt-hour meters.

Estimates of the cost for interconnection vary

widely—from $12/kW for a large cogenerator

to $1 ,300/kw for a small system—depending on

the generator type, the system size, the amount

of equipment already in place, and a particular

utility’s or State public service commission’s requirements for equipment type and quality. In

general, interconnection costs will be higher if

a dedicated transformer is needed. Economies of

scale also are apparent for circuit breakers, transformers, and installation costs. Moreover, some

utilities or commissions may require more equipment than described above in order to provide

extra protection for their system and the other

customers. The quality of the interconnection

equipment required also may affect costs substantially. Some utilities allow smaller cogenerators

to use lower quality and less expensive industrialgrade equipment, but the size cutoff varies widely

among utilities—from 200 to 1,000 kW. In other

areas, all cogenerators are required to use the

higher quality utility-grade equipment, but with

such equipment the cost of interconnection may

be prohibitive for small cogenerators. Few guidelines exist for the type and quality of interconnection equipment necessary for cogenerators,

but several are under preparation. Once standard

guidelines are available, interconnection costs

should become more certain.
IMPACTS OF COGENERATION

Cogeneration has the potential for both

beneficial and adverse effects on fuel use, utility

planning and operations, and the environment.

In each case, OTA found that the potential negative impacts could be mitigated substantially

if the cogeneration technology is carefully selected and sited, if the cogenerator works closely

with the utility throughout the project’s planning and implementation, and if the cogeneration system is carefully integrated with existing

and planned future energy supplies.

Effects on Fuel Use

All cogenerators will save fuel because they

produce electric and thermal energy more efficiently than the separate conversion technologies

they will displace (e.g., an electric utility

powerplant and an industrial boiler). Whether

cogeneration will save oil depends on the fuel

used by a cogenerator and the fuels used in the

separate systems that are displaced. If both of

the separate technologies burn oil and would

continue to do so for most of the useful life of

the cogenerator that supplants them, then even

an oil burning cogenerator will reduce total oil

consumption. However, if either or both of the

separate conventional technologies use an alternate fuel (e.g., coal, nuclear, hydroelectric, biomass, solar), or would be converted to an alternate fuel during the useful life of a cogenerator,

then oil-fired cogeneration would increase total

system oil use.

Where oil savings are available through

cogeneration, their magnitude will depend on

the type of cogenerator and the types of separate conversion technologies that are displaced, as well as on the rates for purchases of

cogenerated power under PURPA. For example,

an oil-fired steam turbine cogenerator could reduce oil use by 15 percent if it is substituted for

an oil-fueled steam electric powerplant and separate low-pressure steam boiler, while a diesel cogenerator that recovers three-quarters of the potentially usable heat could represent a 25 percent

savings if it replaces a diesel electric generator

and separate oil burning furnace. (Much greater

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

Higher rates for utility purchases of cogenerated power will favor technologies with high E/S

ratios, thus increasing the potential to displace

utility generating capacity, much of which will

be intermediate and peakload plants that burn

oil. However, because currently available high

E/S cogenerators also are limited to the use of oil

(or natural gas), care must be exercised in deploying these technologies if it is important to ensure

that oil savings are achieved over the useful life

of the cogenerator. In many cases, the market

(high prices and uncertain availability), regulatory

provisions, tax measures, and the utility’s avoided

costs will provide such insurance.

Impacts on Utility Planning

and Operations

Cogeneration can offer significant economic

savings for utilities that need to add new capacity. Where utilities need to displace oil-fired

capacity or accommodate demand growth, cogeneration can bean attractive alternative to conventional powerplants. Cogenerators’ relatively small unit size and short construction leadtime can provide more flexibility than large

baseload plants for utilities in adjusting to unexpected changes in demand, and cogeneration

is a more cost-effective form of insurance against

such changes than the overbuilding of central

station capacity. Cogeneration also has the potential to significantly reduce interest costs during construction (and thus the overall cost of

providing electricity).

Relying on cogeneration capacity instead of

conventional powerplants should not pose significant operating problems for utilities if the cogenerators are properly connected to the grid. As

discussed previously, large numbers of small gridconnected cogenerators should not overburden

utility system dispatch capabilities if they are

treated as negative loads, but the effects of a

substantial penetration of a system are uncertain.
76 ● Industrial and Commercial Cogeneration

However, expansion of cogeneration could

have a substantial adverse economic impact on

utilities that have excess capacity and/or a low

rate of growth in demand. If large industrial and

commercial sites drop out of a utility’s load, then

the utility’s fixed costs must be shared among

fewer customers, who would then have higher

electric rates. This competition has been observed in other regulated industries (e.g.,

telecommunications, railroads). The effects of

such competition are essentially the same as

those of the competition from conservation measures or of the excess capacity that can result from

oil displacement.

Where utilities already have excess capacity or

are committed to major construction programs

that cannot be deferred, the risk of reduced fixed

cost coverage can be acute. In the long run, such

competition could represent a benefit for most

utilities by reducing the need for new capacity

and thus relieving financial pressures on utilities

and lowering rate levels. But until the construction budget is adjusted, the short-term effects of

revenue losses could be severe for some utilities

and their remaining customers.

Furthermore, if utilities purchase power from

cogenerators based on the utility’s full avoided

cost, the utility’s non-cogenerating customers may

not receive any economic benefit from cogeneration. Cogenerators usually will be installed only

where their operating costs would be less than

the avoided cost rate paid by the utility for their

power. If the cogenerator receives the full difference, the ratepayer will receive no direct benefit.

This situation is exacerbated if the avoided cost

payments are higher than the utility’s actual shortrun marginal cost (e.g., if the State regulatory

commission bases avoided costs on the price of

oil and the utility operates with a mix of fuels,

or if the commission establishes a high avoided

cost as an explicit subsidy to encourage cogeneration). A payment to cogenerators of less than

the utility’s full avoided cost, with the difference

going toward rate reduction, would share any

cost benefits of cogeneration with the utility’s

other ratepayers.

One solution to both the competition posed

by cogeneration and the rate reduction issue is

for utilities to own cogenerators. ownership

could be advantageous to a utility because the

cogenerator would be included in the utility’s rate

base and thus the utility would earn a percentage return on the equipment. Where cogeneration is economically competitive with other types

of capacity additions, utilities should be investing

in it. However, cogeneration systems that are

more than 50 percent utility-owned are not eligible for the economic and regulatory incentives

established under PURPA, which often determine

economic competitiveness. If full utility ownership were allowed incentives under PURPA, cogeneration’s market potential probably would increase, as would the amount of electricity it

would supply to the grid (because utilities would

be more likely to install high E/S ratio technologies). In addition, utility investment in cogeneration would have the economic advantages related

to the small unit size and shorter construction

Ieadtimes discussed previously, and could result

in lower electricity rates compared to conventional capacity additions. However, full utility

ownership under PURPA raises a number of concerns about possible anti-competitive effects and

about the resulting profits to utilities; these are

discussed in more detail under “Policy Considerations,” below.

Environmental Impacts

The primary environmental concern about cogeneration is the public health effects of changes

in air quality. Cogeneration will not automatically offer air quality improvement or degradation

compared to the separate conversion technologies it will replace. Cogeneration’s greater fuel

efficiency may lead to either a decrease or an increase in the total emissions associated with electric and thermal energy production, depending

on the types of combustion equipment, their

scale, and fuel used. Similarly, cogeneration may

improve or degrade air quality by shifting emissions away from a few central powerplants with

tall stacks to many dispersed facilities with shorter

stacks, depending on the variables listed above

as well as on the location of the cogenerators and

the 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 impacts due to their high–but usually controllable–nitrogen oxide emissions. Diesels also emit

potentially toxic particulate, but clear medical

evidence of a human health hazard is lacking at

this time. Steam and gas turbines should not result

in an increase in total emissions unless they use

a “dirtier” fuel than the separate conversion technologies they replace (e.g., a shift from distillate

oil to high sulfur coal), or where a new turbine

cogenerator that primarily produces electricity is

installed instead of a new boiler or furnace.

Adverse local air quality impacts are most likely to occur with cogeneration in urban areas,

because urban cogenerators usually will be

diesels or spark-ignition engines, because urban

areas would have a higher total population exposure, and because tall buildings can interfere

with pollutant dispersion. Moreover, the small

systems that would be used in these applications

tend to have high nitrogen oxide and particulate

emissions. As a result of these considerations,

urban cogenerators must be designed and sited

carefully, including choosing an engine model

with low emissions, applying technological

emission controls, and ensuring that the exhaust

stacks are taller than surrounding buildings.

Cogenerators’ greater fuel efficiency also can

lead to an important environmental benefit in

other aspects of a fuel cycle (e.g., exploration,

extraction, refining/processing) if a cogenerator

uses the same fuel as the conventional energy systems it displaces. However, if a fuel that is difficult to extract, process, and transport (e.g., coal)

is substituted for a “cleaner” fuel (such as natural

gas), the overall impact may be adverse rather

than beneficial.

Finally, cogeneration might affect water quality (from blowdown from boilers and wet cooling systems, and from runoff from coal piles and

scrubber sludge and ash disposal), waste disposal

(sludge and ash), noise, and materials (from cooling tower drift). All of these will be more likely

to pose a problem in urban areas, and all are

either controllable and/or are more likely to be

a nuisance than a health hazard.

Socioeconomic Impacts

General trends for impacts on economic and

social parameters such as capital investment,

operating and maintenance (O&M) costs (excluding fuel costs), and labor requirements cannot be identified at this time due to the large

uncertainties in future deployment patterns.

These impacts will depend heavily on the size

and type of cogenerators used, the size and type

of separate conversion technologies that would

be displaced, the regions in which cogeneration

would be installed (construction costs and labor

requirements generally are lower in the South),

and cogenerators’ operating characteristics. For

example, in comparing cogeneration capital costs

with those for conventional baseload and peakIoad capacity, OTA found that the cost of installing 100,000 MW of electric generating capacity

under cogeneration scenarios varied from about

25 percent more to approximately 95 percent less

than the cost of installing an equivalent amount

of capacity under conventional central station

scenarios, depending on the capacity mix and

location for each scenario.

For purposes of comparison, OTA analyzed the

mean values for capital and O&M costs, and for

construction and O&M labor requirements, for

50,000, 100,000, and 150,000 MW of electricitygenerating capacity with and without cogeneration. In this comparison, OTA found that mean

capital costs for cogeneration tended to be

around 20 to 40 percent lower than the mean

costs for an equivalent amount of conventional

utility capacity. Because cogenerators have a

shorter construction Ieadtime than conventional

powerplants, savings on interest charges during

construction would increase this capital cost difference. The O&M cost differences were calculated for two different cogeneration capacity

factors–45 and 90 percent. With a capacity factor of 90 percent, mean cogeneration O&M costs

were higher (25 to 70 percent) than mean utility

O&M costs, while cogenerators operating at a 45

percent capacity factor had mean O&M costs

ranging from approximately 20 percent higher to

roughly 35 percent lower than mean utility costs.
18 ● Industrial and Commercial Cogeneration

Construction and O&M labor requirements both In general, these results confirm reports in the

tended to be higher for the cogeneration sce- Iiterature that cogeneration could save investnarios than for the central station capacity ment capital while increasing direct employment

scenarios. Up to 50 percent more construction in electricity supply. However, the actual ecoIabor might be required for cogeneration than for nomic and employment effects might be much

utility capacity. The O&M labor requirements different if the mix of technologies installed were

varied much more widely due to the lack of data different from those examined by OTA.

and the pronounced economies of scale for cogeneration O&M labor.

POLICY CONSIDERATIONS

The primary Federal policy initiatives that affect the deployment of cogeneration capacity include provisions of title II of PURPA, the Powerplant and Industrial Fuel Use Act of 1978 (FUA),

the Clean Air Act, and the tax laws, as well as

Government support for research and development. In general, the combined focus of these

initiatives is to encourage grid-connected cogeneration that will use energy economically and

utility resources efficiently. Although the longterm effects of these policies on cogeneration implementation are still uncertain (due to delays in

State implementation and to ongoing changes in

Federal priorities), a number of unresolved issues

have been identified for possible further congressional action. These include the use of oil in cogeneration, the economic incentives for cogeneration, utility ownership of cogeneration capacity,

requirements for interconnection with the grid,

and the effects of cogenerators on local air

quality.

Oil Savings

Despite their inherent energy efficiency, not all

cogenerators will save oil. The purchase power

rate provisions of PURPA, FUA prohibitions on

oil use in powerplants and industrial boilers, and

the energy tax credits discourage cogeneration

applications that would increase oil use, but they

may not be effective in all cases. For example,

cogenerators with less than about 10-MW generating capacity or that sell less than half their annual electric output, are automatically exempt

from FUA prohibitions. Similarly, an oil-fired cogenerator may not be entitled to rates for utility

purchases of cogenerated power under PURPA

that are as high as those paid to systems burning

alternate fuels, but the installation could be economic without those payments (e.g., if retail electricity rates are very high). Moreover, an existing

industrial or commercial oil burning energy system could be retrofitted for cogeneration and still

qualify for the energy tax credit as long as onsite

energy use is reduced.

In many cases, the uncertain price and longterm availability of oil, coupled with regulatory

and economic disincentives to its use, will be sufficient to discourage oil-fired cogeneration. However, where oil-fired cogenerators still would be

economic but would not provide lifetime oil savings, additional policy initiatives might be considered if net oil savings is the primary goal.

These include amending FUA to prohibit the use

of oil in all cogenerators regardless of size or electricity sales unless a net lifetime oil savings can

be demonstrated; amending PURPA to deny

qualifying facility status (and thus economic and

regulatory incentives) to oil burning cogenerators

unless net oil savings are shown; and amending

the investment and energy tax credits and other

tax code provisions to deny tax deductions,

credits, or other measures for cogeneration projects unless net oil savings are demonstrated.

However, these measures may only provide oil

savings of less than 100,000 barrels per day in

1990. Moreover, net oil savings are difficult to

prove, and these regulations could be expensive

and time-consuming for both potential cogenerators and implementing agencies, and could discourage even those cogeneration systems that

would save oil.
Ch. 1—Ovefview ● 19

If net oil savings is the primary goal, there are

several policy alternatives to additional layers

of fuel use regulations. First, oil consumption

could be taxed (e.g., with an oil import fee). Such

a tax would encourage conservation in all oil markets and provide additional Federal revenues.

Alternatively, restrictions in FUA and the tax laws

on the use of natural gas in cogenerators might

be eliminated. Natural gas for cogeneration is

likely to be competitive with oil, and gas-fired

cogenerators usually will be technically and economically attractive in the same situations as oil

burning systems. Moreover, gas-fired cogeneration could provide a bridge to the development

of gasification systems using alternative fuels.

Thus, removing regulatory and tax restrictions on

the use of natural gas in cogenerators would complement market disincentives to oil use, by presenting an economically attractive alternative in

those situations where oil might otherwise be

favored.

On the other hand, if gasification systems do

not become commercial as soon as their developers project, or if the cost of producing low- or

medium-Btu gas remains significantly higher than

the cost of natural gas, then this strategy could

lock cogenerators into natural gas use for 10 to

20 years. Moreover, if natural gas-fired cogeneration were given incorrect incentives, and made

more attractive than market conditions would justify, this could discourage the use of non-premium

fuels (e.g., coal, biomass, wastes) and add to the

demand for natural gas. If supplies are limited,

the cogenerators’ demand could increase supply pressures for established gas users.

Economic Incentives for Cogeneration

Cogeneration’s market potential (the amount

of cogeneration capacity that may be installed

and the amount of electricity that it will produce) is extremely sensitive to economic considerations. These include the rates for utility purchases of cogenerated power, tax credits and

leasing provisions, and other policy measures

that either reduce the capital cost or offset the

operating cost of cogeneration systems. At present, however, the continued availability of existing policy initiatives is in doubt.

A recent court decision vacated the Federal Energy Regulatory Commission (FERC) regulations

implementing PURPA that called for utility purchases of cogenerated power at rates equal to 100

percent of the incremental cost saved by the utility by not generating the power itself or purchasing it from the grid (termed the utility’s “avoided

cost”). The court heId that FERC had not adequately justified rates based on the full avoided

cost when a lower rate would still compensate

most cogenerators adequately while sharing the

economic benefits of cogeneration with the utility’s ratepayers. In order for the ratepayers to

share in any cost benefits of cogeneration, less

than full avoided costs would have to be paid to

the cogenerator, with the difference going to rate

reductions, or the utility would have to own the

cogenerator. The full avoided cost rates remain

in effect pending final resolution in the case (including appeals and revision of the regulations,

if necessary), but uncertainty about the long-term

purchase rates is substantially discouraging cogeneration except in those cases where State legislatures or regulatory commissions have instituted full avoided cost rates on their own initiative.

A second source of uncertainty is the 1982 expiration date for the special energy tax credit. The

availability of this credit often can make or break

the economic feasibility of cogeneration projects

(and other alternate energy systems). Due to the

currently high interest rates and the promise of

improved technologies now under development

or demonstration, many potential cogenerators

would prefer to wait several years before making their investment. The continued availability

of the energy tax credit (perhaps through 1990)

could help to ensure that those investments

would be made, while an earlier expiration date

might encourage the installation of less efficient

existing technologies.

Finally, if the Government wanted to maximize

cogeneration’s market potential, then policies

that substantially reduce capital costs might be

implemented. With the current high interest

rates, debt financing—the primary mode of financing for potential cogenerators—is unattractive or unavailable. Therefore, subsidies that lower interest rates and extend loan terms may be

more attractive than tax credits.
Utility Ownership

Electric utility ownership could substantially

increase cogeneration’s market potential. Power

production is electric utilities’ primary business

and they would thus not be subject to many of

the qualms of industrial or commercial concerns

that are unaccustomed to producing electric

power or that place higher priorities on investments in process equipment. Some utilities may

require a lower return on their investment than

other types of investors, and a cogeneration project that may only be marginally economic for an

industrial or commercial firm could be attractive

to a utility. Moreover, utility ownership could

allay concerns about competition from cogenerators.

Although there are no legal restrictions on utility ownership of cogenerating capacity, such ownership is at a competitive disadvantage because

cogenerators in which electric utilities or utility

holding companies own more than a 50-percent

equity interest do not qualify for the economic

and regulatory incentives under PURPA, and because public utility property is not eligible for the

energy tax credit. Removing these disincentives

would place utilities in an equal (at least) position with other investors with regard to cogeneration, and could substantially increase the production of cogenerated electricity.

However, full utility ownership under PURPA

raises concerns about the possible effects of such

ownership on competition and on utility obligations to minimize electricity generation costs. Utilities could favor their own (or their subsidiaries’)

projects in contracting for cogeneration capacity. They also might favor a few major established

suppliers of cogeneration equipment, leading to

the possibility of adverse effects on small business

and the development of innovative technologies.

Moreover, if a utility is paying its subsidiary for

cogenerated electricity based on the utility’s

avoided cost of generation or purchases from the

grid, then the utility has few incentives to reduce

its marginal costs, because to do so would be to

reduce the subsidiaries’ rate of return and profitability. while these concerns about utility

ownership under PURPA are real, they can be

allayed through carefully drafted legislation or

regulations, or through careful State review of

utility ownership schemes. If these cautionary

measures are taken, the benefits of utility ownership probably would outweigh the potential

for anti-competitive and economic costs.

interconnection Requirements

The requirements for interconnecting and integrating cogenerators with utility transmission and

distribution systems have become both technical

and institutional issues. There are technical issues

because of the wide variability among States and

utilities on the type and quality of equipment that

is necessary to regulate system power quality,

protect the safety of utility employees, maintain

control over system operations, meter cogenerators’ electricity production and consumption

properly, and prevent damage to utilities’ and

other customers’ equipment. Few guidelines exist

for interconnection needs, but the equipment required can add enough to a project’s costs to

make cogeneration economically infeasible. As

a result, a high priority should be placed on the

preparation of guidelines for utilities and State

commissions to follow in setting interconnection

requirements.

Second, utilities’ legal obligation to interconnect is unclear. FERC regulations implementing

PURPA established a general obligation to interconnect in order to carry out the statutory mandate that utilities must purchase power from and

sell it to cogenerators. However, PURPA also

amended the Federal Power Act to provide for

full evidentiary hearings on interconnections

upon the request of a utility or a qualifying cogenerator. The U.S. Court of Appeals recently

ruled that the Federal Power Act procedure was

the valid one. Therefore, if a utility is not willing

to interconnect, the cogenerator must go through

the costly and time-consuming process of such

a hearing. Furthermore, most of the showings required of the petitioner in such a hearing would

be extremely difficult and expensive for a poten-
tial cogenerator to make. This issue probably can

only be resolved through a congressional amendment to PURPA that specifies utilities’ obligation

to interconnect with cogenerators (and small

power producers) and leaves resolution of technical and cost issues to State utility commissions.

Air Quality Considerations

Proponents of cogeneration have argued that

air pollution control regulations unnecessarily

restrict the deployment of cogenerators. They

suggest that cogenerators be given special treatment that accounts for their increased fuel efficiency and their displacement of emissions from

centrally generated electricity. Proposed changes

include emission standards that are tied to the

amount of energy output rather than the fuel input, or separate and more lenient emissions limitations for cogenerators; and less strict new

source review procedures for cogenerators under

prevention of significant deterioration and nonattainment area provisions of the Clean Air Act

(e.g., by allowing an automatic offset for reductions in powerplant and boiler emissions).

Although these changes would remove some

disincentives to cogeneration, OTA found that

in many situations there is no public health or

environmental justification for automatically

granting cogenerators relief from air quality requirements. A potentially more productive alternative would be to favor situations where cogenerators can demonstrate that they will have a positive net impact on air quality. In those cases,

relief from regulatory requirements could be

granted on a case-by-case basis. Review of individual cases will be especially important in urCHAPTER 1

1.

2.

3.

Edison Electric Institute, Statistic/ Yearkok of the

E/ectric Uti/ity /ncfustry: 1980 (Washington, D. C.:

Edison Electric Institute, 1981).

General Energy Associates, /ndustria/ Cogeneration

Potential: Targeting of Opportunities at the Plant

Site (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. Government Printing Office, 1976).

ban areas where small internal combustion engine cogenerators that are not regulated under

the Clean Air Act could have significant adverse

impacts on air quality.

Research and Development

The most promising cogeneration applications

are those that can use fuels other than oil and

that can produce significant amounts of electricity. Of the currently available technologies (that

are widely applicable), only steam turbines can

accommodate solid fuels. But steam turbines

have a low E/S ratio. Higher E/S ratio technologies

are available, but can only use oil or gas. Therefore, research and development efforts should

concentrate on demonstrating high E/S cogenerators that can burn solid fuels cleanly, and on

advanced combustion systems such as fluidized

beds that can be used in conjunction with a cogenerator. Because many potential cogenerators

will not be able to burn solid fuels directly (due

to site, environmental, or resource availability

limitations), special attention also should be paid

to the development and demonstration of gasifiers that would convert solid fuels to synthetic

gas onsite, or for transport to the cogeneration

site. Gasifiers would allow available cogeneration technologies to be installed now and use

natural gas (currently relatively abundant) until

synthetic gas becomes available.

Research also should be directed at removing

the remaining technical uncertainties in interconnection, developing lower cost pollution control

technologies for small generators, and improving coal transportation and handling in urban

areas.

4. Resource Planning Associates, Cogeneration: Technical Concepts, Trends, Prospects (Washington,

D. C.: U.S. Department of Energy, DOE-FFU-1 703,

1978).

5. TRW Energy and Environmental Division, Ana/ysis

of Existing lnclustrial Cogeneration Capacity (~ashington, D. C.: U.S. Department of Energy, 1982).
Chapter 2

Issues and Findings
Contents

Page

What 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 and

Electric 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. Page

3. interconnection Costs for Three Typical Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37

4. Considerations in Determining Avoided Costs Under PURPA . . . . . . . . . . . . . . . . . . . 41

5. Effect of Cogeneration Characteristics on Air Quality . . . . . . . . . . . . . . . . . . . . . . . . . . 43

Figures

Figure No. Page

3. illustrations of Topping Cycle Cogeneration Systems . . . . . . . . . . . . . . . . . . . . . . . . . . 26

4. Schematic of a Bottoming Cycle Cogenerator . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27

5. Schematic of a Combined-Cycle Cogenerator . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29

6. Fuel Cell Operation. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30

7. 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 mechanical

power plus useful thermal energy–in one technological process. The electric power produced

by a cogenerator can be used onsite or distributed through the utility grid, or both. The thermal energy usually is used onsite for industrial

process heat or steam, space conditioning, and/or

hot water. But, if the cogeneration system produces more useful thermal energy than is needed

onsite, distribution of the excess to nearby facilities can substantially improve the cogenerator’s

economics and energy efficiency.

The total amount of fuel needed to produce

both electricity and thermal energy in a cogenerator is less than the total fuel needed to produce

the same amount of electric and thermal energy

in separate technologies (e.g., an electric utility

generating plant and an industrial boiler). It is

primarily this greater fuel use efficiency that has

created a resurgence of interest in cogeneration

systems. However, cogeneration also can be attractive as a means of adding electric generating

capacity rapidly at sites where thermal energy

already is produced.

Cogeneration technologies are termed “topping cycles” if the electric or mechanical power

is produced first, and the thermal energy exhausted from power production is then captured

and used (see fig. 3). “Bottoming cycle” cogeneration systems produce high-temperature thermal

energy first (e.g., for steel reheating or aluminum

remelting), and then recover the waste heat for

use in generating electric or mechanical power

plus additional, lower temperature thermal energy (see fig. 4). Topping cycle cogenerators would

be used in residential, commercial, and most industrial applications, while bottoming cycle applications would most likely arise from high-temperature industrial processes.

WILL COGENERATION SAVE OIL?

Cogeneration is widely acclaimed as a conservation technology because it uses less fuel (measured in Btu equivalents) to generate a given

amount of electricity and useful thermal energy

than separate conventional energy systems (e.g.,

a powerplant and an industrial boiler; see fig. 2).

However, just because cogeneration is more fuel

efficient does not mean that it will automatically

reduce oil consumption.

Whether cogeneration will save oil (or natural

gas, or any other particular fuel) depends on the

fuel burned by a cogenerator and the fuel used

in the separate electric and thermal energy producing systems the cogenerator displaces. if

both of these separate systems would burn oil,

and continue to burn oil for most of the operating life of an oil-fired cogenerator that replaced them, then an oil burning cogenerator

would reduce total oil consumption. This savings can range from a 15-percent reduction in oil

use when a steam turbine cogenerator is substituted for a steam electric powerplant and a

separate low-pressure steam boiler, to a 34 percent savings if a diesel cogenerator that converts

38 percent of the fuel energy to electricity (30 percent to useful thermal energy) replaces separate

oil-fired powerplants and furnaces.

However, if a cogenerator that will burn oil

during most of its useful life replaces either a

powerplant or a conventional furnace or boiler

that uses a different fuel (e.g., coal, wood), or

that plans to convert to a different fuel during

the useful life of the cogenerator, then oil burning cogeneration will actually increase total system oil use. Therefore, cogeneration will only

save oil if it uses an alternate fuel itself (e.g., coal),

or if it replaces separate electric and thermal energy systems that use (and will continue to use) oil.

25
26 ● Industrial and Commercial Cogeneration

Figure 3.—illustrations of Topping Cycle Cogeneration Systems

Combustion turbine

Air and

ir

High-t

Diesel engine

Air and

Steam turbine

Diesel engine

fuel--- > 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 three

reasons. First, most commercially available cogeneration technologies require clean premium

fuels such as oil or natural gas (see ch. 4). Steam

turbine cogenerators can burn coal or other alternate fuels such as biomass or solid waste, but may

be prevented from doing so due to site or environmental considerations. Advanced cogenerators that can use alternate fuels may not be available for several years. Second, although industrial

processes and, to a lesser extent, electric utilities,

are heavily dependent on oil and natural gas,

both groups already plan to reduce their use of

these fuels either through conservation or conversion to alternate fuels or both. Third, although

the Powerplant and Industrial Fuel Use Act of

1978 (FUA) prohibits the use of oil and natural

gas in new powerplants and boilers, cogenerators

are exempt from these prohibitions if less than

half of their annual electric output is sold or exchanged 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 kilowatthour (Btu/kWh) heat rate), or if they can

demonstrate a net savings of oil or gas.

When these three considerations are combined

with economic conditions that favor cogeneration (e.g., high retail electricity rates), the combination could outweigh market considerations

and result in oil-fired cogeneration that would

lock industrial or commercial cogenerators into

premium fuel use for 10 to 20 years or more. On

the other hand, if oil cogeneration is used only

where premium fuel savings are sure to result

(i.e., where both the electric and thermal systems

the cogenerator replaces would continue to burn

oil for most of the operating life of the cogenerator), or where conversion to alternate fuels will

be possible in the near term (e.g., a dual-fuel system that can convert from oil to synthetic gas

when gasification technology is improved), then

even oil-fired cogeneration can pose significant

oil savings.
28 ● Industrial and Commercial Cogeneration

UNDER WHAT CIRCUMSTANCES ARE AVAILABLE COGENERATION

TECHNOLOGIES ATTRACTIVE?

The commercially available cogeneration technologies described in this report include steam

turbines, open-cycle combustion turbines, combined-cycle systems, diesels, and steam Rankine

bottoming cycles. All of these technologies will

provide energy savings because their fuel efficiency is greater than that of the separate electric and

thermal energy systems they will replace, but

their comparative technical, economic, and fuel

use advantages vary (see table 1 and ch. 4; for

a review of their relative environmental advantages, see, “What Are the Environmental Impacts

of Cogeneration?”).

A steam turbine topping cycle cogenerator (see

fig. 3) produces thermal energy at moderate temperatures and pressures that are suitable for many

industrial applications that do not need high-temperature heat. Available steam turbines have a

relatively high overall efficiency, but their ratio

of electricity generated to thermal energy produced (electricity-to-steam (E/S) ratio) is relatively

low. Therefore, steam turbine cogenerators are usually not appropriate where large electricity requirements are paramount, such as the need to provide power to the grid to improve economic feasibility. In addition, steam turbines can have relatively high unit costs, longer startup times and

installation Ieadtimes than other available cogenerators, and more stringent personnel requirements specified by boiler codes. On the other

hand, steam turbines are extremely reliable, and

can use a wider range of fuels more easily than

other cogeneration technologies, including coal,

biomass, and solid wastes, as well as coal-derived

liquids and gases when they become available.

Open-cycle combustion turbine topping cycles

(see fig. 3) have a higher E/S ratio and produce

higher temperature steam than steam turbines.

Therefore, combustion turbines can meet the

electric and thermal needs of more types of industries and are more likely to produce excess

electricity that may be exported to the grid. Combustion turbines’ unit cost and construction time

are relatively low while their reliability is comparable to that of steam turbines. Combustion turbines are available in a wider range of unit sizes

than steam turbines, and the lower capacity units

(i.e., below 7 MW) may be attractive for commercial facilities (such as shopping centers, apartments, hotels) because they are small in size and

can be operated remotely. Combustion turbines

also are well suited to arid climates because they

require no cooling water. Finally, although opencycle combustion turbines cannot now use solid

fuels such as coal or wood directly, they will be

able to use synthetic gas or liquid fuels derived

from coal or biomass, and units using pulverized

wood directly are under development.

Combined-cycle cogenerators (combined

steam turbine and combustion turbine systems;

see fig. 5) increase electric power output at the

expense of recoverable heat. They have a higher

E/S ratio than either a steam or combustion turbine alone, and thus will be most attractive in

situations where electricity requirements are relatively high, or where electric power can be distributed to the grid economically. Their unit capacity also tends to be greater than either of the

separate turbine systems. Currently available

combined-cycle systems require too much space

for most commercial applications, but they should

be well suited to larger industrial facilities. Their

unit cost and installation Ieadtime are higher than

combustion turbines’, but comparable to medium- or large-size steam turbines. Furthermore,

while combined cycles’ availability is lower than

either system alone, their overall fuel efficiency

is higher. Finally, combined cycles can use the

full range of fuels and will be readily adaptable

to fluidized bed combustion systems.

Diesel cogenerators (see fig. 3) have a higher

E/S ratio than the technologies described above,

and thus will be very attractive for facilities with

high electricity demand but low thermal energy

needs (i.e., most commercial building applications and many smaller industries), or where electricity can be distributed to the grid economically.

Diesels’ relatively high efficiency, low cost, short

installation Ieadtime, long service lifetime, and

established service infrastructure all contribute

to their attractiveness. However, diesels also can
Ch. Z—Issues and Findings ● 29

Figure 5.—Schematic of a Combined-Cycle Cogenerator

Mechanic~inefficiency Generator 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 less

acceptable environmentally due to their potentially high nitrogen oxide and particulate emissions. In addition, currently available diesel technologies must burn oil or gas (some are dualfueled), although they will be able to use synthetic fuels. Diesels capable of burning powdered

coal or coal slurries are under development, but

it is unclear whether they will be economically

competitive with other types of cogenerators.

Rankine steam bottoming cycles (see fig. 4) are

conceptually different from the technologies summarized above in that high-temperature process

heat is produced first, then waste heat from the

thermal process is used to produce electric or

mechanical power plus additional lower temperature thermal energy. Because waste heat is used

to generate electricity, Rankine bottoming cycles

can present even greater fuel savings than topping cycle cogenerators. The cost, average annual availability, and construction Ieadtime of

Rankine steam bottoming cycles are comparable

to steam turbines, while their expected service

life is approximately equal to combustion turbines, combined cycles, and diesels. Unit capacity, however, often is smaller than other cogeneration systems. Rankine steam bottoming cycles

typically are considered for industrial applications

with very high-temperature heat needs.

WHAT ARE SOME PROMISING FUTURE

COGENERATION TECHNOLOGIES?

Current research and development efforts on cumstances Are Available Cogeneration Technolcogeneration are directed toward both improve- ogies Attractive?”) and the development of new

ments 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 than

oil and gas (e.g., coal, biomass, solid waste), improved fuel efficiency, increased electrical output, and lower capital and operating costs (see

ch. 4).

Advanced steam turbine cogenerators with

higher steam pressures and temperatures, and

thus greater electric generating efficiency, should

be available between 1985 and 1990. Much of

the research on steam turbines is aimed at improving the efficiency of smaller systems (less than

7 MW), while reducing their cost. Similarly, research on open-cycle combustion turbines is directed toward increasing efficiency through

higher inlet temperatures by improving turbine

blade cooling or making materials changes in

blade composition. Materials changes also would

improve the anticorrosive properties of turbine

blades and thus would allow combustion turbines

to use solid fuels (municipal solid waste, pulverized coal, etc.). However, as with steam turbines,

capital and operating costs for advanced combustion turbines are likely to be slightly higher

than present costs. Improvements in combinedcycle systems include the advances in combustion turbines, as well as the development of

smaller combined cycles with a wider range of

potential applications. Finally, advanced diesel

cogenerators are being developed that use coalderived fuels, and have a much greater power

output, as well as those for which all the recovered thermal energy could be high-quality steam.

Each of these improvements in the diesel cogenerator should be commercially available by 1990,

but not all in the same system.

Advanced cogeneration technologies that are

not now available commercially include closedcycle combustion turbines, organic Rankine bottoming cycles, fuel cells, and Stirling engines (see

table 1 and ch. 4). (Solar cogenerators, such as

the therm ionic topping system, are not discussed

in this report.)

Closed-cycle, externally fired combustion turbines are not available commercially in the

United States but are well developed in Europe

and Japan. These systems are potentially very attractive because they can use a wide variety of

fuels (including coal), have a relatively high efficiency and E/S ratio, and should be priced competitively with other topping cycle cogenerators.

They will be attractive primarily in larger industrial

and utility applications.

Organic Rankine bottoming cycles evaporate

organic working fluids (e.g., toluene) to produce

shaft power, and can operate efficiently at lower

temperatures and in smaller sizes (i.e., 2 kW to

2 MW) than steam bottoming cycles. Because

they use lower temperature heat, they can be

adapted to a wide variety of heat sources, including solar, geothermal, and industrial waste heat,

or engine exhausts. However, they currently require more maintenance than most topping cycles, and further development and demonstration are necessary before the organic Rankine

bottoming cycle can be considered a “mature”

technology.

Fuel cells (electrochemical devices that convert the chemical energy of a fuel directly into

electricity with no intermediate combustion cycle

—see fig. 6) are potentially attractive cogenerators

due to their modular construction, good electrical-load-following capabilities, automatic operation, ability to use coal-derived fuels, and low

pollutant emissions. In addition, fuel cells could

be adapted to a wide range of sizes and applications, from small (40 to 500 kW) residential and

commercial systems to larger industrial and utility

plants (5 to 25 MW). Although fuel cell demonFigure 6.—Fuei Cell

Hydrogen-rich gas and C02

from shift converter

1

Porous

anode

( - )

Electrolyte

(phosphoric

acid)

Porous

cathode

(+)

Operation

C02 and unreacted

hydrogen
Ch. 2—Issues and Findings ● 31

stration plants are under construction, commercial readiness is still at least 5 years away. The

primary development concerns include somewhat high capital costs and short service life.

Finally, Stirling engines (see fig. 7) could offer

an attractive alternative to available topping cycles because of their ability to use coal and other

solid fuels, their high thermal and part-load efficiency, and their low emissions, noise, and vibrations. Stirling engines also could be used as components of solar energy systems or as adjuncts

to fluidized bed combustors, nuclear reactors, or

other conversion technologies. Current research

efforts are directed toward improved efficiency

and solid fuel combustion characteristics, as well

as lower capital costs, before Stirling engines can

be considered commercial. Because they produce relatively low-temperature recoverable

heat, Stirling engines will be most attractive for

water heating or in facilities with relatively small

process heat requirements.

In addition to the cogeneration technologies

reviewed above, two types of advanced combustion systems may be attractive for increasing cogenerators’ fuel flexibility: gasifiers and fluidized

bed combustors. Gasifiers would convert coal,

pet coke, or other solid fuels to medium-Btu gas

(about 300 Btu/standard cubic foot) for distribution to cogenerators (or other facilities) within

about a 100-mile radius. Gasification could centralize the use of solid fuels, and thus eliminate

cogenerators’ need for coal storage and handling

facilities. However, gasification is not yet a proven technology, although both small- and largescale systems are being demonstrated. Whether

such a scheme will be successful is heavily deFigure 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, June

1978).

pendent on the capital costs, which are still highly

uncertain. Fluidized bed combustors can accommodate a wide range of solid fuels, and operate

at a lower temperature and pose fewer environmental and operating problems than conventional boilers. Fluidized beds can be adapted to fire

several different types of cogeneration technologies. Atmospheric fluidized bed systems could

be used with steam or combustion turbines or

combined cycles, while pressurized systems could

drive combustion turbines or combined cycles.

Fluidized bed combustors are now being demonstrated and could become commercial within a

few years.

WILL COGENERATION BE COMPETITIVE WITH CONVENTIONAL

THERMAL 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 Save

energy technologies when it can use relatively oil?”). Moreover, the price gap between oil/gas

inexpensive, plentiful fuels, and where there are and other fuels is likely to become wider over

large thermal energy needs or it can meet on- time. Therefore, cogenerators will have to use

site energy needs while supplying significant relatively inexpensive and plentiful fuels (such

amounts of electricity to the utility grid. as coal, biomass, or solid wastes) in order to be
32 ● Industrial and Commercial Cogeneration

economically competitive with utility generating

capacity over the long run (10 to 20 years and

beyond). Alternatively, if the utility’s avoided cost

is determined by the price of oil, or if the utility

is primarily dependent on oil-fired capacity, then

natural gas may remain economically attractive

as a cogeneration fuel for several years. In the

short term, it is possible that cogenerators may

be able to rely on natural gas as a transition measure until synthetic gas from coal or biomass becomes widely available at a competitive price.

However, if gasifier technology or planned advances in the fuel flexibility of cogeneration technologies are not available as soon as expected,

or synthetic gas is not competitive in price with

natural gas, this strategy could lock cogenerators

into premium fuel use for many years.

For cogeneration to be economically attractive, there usually must also be substantial thermal loads. Sites with low loads (e.g., less than

50,000 lb/hr of steam) due to conservation measures or limited process needs, or with fluctuating

loads, generally would not be economically competitive with conventional steam boilers and utility-supplied electricity. Thus, commercial buildings are likely to have a low potential for

cogeneration because of their very low thermal

load factors. In some cases, however, cogenerators can be “undersized” and operated at a high

capacity factor to meet the base thermal load,

with conventional boilers or furnaces used when

necessary to meet the remaining thermal demand

(see, “What Are the Opportunities for Cogeneration in Commercial Buildings?”).

Finally, cogeneration’s ability to meet onsite

thermal and electrical needs, or to meet the

thermal needs and supply significant amounts

of power to the utility grid, will be a major determinant of its economic competitiveness. In the

regions where electric utilities have substantial

amounts of generating capacity fueled by oil or

natural gas, or where demand growth is significant (primarily the Northeastern States and California, and to a lesser extent the South Atlantic

and West South-Central States), cogeneration will

be more attractive when it can supply significant

amounts of electricity to the grid (see, “What Are

the Potential Effects of the PURPA Incentives?”).

Alternatively, if the utility has substantial excess

capacity or primarily uses coal or other nonpremium fuels, and avoided costs are low or retail

electricity rates are high, a cogenerator’s economic competitiveness will depend primarily on

its ability to reduce onsite energy costs.

These determinants of cogeneration’s economic competitiveness will affect the choice of cogeneration technologies. Of the technologies that

are commercially available, only the steam turbine topping and Rankine cycle bottoming systems can use fuels other than oil/gas. However,

bottoming cycles usually are limited to specialized applications that require high-temperature

heat, while steam turbines have low E/S ratios

(see, “Under What Circumstances Are Available

Cogeneration Technologies Attractive?”). Systems

with higher E/S ratios that will be able to use alternate fuels are under development or demonstration, as are advanced combustion technologies

such as fluidized beds and gasifiers, and should

be available commercially by the mid to late

1980’s (see, “What Are Some Promising Future

Cogeneration 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 about

generation 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 for

2), and at least 3,300 MW in the planning stage which an investment is likely to be made) is much

or under construction. The technical potential lower due to economic and institutional considfor industrial cogeneration (the number of sites erations.
●

●

●

●

versions of existing process technologies

now under development will have greater

fuel flexibility, higher fuel efficiency, and

higher electricity output.

Whether cogeneration retrofits are feasible

or new plants will be built: For instance,

petroleum refineries are well suited to cogeneration, and some existing refineries could

be upgraded, resulting in the production of

low-Btu gas suitable for onsite cogeneration.

But, few new refineries are likely to be built

except in areas such as California, which has

special requirements related to enhanced oil

recovery.

Whether a plant’s operating pattern makes

cogeneration economic: Many food processing plants operate only during harvest season, and the resulting low capacity factor

may make cogeneration economically infeasible. However, the food processing season

often overlaps the hottest months when irrigation and air-conditioning loads contribute

to peak demands on electric systems in rural

areas, the seasonal price for utility generated

power is often very high and/or its reliability

is low. As a result, this industry’s seasonal

operating pattern can be outweighed by its

potential for lower energy costs.

The availability of capital for investments

in cogeneration: Industrial firms typically require shorter payback periods for their investments than cogeneration may be able to

provide, although current accelerated depreciation measures and investment and energy

tax credits can improve the payback significantly. Cogeneration also must compete for

available capital with process equipment or

other investments that improve an industry’s

competitive position (as well as with conservation measures, as mentioned above).

Third-party or utility ownership can improve

capital availability (see, “Who Will Own Cogenerators?”), as can low interest loans and

other financing measures that alleviate the

effects of high interest rates and capital

shortages.

Whether there is a match between a plant’s

needs and the cogenerator’s output: An industry may need more or less thermal or
34 . Industrial and Commercial Cogeneration

●

electric energy than a cogenerator provides.

usually the technology will be chosen to optimize the match between load and output,

but this will not always be possible. The Pub

Iic Utility Regulatory Policies Act (PURPA) requirements that electric utilities offer to buy

power from and sell power to cogenerators

can mitigate an electricity supply and demand mismatch, but the economics may not

always be favorable to the cogenerator (see,

“What Are the Potential Effects of the PURPA

Incentives?”). In some cases, industrial parks

with central cogenerators and shared energy

products through dedicated distribution systems may be an attractive solution to thermal and electric supply/demand mismatches.

Regulatory uncertainty and perceived risks:

Doubt about the continued availability of the

economic and regulatory incentives offered

by PURPA, the fuel use and pricing provisions of FUA and the Natural Gas Policy Act,

and the various tax incentives for investment

in cogeneration (e.g., investment and energy

tax credits, accelerated cost recovery, safe

harbor leasing) can be a significant deterrent

to investment in cogenerators. Similarly, uncertainty about interest costs and capital

availability, fuel costs, investment payback

periods, the use of solid fuels, and environmental regulation can be disincentives to the

implementation of cogeneration projects.

All of the above factors could lead industrial

managers to adopt a “wait-and-see” attitude toward cogeneration. As a result, widespread deployment of industrial cogeneration capacity

could be delayed a decade or more. But the resolution of legal and regulatory uncertainties, the

rapid development and demonstration of advanced technologies that can burn solid fuels

cleanly, and lower interest rates or innovative

financing and ownership arrangements could

substantially improve industrial cogeneration’s

market potential. In addition, if natural gas prices

are seen to be lower than distillate for an extended period—lo to 20 years—an industry might

decide it is worth the investment risk if their purchase power rates are based on oil.

WHAT ARE THE OPPORTUNITIES FOR COGENERATION

IN COMMERCIAL BUILDINGS?

Although the opportunities for cogeneration in

commercial buildings depend on the same general factors as industrial cogeneration—thermal

energy demand, availability of capital, competition with conservation, capability of using nonpremium fuels, etc. —there are characteristics

about buildings that constrain cogeneration more

than in industry.

In the near term–the next 10 to 15 years–commercial cogeneration will be fueled predominantly by natural gas. Coal-fired units can be

used but these will be limited because of the difficulties of handling and storing coal in and

around commercial buildings. Therefore, the

principal determinants for commercial cogeneration for the near term will be the price and

availability of natural gas, and either the price

of electricity from central station units or the

price that utilities will pay for electricity from

cogenerators as set by their public utility commissions. For those regions where the latter is set at

or near the price of oil-fired electricity and the

utilities have oil or natural gas fueled capacity,

commercial cogeneration fueled by natural gas

has a promising market even if natural gas prices

should approach those of distillate fuel oil. The

primary advantage of commercial cogeneration

in these cases is that it allows rapid development

of new capacity to meet new demand and/or to

replace the utility’s oil-fired capacity.

Under least cost conditions, cogenerated electricity will be produced and sold when it is less

expensive than central station electricity (see,

“Will Cogeneration Be Competitive With Conventional Thermal and Electric Energy Systems?”).

Net fuel savings by cogeneration compared to

separate production of electricity and heat, however, may be less than that indicated by the
Ch. 2—Issues and Findings ● 35

amount of electricity sold because of the very low

thermal load factors of commercial buildings. The

most promising arrangement for commercial

buildings probably would be to undersize the

cogenerator and operate it at a high capacity

factor to meet the base thermal load, and use

conventional thermal energy systems when necessary to meet the remaining load. This allows

a high degree of heat recovery and efficient capital utilization. Alternatively, the diversity added

by using several buildings for heating loads could

greatly increase net fuel savings. This also means

that buildings located in regions with high thermal loads (about 6,000 degree days or higher per

year) will be the most attractive candidates for

cogeneration.

However, in both the near and long term,

commercial cogeneration will compete with

conservation-especially in new buildings. Conservation will very likely be more economic than

cogeneration for most of the Nation’s buildings.

Further, the more efficient a building is, the lower

its thermal demands and the less attractive cogeneration becomes. This is particularly significant

when capital is scarce. Utility ownership may be

one way of reducing the severity of the latter concern (see, “Who Will Own Cogenerators?”).

For the longer term, beyond 10 years, commercial cogeneration ultimately must compete

with new coal-fired or, possibly, nuclear capacity. It is unlikely that natural gas-fired cogeneration will be able to compete economically with

new coal-fired central station capacity—even with

byproduct credit for displacing natural gas for

space heating—unless natural gas prices stay well

below distillate oil. This is not likely to be the case

toward the end of the century as supplies of conventional natural gas diminish. Where electricity

growth rates are high (greater than 2 percent per

year) and thermal demands are high (6,000 degree days or higher per year), however, natural

gas-fired commercial cogeneration, even at high

gas prices, could be competitive for new intermediate and peaking electric loads or for cases in

which coal use is limited.

Cogeneration directly fired by coal with new

technologies, such as fluidized bed combustion,

or indirectly through low-Btu gasification and

combined-cycle systems, could compete with

new central station coal capacity (see, “What Are

Some Promising Future Cogeneration Technologies?”). Some current analyses indicate that this

will be so, but the OTA analysis of synthetic fuels

for transportation shows that there is considerable

uncertainty with respect to cost of synfuels production (6). Other promising possibilities are

combined-cycle systems fired by biomass or solid

waste gasifiers. These new technologies do not

eliminate the coal or biomass handling problem,

however, which will still act to inhibit cogeneration.

Finally, environmental considerations are likely to be more important for commercial buildings than for other cogeneration applications.

This is due in part to the potential for increased

emissions with the technologies that are most

suited to commercial building applications, and

in part to the inherent characteristics of the urban

environment (e.g., proximity of buildings to each

other, urban meteorology; see, “What Are the

Environmental Impacts of Cogeneration?”).

WHAT ARE THE INTERCONNECTION REQUIREMENTS

FOR COGENERATION?

In the past, electric utilities and the agencies into the grid. These “two-way” power flows have

that regulate them have only been concerned raised concerns about the technical and safety

with power flows from the central grid to cus- aspects of interconnection and integration with

tomers, or from one utility to another. However, the grid, about liability for any damage that may

the economic and other incentives offered to co- result from improper interconnection, and about

generation under Federal (and some States’) law the costs of the equipment needed for proper inassume that cogenerators may feed power back terconnection and integration. OTA found that
36 ● Industrial and Commercial Cogeneration

most of the technical aspects of interconnection

and integration with the grid are relatively well

understood, although some electric utilities still

have reservations. Rather, the primary issues re

Iated to interconnection are the costs of the

equipment and the utilities’ legal obligation to

interconnect.

The technical aspects of interconnection about

which utilities are concerned include maintaining power quality, metering cogenerators’ power

production and consumption, and controlling

utility system operations. Power supplied by cogenerators to the grid must be within certain tolerances so that the overall utility system power

quality remains satisfactory and utilities’ and customers’ equipment will function properly and not

be damaged. In order to maintain power quality,

grid-connected cogenerators may need capacitors to keep voltage and current in phase, over/

under relays to disconnect the generator if its

voltage goes outside a certain range, and a dedicated distribution transformer to isolate voltage

flicker problems. However, the power quality effects of interconnected cogenerators often are

technology- and site-specific, and not all systems

will need all of this equipment. in particular,

smaller systems (under 20 kW) may have few or

no adverse effects on power quality and may require only limited interconnection equipment.

Larger systems probably will already have dedicated transformers, and would only need capacitors to correct power factor if they use induction

(as opposed to synchronous) generators.

Cogenerators’ power production and consumption must be metered accurately in order

to collect data for better understanding their contribution to electric system loads, and thus for determining how to price buyback and backup

power. Two standard watthour meters can be

used, with one operating normally to measure

electricity consumption and the other running

backwards to indicate production. Alternatively,

more advanced meters are available that indicate

not only kilowatthours used/produced, but also

power factor correction and time-of-use. Although an advanced meter provides more useful

data, it also costs about five times more than two

standard watthour meters. Whether cogenerators are given a choice between standard and

advanced meters and, if not, whether the utility

or the cogenerator pays for the advanced meter,

varies among utilities.

Utilities also are concerned about cogenerators’

effects on their ability to control utility systems

operations, including the possibility that large

numbers of cogenerators (or small power producers) would overload system dispatch capabilities,

and would contribute to unstable power systems.

Although very large cogenerators might be dispatched by a central utility control center (and

thus require connection via expensive telemetry

equipment), most utilities will treat cogenerators

as “negative loads” by subtracting the power produced by the dispersed generators from total system demand, and then dispatching the utility’s

capacity to meet the reduced demand. Studies

of such negative load treatment indicate that it

should work well where the total capacity of the

cogenerators is limited compared to the overall

system capacity. However, additional research

is needed on the effects of large numbers of

cogenerators on system stability. The primary

concern with a significant system penetration of

cogenerators is their ability to remain synchronized with the system following a disturbance.

Without proper interconnection measures,

large numbers of cogenerators also might pose

hazards to worker safety during repairs to transmission and distribution lines. First, dispersed

generators will need to locate their disconnect

switches in specified areas in order to simplify line

workers’ disconnect procedures. Second, induction (and, very occasionally, synchronous) generators must guard against self-excitation either

by using voltage and frequency relays and automatic disconnect circuit breakers, or by locating

their power-factor correcting capacitors where

they will be disconnected with the cogenerator

or where they can be isolated easily by line

workers. Therefore, while proper interconnection must be ensured in order to protect utility

workers’ safety, none of the necessary precautions is difficult to implement.

The cogenerator usually is liable for accidents

or damage to equipment resulting from improper

interconnection or operation. The utility may include 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 a

condition of the contract between the utility and

cogenerator. However, in some cases, requirements for both insurance and protective equipment may be redundant and place an excessive

cost burden on the cogenerator.

The cost of interconnection varies widely depending on the size and type of cogenerator,

the equipment already in place, and the utility’s

or State regulatory commission’s requirements.

Few guidelines have been published (although

several are being prepared) and some utilities or

commissions may require more equipment than

described above in order to provide extra protection for their system and their other customers.

In addition, the quality of equipment required (industrial or utility grade) can affect the cost substantially. Most utility engineers agree that the less

expensive industrial grade should be adequate

for smaller cogenerators, but specifications of the

cutoff range from 200 to 1,000 kW. Finally, costs

will depend on the amount of equipment that is

already in place (e.g., dedicated transformers)

and on the adequacy of existing distribution lines.

Based on published studies, OTA estimated two

sets of interconnection costs for three sizes of

cogeneration systems: a “base case” that assumes

that much of the equipment is already in place

or not required (e.g., capacitors, dedicated transformers, protective relays), and a “worst case”

that assumes this equipment must be purchased

(see table 3). Most of the cost difference between

the two cases results from the addition of a dedicated transformer, and from the use of more expensive relays and other protective devices.

Moreover, these estimates indicate that there are

significant economies of scale in interconnection

costs.

The Federal Energy Regulatory Commission’s

(FERC) rules implementing section 210 of PURPA

originally specified that “any electric utility shall

make such interconnections as may be necessary

to accomplish purchases or sales” of cogenerated

power. However, this rule recently was overturned by the U.S. Court of Appeals on the

grounds that it is inconsistent with other parts of

PURPA that provide for individual FERC orders

requiring interconnection after the opportunity

for a full evidentiary hearing in accordance with

the Federal Power Act. Thus, if cogenerators cannot get a utility to agree to interconnect with

them, they will have to meet the multiple stringent legislative tests of the Federal Power Act,

which will be very difficult, expensive, and timeconsuming for the cogenerator.

Table 3.—interconnection Costs for Three Typical Systems

50 kW 500 kW 5MW

Equipment Best Worst Best Worst Averaae

Capacitors 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 12,500

80 1,000 80 1,000

600 600 600 600

300 300 1,400 1,400

620 620 4,200 4,200 — — 2,600 2,600

600 1,100 600 1,100 — 3,500 – 3,500

$2,600 $13,020 $11,080 $32,900

52 260 22 66

$1,:00

40,000

1,000

600

3,000

5,000

2,600

1,100

3,500

$57,800

12

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

calculations.

SOURCE: Office of Technology Assessment calculations based on data derived from Howard S. Geller, The /interconnection

of Cogenerators and Small Power Producers to a Utility System (Washington, D. C.: Office of the People’s Counsel,

February 1982).
38 . Industrial and Commercial Cogeneration

WHO WILL OWN COGENERATORS?

Cogenerators might be owned by industrial,

commercial, or other users, by utilities, by third

parties, or by some combination of these (joint

ventures). Each of these forms of ownership has

relative advantages and disadvantages for financing, taxation, operating characteristics, and regulatory considerations.

The energy and investment tax credits, coupled

with the economic and regulatory incentives instituted by PURPA, encourage private firms (e.g.,

industrial facility and commercial building owners) to cogenerate. The PURPA requirement that

utilities purchase electricity from, and sell it to,

cogenerators, and the provision that exempts cogenerators from regulation as electric utilities, removed the primary institutional and economic

obstacles to private ownership of cogeneration

capacity. PURPA also encourages the development of contractual relationships between private

owners and electric utilities—often a prerequisite

for obtaining attractive financing. Long-term contracts can establish a purchase rate based on the

utility’s avoided costs either at the time of the

contract or at the time power is delivered to the

utility, or the cogenerator and utility can negotiate

a price independent of avoided cost considerations. PURPA incentives are augmented by private owners’ ability to earn up to 20 percent tax

credits for investment in cogenerators through

the end of 1982, and 10 percent thereafter, which

offers a boost to cash flow early in a project’s life.

Finally, user ownership generally would provide

the greatest control over the cogenerator’s energy

output. However, industrial and commercial

firms’ willingness to invest in cogeneration will

be influenced heavily by the cost of capital (often

higher than the cost to utilities or many third-party

investors), the need to invest in process equipment or other items that will contribute to a firm’s

competitive position, and the availability of less

costly conservation measures.

Investor-owned electric utilities and their subsidiaries are logical potential owners of cogeneration capacity because electricity generation is

their primary business. Ownership of cogenerators would enable the electric utility industry to

provide a wide range of energy supply options

and not just to facilitate their development by

other parties. Moreover, utility ownership would

reduce the potential for revenue losses from the

development of generating capacity by nonutilities, while providing an additional revenue

stream from thermal energy sales. Direct utility

ownership (i.e., not utility subsidiaries) also could

result in lower generation costs to be passed on

to consumers because the avoided cost would

become the lower of the cost of cogenerating or

of providing electricity from alternate sources

(see, “What Are the Potential Effects of the

PURPA Incentives?”). In addition, utilities are

more likely to choose technologies that have high

E/S ratios and that can accommodate coal or

other alternate fuels (e.g., with gasifies). As a

result of all these considerations, cogeneration’s

market potential in general, and its ability to

supply large amounts of electricity to the grid

in particular, are likely to be enhanced substantially under utility ownership.

However, current Federal policy toward cogeneration discourages full utility ownership. First,

PURPA incentives are not available to cogenerators in which utilities own more than a 50-percent

interest. Allowing 100-percent ownership would

mean that utilities could earn a higher rate of

return on unregulated cogeneration capacity than

on their regulated central station capacity, and

would compensate utilities more fully for accepting the business risks of investment in generating

equipment over which they have little control

(e.g., strikes, plant closings, or fuel interruptions

at the cogeneration facility). Second, utility property is not eligible for the energy tax credit, and

thus utilities would not gain the same cash flow

advantages as private investors. Removing these

disincentives would allow electric utilities to compete on at least an equal basis with other potential owners, and may give utilities a competitive

advantage, and thus could substantially increase

cogeneration’s market potential.

However, full utility ownership raises concerns

about competition and potential economic distortions. Utilities could favor their own (or their subsidiaries’) projects through the duration or other

terms of the purchase power contract, the inter-
Ch. 2—issues and Findings . 39

connection requirements, or the priority for contracting. There is also a potential for utilities to

cross-subsidize cogenerators through their other

operations, making it difficult for private owners

to compete, or for utilities to favor particular models and thus stifle competition among vendors.

Each of these concerns can be dealt with either

through carefully drafted legislation and regulations, or through careful review of utility ownership schemes by State regulatory commissions.

Publicly owned utilities also are logical candidates for investment in cogeneration capacity.

Most publicly owned electric utilities purchase

all or some of their power from the grid. investment in cogeneration capacity would enable

them to add a new source of municipal revenue

while increasing the reliability of their power supply. Moreover, many existing small municipal

powerplants are sitting idle due to their high operating costs relative to the cost of grid-supplied

power. These small plants could be retrofitted for

cogeneration and the thermal energy used to

meet local needs for such processes as grain drying or ethanol production. Municipal utilities also

have advantages in financing because they are

tax-exempt and so is the interest paid on their

obligations.

Finally, joint ventures among any of the types

of owners listed above or with third-party investors will be attractive, primarily due to the tax advantages. If the primary investor cannot take advantage of tax benefits such as credits or accelerated depreciation (e.g., because the investor is

tax-exempt or has a low tax liability), the cogeneration equipment can be sold to another party

for tax purposes only and leased back to the cogenerator or other owner.

WHAT ARE THE POTENTIAL EFFECTS OF

THE PURPA INCENTIVES?

PURPA extends several important incentives to

qualifying cogenerators (and small power producers). These include exemptions from electric utility or utility holding company regulation under

Federal and State law and from some Federal fuel

use and pricing regulations; incentive rates for

sales of cogenerated electricity to the grid, and

nondiscriminatory rates for purchases of backup

or supplementary power from the grid; and special provisions on interconnection, and on wheeling of cogenerated power. All of these incentives

are important because they could remove longstanding regulatory and economic barriers to onsite electricity generation. However, the rate provisions of PURPA are likely to have the most important impacts.

PURPA requires electric utilities to purchase

power from cogenerators at a rate that does not

exceed “the incremental cost to the electric utility

of alternative electric energy.” This is termed the

utility’s avoided cost, and is measured by the savings to the utility in not generating the power itself

or purchasing it from the grid. Avoided cost rates

are based on a cogenerators’ contribution to

power supply or peak load during daily or seasonal peak demands (including the reliability of that

contribution from the utility’s perspective); a

credit for capacity and/or energy if the cogenerator enables the utility to defer new construction

and decrease oil/gas use; and any costs or savings to the utility in transmission and distribution.

The level at which avoided cost rates will be

set is uncertain at this time. The original FERC

rules implementing PURPA provided for purchases of cogenerated power at 100 percent of

the utility’s avoided cost. This provision was challenged successfully on the grounds that PURPA

established the full incremental cost as a rate ceiling, and that FERC had not adequately justified

their choice of the highest permissible rate when

a lower rate would share the economic benefits

of cogeneration with the utility’s ratepayers. FERC

is appealing this ruling, but it may be months

before a final decision is available and the regulations are rewritten, if necessary.

Regardless of whether the rates for purchases

of cogenerated power are set at 100 percent of
40 . Industrial and Commercial Cogeneration

avoided costs or less than 100 percent, these

rates will vary widely regionally. In most cases,

only those utilities that are heavily dependent on

oil or gas, have a declining reserve margin, or are

anticipating relatively high peak demand growth

(e.g., 3 percent per year or greater) will have sufficiently high avoided costs to make grid-connected cogeneration an attractive investment (see

table 4). Therefore, PURPA rate provisions are

most likely to be an incentive to cogeneration in

the New England States (especially Massachusetts, Rhode Island, New Hampshire, and Connecticut); the Mid-Atlantic States (particularly

New York, New Jersey, and Delaware); the

Southern and South-Central States of Florida,

Mississippi, Arkansas, Louisiana, and Texas; and

the State of California and the Pacific Northwest.

However, in each area, PURPA avoided cost

incentives may be reduced by such factors as

utility plans to convert to less costly generating

capacity, or by conservation measures that reduce the rate of peak demand growth. Thus, if

peak demand growth rates are not so high as

those presented in table 4, then reserve margins

would be higher than shown and avoided costs

would be lower. Where avoided costs are low,

a cogenerator may deliver its electricity to a more

distant utility that would have higher avoided

costs, if the local utility agrees to transmit the

power.

PURPA economic incentives also can have important impacts on electric utilities and their customers—especially if cogenerated power is priced

at 100 percent of the utility’s avoided cost. Because the avoided cost rate is based on the cost

to the utility of alternative electric power, the

price of electricity for non-cogenerating customers should not be any higher than it would be

if the utility did not make avoided cost payments

to cogenerators (unless the State has established

rates higher than the full avoided cost). However,

neither will the price to those customers be any

lower under 100-percent” avoided cost rates (except in those cases where utilities negotiate a contract price for cogenerated power that is less than

the full avoided cost).

Moreover, even though utilities should treat cogenerated power as part of their overall capacity,

they will not earn a rate of return on cogeneration equipment unless they own it. Under PURPA,

cogenerators that are more than 50 percent utility-owned are not eligible for PURPA economic

and regulatory incentives. If utilities could own

cogeneration capacity outright and still benefit

from those incentives, the avoided cost could

become equivalent to the cost of cogenerated

electricity or the cost of alternative power—

whichever is lower. If the cost of cogenerated

power were lower, utilities could pass this savings on to their non-cogenerating customers,

while still earning a higher rate of return on unregulated cogenerators than the regulated return

on their conventional capacity. Therefore, removing the ownership limits in PURPA could act as

an incentive to utility investment in cogeneration,

and thus increase the technology’s market potential. However, utility ownership also raises concerns about possible anti-competitive effects (see,

“Who Will Own Cogenerators?”).

WHAT ARE THE POTENTIAL ECONOMIC IMPACTS

OF COGENERATION ON ELECTRIC UTILITIES?

Cogeneration could have either beneficial or

adverse economic impacts on electric utilities

and their customers, depending on the choice

of cogeneration technologies, their fuel use, and

the type of utility capacity they might displace;

on who owns the cogenerators; on the systems’

operating characteristics; and on the price paid

by utilities for cogenerated power. These potential impacts include decreased (or increased) costs

of constructing and operating electric generating

capacity, increased (or decreased) employment

associated with electricity supply, and a decreased (or unchanged) rate of growth in electricity rates.

In order to gauge the potential magnitude of

these economic impacts if cogeneration achieved

a 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 1991-2000

Northeast . . . . . . . . . . . . . . . . .

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

45.4

16.0

38,3 —

80.0

75.4

44.8

38.0

17.4 —

44.5

59.4

15.5

39.5 —

—

—

47.9

—

37.7

4.9

23.8

100.0 —

—

—

10.7

4.8 —

—

—

1.6 —

—

—

—

—

5.3 —

27.0

17.7

15.7 —

—

—

—

—

—

—

40.6 —

52.9 —

—

—

—

24.1 —

—

2.1 —

10.5 —

4.9 —

—

—

—

16.0 —

—

30.6 —

—

—

—

—

—

—

—

2.9 —

—

—

2.4 —

—

—

—

—

70.4

41.1

82.9

15.5

82.3

73.2

14.4 —

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 Electric

lnstltute,1981~ and North Amerlcan Electrlc Rellabillty council, Electrlc Power Supply and Demand, 1981-1990 (Princeton, N.J; North American Electric

Reliablllty Council, July 198l)
42 . Industrial and Commercial Cogeneration

six scenarios of cogeneration use that postulate

penetrations of 50,000, 100,000, and 150,000

MW of cogeneration capacity by 2000 with two

different technology mixes. We then compared

the capital requirements, operation and maintenance (O&M) costs, and construction and O&M

labor needs for these scenarios to those for installing an equivalent amount of central station baseIoad and peaking capacity (using two mixes for

baseload capacity–loo percent coal and SO/SO

coal and nuclear). In this comparison, OTA found

that:

●

●

●

●

capital requirements for cogeneration varied

from around 95 percent less to about 25 percent more than the capital requirements for

an equivalent amount of central station capacity;

O&M costs for cogeneration ranged from approximately 75 percent less to about 95 percent more than the O&M costs for central

station generation;

construction labor requirements for cogeneration varied from around 45 percent less

to approximately 70 percent more than those

for constructing an equivalent amount of utility capacity; and

O&M labor requirements, measured in

work-hours per megawatthour, varied much

more widely (e.g., 10 to several hundred

times greater labor needs for cogeneration

than for central station capacity).

In generaI, the wide variations in these results

can be attributed to the economies of scale in

the costs and labor needs for constructing and

operating cogeneration capacity. Thus, total estimated cogeneration capital requirements are, on

the average, lower than those for central station

capacity, but may be slightly higher if all the cogenerators were very small systems with a high

initial cost per kilowatt (e.g., 500-kW steam turbines, 75-kW diesels, 100-kW combustion turbines). Similarly, average estimated construction

labor requirements for cogeneration range from

about the same as those for installing conventional utility capacity to around so percent higher,

and could be even greater when the smallest cogenerators (that require more work-hours per

kilowatt of capacity) are installed. On the other

hand, construction labor requirements for cogeneration may be lower than those for central station utility capacity if the largest cogenerators are

used (e.g., 100-MW steam or combustion turbines, 30-MW diesels). For O&M costs, cogeneration tends to be more expensive for small systems

and those with a higher capacity factor, and less

expensive for large systems or those with a lower

capacity factor. Finally, the O&M labor requirements for cogeneration are the most uncertain,

primarily due to the lack of data in this area and

because the economies of scale are even more

pronounced.

Because the mean cost of cogenerated electricity tends to be lower than the marginal cost of

electricity from new central station capacity, cogeneration may have the potential to reduce the

rate of growth in retail electricity rates. That is,

if utilities installed cogeneration capacity, lower

costs would be passed on to their customers than

if they installed conventional capacity. However,

if utilities purchase cogenerated power at a rate

based on their marginal, or full avoided costs,

then the cost passed onto other customers would

be equivalent to the cost of alternative electricity

(i.e., either central station capacity or power supplied by the grid), and cogeneration would not

reduce retail electricity rates, (see, “What Are the

Potential Effects of the PURPA Incentives?”). Furthermore, where State regulatory actions provide

for purchases of cogenerated power at rates that

are even higher than full avoided costs (e.g.,

either because the State commission sets purchase power rates equivalent to the cost of oil

and the utility uses a mix of fuels, or when the

commission establishes an explicit subsidy rate),

non-cogenerating ratepayers will be subsidizing

cogeneration.
Ch. 2—Issues and Findings . 43

WHAT ARE THE ENVIRONMENTAL IMPACTS OF COGENERATION?

The primary environmental concern about cogeneration is the air quality impacts. In general,

cogeneration does not appear to offer automatic

air quality improvement or degradation compared to the separate production of electricity

and thermal energy (see table s). Rather, each

cogeneration application must be evaluated separately. Thus, cogeneration’s greater fuel efficiency—when considered by itself—appears to offer

a decrease in the total emissions associated with

electric and thermal energy production, but,

when evaluated in combination with the other

changes associated with substituting cogeneration for conventional energy systems (including

changes in the type of combustion equipment,

its scale, and the type of fuel), may actually lead

to an increase in total emissions.

Similarly, the location and technological characteristics of a cogenerator will affect ambient

pollution concentrations and pollution dispersion. Cogeneration usually involves shifting emissions away from a few central powerplants with

tall stacks to many dispersed facilities with lower

stacks. In many situations, this shift will lead to

local increases in annual average pollutant concentrations near the cogenerators. For urban cogenerators, total population exposure may in-

.

crease because the emissions sources have been

moved closer to densely populated areas. Also,

air quality under certain meteorological conditions (such as low-level inversions) may be worse

with cogeneration than with conventional separate electricity and thermal energy production.

On the other hand, in some situations the “worst

case” short-term pollutant concentrations caused

by cogenerators will not be so high as the worst

case concentrations associated with the facilities

they displace. Moreover, if a cogenerator replaces

several small furnaces or boilers then its air quality

impacts can be positive.

Industrial and large-scale commercial cogeneration systems using steam or combustion turbines do not appear to present significant air

quality problems in most situations. However,

if the substitution of these cogeneration technologies for separate electric and thermal energy

production also involves a switch from “clean”

to “dirty” fuels (e.g., from distillate oil to high

sulfur coal) then emissions could increase. Similarly, where a new steam or gas turbine cogenerator that primarily produces electricity is substituted for a new boiler or furnace, then the cogenerator could add significantly to local emissions.

Table 5.—Effect of Cogeneration Characteristics on Air Quaiity

Effect on air quality

Technological characteristic Direct physical effect (positive or negative)

Increased efficiency Reduction in fuel burned Positive

Change in scale (usually smaller for Change in pollution control Negative for electrica

electric generation, at times requirements (stringency Positive for heat

larger for heat/steam production) increases with scale)

Change in stack height and plume Negative for electric

rise (increases with scale) Positive for heat

Changes in design, combustion Mixed

control

Changes in fuel combustion Changes in emissions production, Mixed

technology required controls, types of

pollutants, physical exhaust

parameters

Change of fuels Change in emissions production, Mixed

type of pollutants

Change of location (most often for Change in emissions density and Mixed

electric generation) distribution—electric power more

distributed, heat/steam may

become 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.
44 . Industrial and Commercial Cogeneration

The use of diesel cogenerators (and gas-fired

spark-ignition engines), however, generally will

lead to increased levels of nitrogen oxide (NOX

)

emissions at the cogenerator site, even after accounting for the displaced emissions from the

separate electric and thermal energy sources.

Available controls can reduce diesel NOX emissions by nearly one-half, which mitigates but does

not eliminate this problem. Diesels also emit potentially toxic particulate, but conclusive medical evidence of harm is lacking at this time, and

the evidence that is available suggests that this

hazard may not be critical.

Cogenerators’ greater fuel efficiency can lead

to an important environmental benefit through

reduced exploration, extraction, refining/processing, and transportation of the fuel saved. However, this benefit is difficult to quantify and compare to the various air quality effects noted above.

Furthermore, this benefit usually will occur only

when the cogenerator uses the same fuel as the

conventional energy systems it displaces. That is,

if a fuel that is difficult to extract, process, and

transport (e.g., coal) is substituted for a “cleaner”

fuel (such as natural gas) the overall impacts may

be adverse rather than beneficial.

The air quality concerns reviewed above mean

that cogenerators—especially those in urban

areas—must be designed and sited carefully.

Most urban cogenerators are likely to be diesels

or gas-fired spark-ignition engines, both of which

have higher NOX emissions than the systems they

would replace. In urban areas with high NOX

concentrations, deployment of large numbers

of cogenerators without pollution controls and

careful siting could lead to violations of ambient

air quality standards and increased risks of adverse health effects. There is considerable potential to mitigate these problems through proper

site selection and engine design, and the use of

available NOX controls. For example, uncontrolled diesel NOX emissions may vary by as

much as a factor of 8 depending on the engine

model and manufacturer, so appropriate engine

choice alone might improve environmental acceptability significantly. However, there are no

Federal emission standards for stationary diesel

engines and the degree of risk from their deployment will depend on the effectiveness of State

and local air quality permitting and management.

Proper siting and design also are important

in avoiding the problems of “urban meteorology, ” or the effect of tall buildings on air currents and, thus, on pollutant dispersion. Urban

meteorology can cause plumes to downwash or

to be trapped and recirculated in the artificial canyons created by urban buildings, and can therefore result in very high local pollution levels during certain wind conditions. Proper design and

siting—especially ensuring that exhaust stacks

are taller than surrounding buildings—can avoid

air quality problems caused by urban meteorology. But the solutions may be costly in certain

circumstances (e.g., when adjacent structures are

much taller than the cogenerator’s building), and

may be ignored by developers unless there is a

strong State or local permit review process.

Although potential air quality impacts are the

primary environmental concern for cogeneration,

water quality, solid waste, noise, and cooling tower drift also may be important. Water pollution

can result from blowdown from boilers and wet

cooling systems, and runoff from coal piles and

from scrubber sludge and ash disposal. In urban

areas, these effluents may have to be pretreated

before discharge into the municipal treatment

system. in addition, sludge and ash disposal may

be a problem in urban areas due to the lack of

secure disposal sites. Noise is also primarily an

urban problem, but control measures are readily available. Finally, cooling tower drift can be

a nuisance for those in the immediate area.
Ch. 2—issues and Findings ● 45

1.

2.

3.

4.

CHAPTER 2

Khalsa, P. S., and Stamets, L., Cornrnercial Status:

Electrical Generation and Non-generation Technologies (Sacramento, Calif.: California Energy Commission, April 1980).

Edison Electric Institute, Statistical Y’earbook of the

Electric Utility Industry: 1980 (Washington, D. C.:

Edison Electric Institute, 1981).

Geller, Howard S., The Interconnection of Cogenerators and Small Power Producers to a Utility System (Washington, D. C.: Office of the People’s

Counsel, February 1982).

North American Electric Reliability Council, Electric Power Supply and Demand, 1981-1990 (Princeton, N.J.: North American Electric Reliability Council, July 1981).

5.

6.

7.

Office of Technology Assessment, U.S. Congress,

Application of Solar Technology to Today’s Energy

Needs (Washington D. C.: U.S. Government Printing 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: Technical Concepts, Trends, Prospects (Washington,

D. C.: U.S. Department of Energy, DOE-FFU-1 703,

1978).
Chapter 3

Context for Cogeneration
Page

National Energy Context . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 49

Current Picture and Trends . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 49

Future Prospects . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 50

implications for Cogeneration . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 51

Conclusion .. .. .. .. .. .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 54

Electric Utilities Context . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 54

The Electric Power Industry . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 55

Current Status of Electric Utilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 72

Regulation and Financing of Cogeneration . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 76

Federal and State Regulation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 76

Financing and Ownership . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 104

Chapter 3 References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 112

Tables

Table No. Page

6. 1980 U.S. Energy Demand . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 50

7. Ratio of Annual Energy Demand to GNP Growth Rates. . . . . . . . . . . . . . . . . . . . . . 50

8. Comparison of Energy Demand Projections . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 50

9. Thermal Energy Demand. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 53

10. U.S. Electric Power System Statistics, 1980 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 55

11. installed Generating Capacity, by Type of Prime Mover 1978 . . . . . . . . . . . . . . . . . 61

12. Differences in Financing by Form of Ownership. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 64

13. New Capacity Additions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 65

14. Capital Structure for Private Utilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 65

15. Sources of Long-Term Financing to REA Electric Borrowers . . . . . . . . . . . . . . . . . . . . 66

16. Taxes Paid by investor-Owned Electric Utilities-Electric Department Only, 1980.. 67

17. Energy Property Eligible for ITC Under the Energy Tax Act of 1978.... . . . . . . . . . 68

18. State Regulation of Utiiity Service and Operations.. . . . . . . . . . . . . . . . . . . . . . . . . . 69

19. Rates for Power Purchased From Quality Facilities by State-Regulated Utilities . . . . 86

20. Capital Recovery Factors for Cogeneration . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 106

Figures

Figure No. Page

8. North American Electric Reliability Council Regions.. . . . . . . . . . . . . . . . . . . . . . . . . 58

9. The General Patterns of an Electric Power System . . . . . . . . . . . . . . . . . . . . . . . . . . . 59

IO. Daily Load Shapes for Five Representative Weekdays . . . . . . . . . . . . . . . . . . . . . . . . 60

11. Typical Electric Distribution System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 62

12. Allocation of Electricity Costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 63

13. Statewide Utility Resource Plan Additions 1981-82: Renewable/Innovative

Technologies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 91

14. CWE Average Avoided Cost Paths: Baseline Construction . . . . . . . . . . . . . . . . . . . . . 95

15. Generic Paths for Average Avoided Costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 98
Chapter 3

Context for Cogeneration

Cogeneration has attracted widespread attention in recent years because of its potential for

increased energy efficiency, and therefore, lower

energy costs. A decision by an industrial concern,

a commercial building owner, or a utility to invest in a cogeneration system will be based on

an evaluation of the supply and price of fuel,

regulatory considerations, the cost and availability

of capital, tax incentives, and the technical, cost,

and output characteristics of cogeneration relative to conventional separate electric and thermal energy systems. This chapter will review the

institutional, regulatory, and financial context

within which cogeneration must compete against

conventional energy supplies, including the national energy context (supply of and demand for

electricity and fuels), the structure and operations

of the electric power industry (as they may affect a utility’s choice of investing in a conventional baseload or peakload powerplant or in

cogeneration), and the regulation and financing

of cogeneration technologies. Subsequent chapters will describe cogeneration technologies and

their cost and output characteristics, promising

cogeneration applications in the industrial and

commercial sectors and in rural areas, and the

potential environmental and economic impacts

of cogeneration.

NATIONAL ENERGY CONTEXT

Cogeneration systems could affect both the

supply of and demand for fuels and electricity.

The greater operating efficiency that can result

from cogeneration’s dual energy output could

reduce the amount of fuel needed to supply electric and thermal energy for the industrial and

commercial sectors. In many cases, depending

on the fuel used by the cogenerator and by the

utility capacity it would displace, the fuel saved

with cogeneration could be oil or natural gas.

Moreover, the widespread use of cogeneration

could reduce the demand for electricity from central generating plants. In order to analyze these

potential effects, it is first necessary to understand

the current supply and demand picture for fuels

and electric power—the national energy context

in which cogenerators would operate.

This section discusses cogeneration with reference to the current and projected energy picture

in the United States. First, the present energy

situation and recent trends are reviewed briefly.

Then, some projections of energy demand–particularly of electric and thermal demand in the

industrial and commercial sectors—are discussed.

In doing so, this section also briefly outlines some

of the factors that could alter the energy picture

in these sectors which, in turn, would affect the

market penetration of cogeneration.

Current Picture and Trends

Table 6 presents 1980 U.S. energy demand by

fuel and sector. Electricity is shown both as a demand and as a “fuel, ” with losses distributed to

each final demand sector.

Total energy demand in 1980 was 76.3 quadrillion Btu (Quads), a decline of 3.4 percent from

the 1979 total of 79.0 Quads. The size of this decline—the largest annual drop in energy demand

ever experienced by this country—was due in

part to the very large increase in oil prices in 1979

and in part to investments in energy efficiency

made as a result of the 1973-74 price rise. This

can readily be seen by the 7.8-percent (2.9

Quads) decline in petroleum consumption from

1979 to 1980, and by the substantial decrease in

the rate of growth in energy demand since the

1973 Arab oil embargo. Since 1973, overall U.S.

energy demand has grown by approximately 0.8

percent annually, as compared with an average

yearly growth of about 3.5 percent between 1950

and 1972. The most telling change in the overall

U.S. energy growth picture, however, is that

while energy growth has slowed dramatically,

gross national product (GNP) has continued to

grow at near historical rates. Table 7 shows the

growth rates for both energy demand and GNP

49
50 . Industrial and Commercial Cogeneration

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

Sector

Electric

Fuel Residential Commercial Industrial Transportation utilities

Petroleum . . . . . . . . . . . . . . 2.05 2,34 8.88 17.99 3.00

Natural gas . . . . . . . . . . . . . 5.91 1.92 8.41 0.60 3.79

Coal . . . . . . . . . . . . . . . . . . . 0.10 0.10 3.35 — 12.12

Nuclear ... , . . . . . . . . . . . . — — — 2.70

Electricity . . . . . . . . . . . . . . 9.00 6,03 9.67 0.04

Hydro . . . . . . . . . . . . . . . . . . —

—

— — — 3.09

Total . . . . . . . . . . . . . . . . . 17.06 10.39 30.31 18.63 24.70

SOURCE: U.S. Department of Energy.

Table 7.—Ratio of Annual Energy Demand

to GNP Growth Rates

GNP rate Energy demand rate

Period (percent) (percent) Ratio

1950-60 . . . . . . . . 3.29 2.76 0.84

1960-70 . . . . . . . . 3.85 4.24 1.10

1970-80 . . . . . . . . 3.26 1.31 0.40

SOURCE: Office of Technology Assessment.

over the last three decades, as well as the ratio

of energy demand to GNP growth rates for each

of those decades. This latter measure indicates

that a healthy economic growth rate can be sustained with a wide variety of energy growth rates,

and demonstrates the conservation potential of

the U.S. energy economy.

In addition to the cost effectiveness of conservation, other important national energy trends

that have emerged during the past 8 years include

the steady decline of domestic oil and natural gas

production, and the increasing financial problems

of electric utilities. The latter are, in large part,

due to the large drop in electricity demand

growth and the rapidly escalating costs of central station electricity generation. The unexpected

rapid decline in the growth of electric energy demand (from 7.9 percent per year for 1950-72 to

3.5 percent annually for 1972-80) found most

utilities with far greater capacity under construction than needed to meet the new growth. When

it became evident that the lower growth rates

were here to stay—in fact they might even get

smaller—electric utilities deferred or canceled as

much of their construction budget as they could.

Many utilities were still left, however, with

substantial excess capacity.

In addition, several factors combined to make

new capacity much more expensive. These included longer construction times, increased environmental and regulatory review, higher interest rates, and high inflation. One major consequence of these considerations is that, in most

cases, the marginal cost of new central station

electricity now exceeds the average cost. As a

result, electric utilities face severe financial problems, and those utilities that are experiencing demand growth or that need to displace oil-fired

capacity may be unable to raise capital for any

new plant construction (see “Electric Utilities

Context,” below).

Future Prospects

All energy demand projections show a continuation of the trend toward increased energy

efficiency, although there is still considerable

variation as to how much (see table 8). The range

of the projections shown in table 8 is due principally to different assumptions about consumer

responses to changes in energy prices. In all

cases, however, these projections recognize that

changes in demand will be the dominant factor

in the energy future of the United States for the

next few decades.

Table 8.—Comparison of Energy Demand

projections (Quads)

Forecaster 1980 1990 2000

Energy Information Administration . . 76.3 87.0 102.5

Exxon . . . . . . . . . . . . . . . . . . . . . . . . . . . 76.3 81.0 91.0

Edison Electric Institute . . . . . . . . . . . 76.3 — 117.2

National Energy Policy Plan. . . . . . . . 76.3 80-90 90-110

SOURCE: Office of Technology Assessment
Another trend mentioned above–the decline

in domestic petroleum and natural gas production—also is very likely to continue. In a technical

memorandum, World Petroleum Availability:

79802000, OTA estimated U.S. oil production

at 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 7.5

MMB/D in 2000 (26). The Energy Information Administration (EIA), on the other hand, projects a

slight increase above today’s level to about 10.9

MMB/D (23). Despite the rapid increase in drilling activity since 1979, OTA has not yet seen any

evidence to contradict findings of a net decline

of between 3 to 6 MMB/D by the end of the

century.

Natural gas production is even more uncertain

due to the existence of large quantities of unconventional gas (Devonian shale, tight sands,

coal seam methane, and geopressurized brine).

For most types of unconventional gas, the uncertainty is not so much the size of the resource

base, but the production rates that can be obtained and the production cost. The available

estimates currently center on total natural gas production 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 world

oil, however, these same estimates show production in 2000 to be approximately the same as it

is today. In any case, there is little probability that

the Nation will see a significant increase in

domestic gas production, and such an increase

is even less likely for oil.

Implications for Cogeneration

The Nation is confronted with a combination

of circumstances that favor continued emphasis

on different, less costly ways to generate electricity, and on increased efficiency in electricity use.

These circumstances have led to a resurgence in

interest in the cogeneration of electricity and thermal energy. The relatively small size of cogeneration units compared to central power stations

may offer significant short-term advantages for

financing new capacity. Cogenerators will take

much less time to build than central station plants

and they represent smaller capacity increments

that would allow rapid adjustment to changes in

demand. Moreover, because cogeneration units

are installed at or close to the point of demand,

most or all of the energy requirements of many

industrial plants and commercial buildings could

be provided onsite with the added possibility of

generating electricity for distribution through the

utility grid. Finally, cogenerators’ ability to use

fuel for two purposes (electricity and thermal

energy) greatly increases the overall utilization

efficiency of that fuel. Thus, where electric utilities

project continued reliance on oil and gas due to

the unavailability or infeasibility of other fuels,

or where cogeneration systems can use alternate

fuels, substantial oil or gas savings may result.

The technical advantages of cogeneration have

always been available. It is the advent of the

economic and energy supply and demand conditions described above that adds potential fuel

economy, financial, and planning advantages for

cogeneration compared to central station electricity generation and conventional thermal

energy combustion systems. Whether these advantages will prove sufficient to accelerate the

growth of cogeneration will be determined largely by the amount and character of demand for

electricity and thermal energy in the commercial

and industrial sector, and by the future financial

health of the electric utility sector.

Electricity Supply and Demand

Perhaps the most critical factor in cogeneration

economics is the demand for electric power. The

Public Utility Regulatory Policies Act of 1978 offers economic and regulatory incentives to cogenerators that enable utilities to defer or cancel

new powerplants and decrease oil and gas use.

A zero or low growth in electricity demand, however, could undermine these incentives by reducing the need for cogenerated electricity and,

therefore, reducing the economic attractiveness

of cogeneration. Moreover, where the utility is

primarily dependent on coal, nuclear, or hydroelectric plants, or where it plans to convert existing oil-fired capacity to alternate fuels,

cogeneration will only be attractive if it also can

use alternate fuels and can offer substantial financial advantages.
Currently there is considerable uncertainty

about future electric power demand growth; the

Solar Energy Research Institute (SERI) projected

a 0.4 percent per year increase under their least

cost approach (61 ), while the North American

Electric Reliability Council (NERC) estimates a 2.9

percent annual growth rate (48). In terms of

capacity requirements, the SERI projection could

be met by 620 gigawatts (GW) of capacity operating at the current capacity factor of 45 percent.

Further, SERI shows that 577 GW could be available in 1985 assuming completion of all plants

scheduled to be on-line in 1985, and the retirement of all plants built before 1961 and of all oil

and natural gas plants built between 1961-70 (61).

Therefore, under the SERI least cost approach,

very little new capacity would be needed past

1985, and any cogeneration added after that

would be likely to substitute for electricity from

existing coal, nuclear, or hydroelectric plants.

Under the NERC case, however, capacity is projected to reach about 900 GW by 2000, an increase of 300 GW over present capacity. Even

then, NERC estimates that the capacity factor

would have to increase to 50 percent to meet

their projected energy demand. Accounting for

retirements and conversion of oil and natural gas,

about 50 percent more new capacity would have

to be added under NERC projections than now

exists (49). In this case, cogeneration could have

a very large market potential.

The future demand for electricity will be determined by the relative prices of electricity and

competing fuels (including conservation measures), by the development of technologies that

use electricity more efficiently (e.g., process

equipment, appliances), and by consumers’ perceptions about the stability of oil and natural gas

resources. Currently, average electricity prices in

the commercial sector are about 2.5 times distillate fuel oil prices and five times natural gas

prices on a delivered Btu basis. * For industry,

both of these price ratios are about 2 to 1. The

ratios have decreased by 20 to 60 percent from

those in 1970, however.

*As will be discussed below, differences in end use efficiency

between equipment using electricity and that using natural gas or

fuel oil make price comparison on a delivered Btu basis alone,

incomplete.

Continuation of the low rate of growth in electricity demand, coupled with the current excess

of generating capacity, may keep the rate of

growth in electricity prices rather low over the

next several years. If prices do remain somewhat

stable, then the difference between electricity

prices and oil and gas prices would be likely to

become even smaller. However, the current decline in the real price of oil could alter this trend.

Furthermore, if the oil price decline continues for

the next few years, natural gas price increases

following decontrol also are not likely to be so

dramatic as originally thought. Therefore, the

ratio of electricity prices to oil and natural gas

prices would not decline for some time. At this

point, it is most likely that the ratio will decline,

although more slowly that previously anticipated. The price trajectories used in the analysis

of commercial cogeneration in chapter 5 also project that the ratio will become smaller.

Such growth rates would continue the trend

toward price closure between electricity and

natural gas or distillate fuel oil. If these trends are

combined with the development of technologies

for buildings and industry that use electricity more

efficiently than equivalent oil or natural gas burning technologies that provide the same services

(e.g., space heating, reheating of finished metals),

the costs of providing these services with electricity could become lower than with oil or

natural gas. For example, in many areas, efficient

electric heat pumps can provide space heating

more economically than oil furnaces. There are

even a few regions where space heating with

electric heat pumps is cheaper than with natural

gas furnaces.

Natural gas and oil are the primary energy

sources for industrial processes, supplying both

direct heat (such as catalyzing chemical reactions

and heat treating) and process steam. The major

use of electricity in industry is to run motors.

Whether technologies that use electricity could

economically replace direct heat or process

steam in industry is much less certain than in the

commercial sector. Some possibilities include

microwave, infrared, or dielectric heating, very

efficient electric motors for replacing steam

mechanical drives, and pulsed current devices

for surface reheating of metals.
Ch. 3—Context for Cogeneration ● 53

It is possible, then, that the growth of electricity

demand could increase sharply toward the end

of the decade. * However, the extent of any increase in industrial or commercial demand will

depend on the size of the dollar savings achieved

by switching to electricity relative to the required

capital investment. Conversion is much more

likely for new buildings and plants than for existing facilities. Therefore, unless there is significant new development in energy intensive industries for which more economical electric technologies are available and accepted, the growth

rate of industrial use of electricity is not likely to

change substantially for the remainder of the

century.

It is this uncertainty of future demand that provides a potentially important role for cogeneration. If electricity use in buildings and industry

did increase substantially, electric utilities could

be strained financially if they tried to meet the

increased demand with new central station capacity. Further, attempts to accommodate demand growth with central station capacity could

lead to a rapid increase in electricity prices. This

is because the marginal cost of electricity—the

cost of a new plant—is often considerably higher

than the average cost. Therefore, as new capacity

becomes a larger fraction of the total electric utility plant, the average cost will grow closer to the

marginal cost. Cogeneration could help alleviate

these pressures, particularly in the first years of

an increase in demand. The small size of cogeneration systems would allow rapid and fairly

precise matching of supply and demand, and

with much smaller increments of capital. This

would greatly reduce the risk of building excess

capacity or having to defer or cancel capacity

under construction should demand growth suddenly slow or stop. Moreover, because cogeneration supplies thermal energy, it could at least partially offset increases in electricity demand due

to a rapid rise in the use of electric heating.

Cogeneration’s competitiveness would then turn

on the difference between the cost of purchasing electricity plus supplying heat, and the fuel

*The extent to which electricity can be substituted economically for other energy sources in buildings and industry will be examined in detail in forthcoming OTA studies on oil disruption and

on electric utilities.

and operating and maintenance costs of a cogeneration system. Finally, the avoidance of extensive new additions to transmission and distribution systems also might alleviate some of the electric utilities’ capital problems.

However, if utilities are able to raise capital

easily, or if demand does not increase in the face

of stable prices, central station powerplants fueled

with coal, uranium, or hydropower may be preferred to oil- or gas-fired cogeneration systems.

These alternate energy sources probably would

be cheaper than the oil or natural gas likely to

be used in most cogeneration systems in the near

term. Therefore central station electricity—even

with a substantially larger capital cost per kilowatt than cogeneration capacity—is likely to be

cheaper than cogenerated electricity despite cogeneration’s higher overall fuel efficiency.

Thermal Energy Demand

The second major influence on the growth of

cogeneration is future thermal energy demand

in buildings (space and water heat) and industry

(direct heat and process steam ). We have already

discussed how some of this future load may be

met by electricity rather than by direct combustion of fossil fuels. In addition, available conservation opportunities will slow thermal demand

growth and could even reduce thermal energy

use (by 2000) from the 1980 levels. Conservation

will affect electricity use as well, and even if

significant conversion from other fuels to electricity (as discussed above) does occur, electricity

demand growth in these sectors still could be kept

low. Table 9 shows two estimates of direct combustion heat requirements for commercial buildings and industry for 2000 compared to 1978. As

can be seen, current thermal demand in industry

is more than twice that of commercial buildings.

Moreover, under either the EIA or the SERI projection, the difference would become even more

pronounced.

Table 9.—Thermal Energy Demand (Quads)

Buildings Industry

Year Space/water heat Direct heat Steam

1978 ......., . . . . 4.5 3.8 6.8

2000 (EIA) . . . . . . . 3.8 5.0 9.3

2000 (SERII . . . . . . 1.6 3.7 6.6

SOURCE: Office of Technology Assessment
54 ● Industrial and Commercial Cogeneration

The SERI estimates in table 9 are based on a

least cost approach using conservation technologies that cost the equivalent of up to the 1980

average cost of oil and electricity ($7.50/MMBtu

and $.057/kWh respectively) (60). The EIA projections are derived from economic and engineering models and reflect judgments about actual consumer response to changing energy

prices (22). In either case, cost-effective conservation opportunities for commercial buildings

could reduce fuel requirements for space and

water heating from 15 to 65 percent. For industry,

EIA estimates a 37-percent increase in steam

growth while SERI projects a 3-percent decrease

(see the section on “Industrial Cogeneration Opportunities” in chapter 5 for an analysis of steam

growth projections).

These analyses indicate that cogeneration will

have greater potential in the industrial sector than

in commercial buildings as far as supplying thermal energy is concerned. Both EIA and SERI analyses imply that in the commercial buildings sector, cogeneration will have to compete with central station electricity and with fuel freed by conservation in meeting future space and water heating demand. When the low load factor inherent

in buildings’ heat load is added, the economic

potential of cogeneration is decreased further (see

ch. 5). In essence, conservation can considerably

reduce the opportunity to take advantage of cogeneration’s high fuel utilization efficiency.

The air-conditioning demand of buildings also

offers a potential market for thermal energy from

cogeneration. In 1980, over 98 percent of all

commercial air-conditioning was electric. For

these buildings, the use of cogenerated steam for

cooling would require conversion to either absorption units or steam-driven compressors.

Where it is economic to do so, such conversion

would increase the baseload steam demand and

therefore the building’s thermal load factor. By

2000, SERI and EIA project cooling demands of

2 and 4 Quads of primary energy, respectively.

Conclusion

The attractiveness of cogeneration will depend,

to a large extent, on energy demand in the commercial and industrial sectors, on the balance between thermal and electric loads, and on the

overall demand for electricity. These, in turn, depend heavily on the price of energy–particularly

the relative prices of electricity, distillate fuel oil,

and natural gas. It is fairly certain that energy demand will grow much more slowly than in the

past. The range of possible growth rates, however, is large. Lower growth rates, while not

necessarily changing the economics of cogeneration, will clearly reduce the potential market as

well as the net fuel savings. Further, a very low

growth rate for electricity is likely to dampen

price increases and reduce the price paid by

utilities for cogenerated power, both of which

would reduce the economic attractiveness of cogeneration. However, the uncertainty of future

electricity demand and the economic problems

caused by a severe mismatch between load

growth and capacity growth make small capacity additions potentially very desirable in the short

term. Therefore, while conservation through increased efficiency is likely to be the most economic route to choose for at least the next several

years, there appears to be a potential role for

cogeneration, particularly in the industrial sector where thermal and electrical demands are

likely to remain large.

ELECTRIC UTILITIES CONTEXT

Future 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 who

factor in determining the role cogeneration will now provide some or all of their own electric

play in the Nation’s energy future. Equally im- power needs and who may even supply power

portant in defining that role will be the electric to the utility. In this context, cogeneration must

power industry. Cogeneration systems may be compete, both technologically and economically,
with well established electric and thermal energy

conversion and distribution systems as well as

with alternate energy forms and conservation.

The elements of this competition—both on a sitespecific and a national energy policy basis—will

be wide ranging, encompassing the technological, fuel use, and institutional characteristics of

the electric power industry, as well as the financing, regulation, and operations of technologies

that supply energy for commercial and industrial

applications.

This section will review the general electric utility context within which cogeneration systems will

compete. The following section of this chapter

will analyze the present institutional and regulatory context specific to cogeneration.

The Electric Power Industry

Current operations of electric utility systems are

diverse, encompassing a wide range of technical

and institutional configurations. These include the

number, size, and type of generating plants; the

amount of electricity consumed by customer

classes and their regional load profiles; and the

different types of institutions that supply power,

coordinate specific utility functions, and regulate

the power industry. Support activities include the

production and acquisition of fuel supply and of

the necessary equipment for fuel handling and

storage, and for electricity generation, transmission, distribution, and consumption.

A wide array of institutions has evolved to perform the functions listed above. The U.S. electric power supply system is composed of over

3,400 separate entities, including private, public,

and cooperative utilities, joint action agencies,

Federal power agencies, power pools, and electric reliability councils. In 1980, these systems had

619,050 megawatts (MW) of installed generating

capacity to supply close to 93 million customers

with about 2.3 trillion kilowatthours (kWh) of

electricity (see table 10) (55). The utilities in the

electric power system obtain financing from a

variety of sources including banks, insurance

companies, traditional stock and bond markets,

and Federal programs; their financial and technical operations are regulated at the Federal,

State, and local level. Finally, both the production and consumption of electricity are supported

by innumerable institutions that manufacture, distribute, install, and service equipment, tools, and

appliances. All of these factors together make the

electric utility industry the largest in the United

States in terms of capital assets and issuance of

stocks and bonds.

Utility Organizations

The organizations that supply electricity in the

United States include private or investor-owned

utility companies; publicly owned utilities such

as State, county, or municipal systems, and Federal power agencies; rural electric cooperatives;

joint ownership organizations; and groups of utilities that coordinate their operations to improve

efficiency and reliability.

Private utiiities are owned by their investors

and generally are granted territorial franchises by

State or local governments. Most investor-owned

utilities (IOUS) generate their own electricity, and

some are part of vertically integrated corporations

that own their fuel supply (e.g., “captive” coal

mines) or other support activities.

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

Electric operating Net electric

Installed 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 11.9

Privately owned systems (217) . . . 476,979 77.1 1,782,545 78.0 70,620,300 76.2 87,062 76.9 207,555 72.4

Rural electric cooperatives

(924) . . . . . . . . . . . . . . . . . . . . . . . 15,425 2.5 63,557 2.8 9,523,600 10.3 9,707 8.6 23,892 8.3

Federal 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 2,266,033 100. 0 92,624,900 100. 0 $113,231 100.0 $286,647 100. 0

aDoes not Include nuclear fuel.

SOURCE: Office of Technology Assessment from “Public Power Directory,” Publlc Power, January-February 1982.
56 ● Industrial and Commercial Cogeneration

IOU companies dominate power generation in

the United States today. The 217 IOUS represent

about 6 percent of the total number of utilities,

but those 217 own approximately 77 percent of

all installed generating capacity and generate

about 78 percent of the electricity produced (see

table 10). In 1977, approximately two-thirds of

the IOUS had a peak demand in excess of 100

MW, and about 12 percent had a peak demand

greater then 3,000 MW (21). Because of the capital intensity of the electric utility industry, with

total operating revenues of over $113 billion in

1980 and net electric plant investment of over

$286 billion, the domination of the industry by

a relatively few IOUS means that they also determine the role of utilities in financial and other

markets.

publicly owned utilities include municipal,

public utility districts, and State and county systems. The authority to establish a public utility

derives from the State government, and a few

States (e.g., New York, Nebraska) currently have

their own systems. However, most States have

delegated this authority to county or municipal

governments.

The relatively large number of publicly owned

utilities, in contrast to their small share of the electricity market (see table 10), reflects their small

size. Most of these systems only purchase wholesale power and distribute it to their customers;

those municipal that do generate have very small

loads (fewer than 100 publicly owned utilities

have peak demands in excess of 100 MW) (21).

Roughly 71 percent of the local public power systems purchase all their electricity, while about

6 percent own sufficient generating capacity to

supply all their needs. The remaining 23 percent

of public utilities generate some portion of their

needs and purchase the remainder (55).

Cooperative utilities represent a different type

of public ownership. The co-ops are nonprofit

economic entities that are owned and managed

by their customer members. Members’ shares in

the co-op may be plowed back into the operation and/or expansion of the business as patronage capital in order to keep the cost of co-op service as low as possible, or the patronage capital

may be “rotated” —essentially paid out as dividends–if the co-op’s equity ratio is 40 percent

or higher.

Rural electric co-ops comprise a vast operating

network of over 900 local and regional electric

systems in 46 States which own and maintain

nearly 44 percent of the Nation’s electric distribution lines, and whose service territories encompass 75 percent of the land area of the United

States. The rural electric system is a two-tiered

operation, including 870 local distribution co-ops

and 54 generation and transmission co-ops

(G&Ts). The 870 local co-ops purchase electricity and distribute it to their own rural customers,

while G&Ts generate and/or transmit electricity

primarily for local distribution co-ops. Some G&Ts

also sell electricity wholesale to municipal and

IOUS, while distribution co-ops may purchase

power from a combination of sources, including

G&Ts, Federal power agencies, and IOUS (16).

Still another form of public utility ownership

is represented by Federal power marketing agencies. The Federal role in electricity generation

dates back to the Reclamation Act of 1906, which

empowered the Bureau of Reclamation to produce electricity in conjunction with Federal irrigation projects, and to dispose of any surplus

power to municipal utilities (39). The second

Federal power marketing agency was the Tennessee Valley Authority (TVA), which was established in 1933 as a multipurpose river project with

responsibility for flood control, regional development, hydroelectric power generation, and other

activities. Today, it is the single largest electric

utility in the country, with a total system capacity of over 31,000 MW. Approximately 65 percent

of TVA’s sales are at wholesale to municipal utilities and rural electric co-ops. The remainder is

sold to private industries, other Federal agencies,

and private power companies (55).

Other Federal power agencies include the

Bonneville Power Administration, which was

established in 1937 and which markets power

from hydroelectric projects constructed by the

Army Corps of Engineers and the Bureau of Reclamation in the Columbia River Basin and operates

the Nation’s largest network of long-distance

high-voltage transmission lines; the Southwestern

Power Administration, which was set up in 1944
Ch. 3—Context for Cogeneration ● 57

to market power from Corps of Engineers projects in Arkansas, Missouri, Oklahoma, and Texas;

the Southeastern Power Administration, created

in 1950 to market power from Corps projects in

10 Southeastern States; the Alaska Power Administration, established in 1967 to operate and

market power from Federal hydroelectric projects

in Alaska; and the Western Area Power Administration, which was set up in 1977 and incorporates Federal power marketing and transmission functions formerly performed by the Bureau

of Reclamation and markets power from a number of Corps hydroelectric projects (55).

A hybrid form of public ownership is the joint

action agency, in which two or more public

power systems pool their plans to purchase

power or to finance total or partial ownership of

generation and/or transmission systems. Where

the local public utility system is no longer adequate or economical and low-cost Federal power

is not available, joint action agencies can place

public power systems in a more advantageous

cost and supply position, allowing even the smallest electric utilities to realize economies of scale

(4). Joint action may also provide publicly owned

utilities with more flexibility in choosing fuels and

types of generating capacity while avoiding the

risks of a single-shot investment in one plant.

IOUS may choose to participate in joint action

agencies to reduce plant construction costs or to

obtain lower cost financing (32).

Joint action agencies are authorized by State

legislation and membership arrangements vary.

They may include statewide areas (e.g., Municipal Electric Authority of Georgia), correspond to

IOU service areas (such as in North Carolina,

which has three agencies, one for each of the

State’s major IOUS), or be determined according

to both geography and perceived mutual interests

(e.g., the five Minnesota organizations). Some

joint action agencies, such as the Missouri Basin

Municipal Power Agency, have members from

several States. As such, they cannot finance projects themselves but must rely on the members’

funding abilities. In 1981, there were 49 publicly owned joint action agencies in 31 States (55).

Since the 1920’s, all the types of utility systems

described above have been interconnected and

their operations coordinated to some degree in

order to reduce costs by increasing the productivity of the resources employed in the generation and transmission of electricity, and to improve reliability by applying the combined resources of several systems to a contingency on

any one. These intersystem agreements now

comprise approximately 20 formal organizations

known as power pools. The degree of coordination among utilities in power pools can range

from very loose agreements for exchanges of

energy; to some coordination of planning, construction, operation, and capacity reserves; to

complete integration with joint planning on a

single system basis, centralized dispatch of

generating facilities, and strict contractual requirements for generating capacity and operating

reserves (29).

In general, the potential economic benefits of

pooling include reduced investment costs

through economies of scale in building larger

generating units and through lower reserve margins that result from reducing the ratio of generating unit size to combined system peakload;

greater operating economies through increased

load diversity, reduced operating costs per unit

output for larger plants, and fuller use of the

lowest cost capacity available on the system; and

increased savings through coordinated construction programs that minimize the costs of temporary excess capacity that may result from the

addition of large generating plants. The potential reliability benefits of power pools derive from

access to support from other systems, and may

be realized either through a reduction in reserves

needed to achieve a certain level of reliability or

through an increase in the level of reliability of

the coordinated systems (29).

Electric reliability councils represent a second

form of coordination among utilities. A Federal

Power Commission (FPC) investigation of the

1965 blackout in the Northeast stressed the need

for greater reliability and coordination among

electric utility companies. In response to FPC findings, NERC and nine regional councils were

formed in the late 1960’s (see fig. 8), representing about 95 percent of the Nation’s generating

capacity. Each regional council consists of a rep98-946 (I - 83 - 5 : IQI, 3
58 . Industrial and Commercial Cogeneration

Mid-America

Interpool Network

Mid-Continent Area

Rellablllty Coordination

Agreement

Northeast Power

Coordlnatlng Council

Southeastern Electric

Reliability Council

Southwest Power Pool

Western Systems

Coordinating Council
resentative from each of the major utilities in the

region and from groups of small utilities in some

regions.

The regional councils develop voluntary standards for those aspects of bulk power supply that

affect the regionwide reliability of service (e.g.,

design criteria for transmission facilities). NERC

aids in the coordination of policy issues among

the regional councils, and provides industry information, comment, and recommendations

about the reliability and adequacy of bulk power

supply at the national level. In addition, NERC

is responsible for the development and mainteFigure 9.—The Generai Patterns

Generating station

Generating station . . . Transmitting

nance of nationwide standards for interconnected

operation (18).

Technical Aspects of the Utility industry

A conventional power system can be described

as the coordinated operation of generating units,

high-voltage transmission lines, and subtransmission and distribution networks. Figure 9 shows

a typical power system structure.

The primary consideration in an electric power

system is to serve the electric loads, or power requirements, in a given area or region. The power

of an Eiectric Power System

a

Receiving substation’

Generating station

Distribution lines

to electric users Distribution lines

to electric users

SOURCE: Economic Regulatory Administration, The National Power Gr/d Study, Volume //(Washington, D. C.: U.S. Department

of Energy, DOE/ERA41056-2, September 1979).
60 ● Industrial and Commercial Cogeneration

requirements include all devices or equipment

that convert electricity into light, heat, or

mechanical energy, or otherwise consume electricity (e.g., aluminum reduction), or the requirements of electronic and control devices. The

total load on any power system is seldom constant; rather it varies with hourly, daily, seasonal,

and annual changes in the service area’s requirements (see fig. 10). The minimum system

load for a given period is termed the baseload,

while maximum requirements (usually resulting

from temporary conditions) are called peakloads.

Because electric energy currently cannot be

stored in large quantities, generating plant operations must be coordinated closely with fluctuations in the load, and large utility systems usually have separate generating plants sized to meet

base, intermediate, and peakloads.

Table 11 shows the current U.S. generating

capacity by type of prime mover. The choice of

capacity type is a function of service needs, economic and financial considerations, resource

constraints (e.g., fuel, land, water), potential environmental impacts, future growth, politics, regulatory requirements, and management preferFigure 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/lzedElectr(c Generathrg Equipment Connected 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

Thousands

of kilowatts

Investor-owned utilities . . . . . . . . . . . . . . . . 453,647

Municipal utilities . . . . . . . . . . . . . . . . . . . . . 34,426

State systems and publlc

utility dlstrlcts . . . . . . . . . . . . . . . . . . . . . . 25,322

Rural electric cooperatives . . . . . . . . . . . . . 11,635

Federal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 54,282

Thousands

Percent of k W

76 23,847

6 4,694

4 11,975

2

9 30,431

Thousands

Percent of k W

4 383,024

< 1 25,511

2 9,245

<1 11,073

5 20,376

Thousands Thousands

Percent of kW Percent of kilowatts Percent

66 44,984 8 1,792 < 1

4 963 < 1 3,258 < 1

2 4,059 < 1 43 < 1

2 < 1 430 < 1

4 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 steam

plants and many hydroelectric facilities are used

for baseload and intermediate-load generation

while some hydro equipment (usually pumped

storage) and combustion turbines are used to

supply peaking power.

The trend in recent years has been to construct

large baseload plants in order to capture economies of scale. Nuclear plants usually exceed

1,000 MW in nameplate capacity and most of the

existing fossil steam plants are larger than 5oo

MW. However, as capital costs and construction

times increase and it becomes more difficult to

finance large powerplants, some utilities are turning to smaller equipment that may use unconventional fuels. Where the service needs are not

expected to grow rapidly, small units such as

cogenerators may improve load factors while

alleviating utility financial problems in the short

term, although their longer term financial and

system planning advantages are uncertain (see

ch. 6).

In order to serve the electric loads of an area

adequately, a utility must plan not only for

baseloads and peakloads, but also for system

reliability during scheduled and unscheduled

outages (e.g., equipment maintenance, storm

damage) and for demand growth. To some degree, system reliability can be achieved through

interconnections with other utilities (i.e., power

pooling), but utilities also must incorporate reserve margins into their planning. Reserve margins are the installed available capacity in excess

of that needed to meet the system’s peak demand

when due consideration is given to maintenance

requirements, random equipment failure, or

other contingencies. The amount of reserve

capacity required in a given situation depends on

the reliability criterion, the behavior of individual

generators, the unit size mix, and the interconnection support available. The usual planning

procedure is to specify a reliability level or loss

of load probability, such as an expected deficiency of 1 day in 10 years, and optimize capacity

expansion so that this criterion is always met (3 S).

The accepted industry minimum value is about

20 percent. In 1979, the average reserve margin

for IOUS was around 36 percent of peakload (20).

Some utilities have reserve margins above so percent, while others are below 10 percent.

Once electricity has been generated, its voltage

is stepped up with power transformers and it is

transmitted to the load center. High-voltage transmission lines (69 kilovolts (kV) and above) are

used to transfer bulk power from the generating

plant to a substation or bulk purchaser, and to

interconnect utility systems for greater efficiency and reliability. Such lines are built to accommodate power flows in either direction in order

to facilitate interconnection among systems.

After the bulk power has been transmitted to

the demand center, it goes into the distribution

system, which supplies electric energy to the individual user or consumer. The distribution system includes the primary circuits and the distribution substations that supply them; the distribution transformers; the secondary circuits, including the services to the consumer; and appropriate protective and control devices (see fig.

11). A transmission substation transforms power

to subtransmission voltage (below 69 kV). It is

then distributed to various distribution substations, load substations, and distribution transformers, where the voltage is stepped down further

to match residential, commercial, and industrial

needs. Once the electricity enters a local distribu-
Figure 11.—Typicai Eiectric Distribution System (three.phase)

From transmission

volt

Industrial Commercial Residential

or large load or rural

commercial load

load

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

tion system, the power usually only flows one

way in order to protect electrical workers and

equipment. Special equipment is thus needed for

onsite generators that feed power back to the grid

(see discussion of interconnection in ch. 4).

Economic and Regulatory Aspects

of Utility Systems

Electric utilities are among the most capitalintensive and highly regulated industries in the

United States, and the two aspects of the industry

are integrally related. The rates charged for

service-as determined by State or Federal regulation—are the primary factor in utility economics. But the economics of electric power

supply and demand also may be affected by financing and its regulation as well as by regulation of utility services and operations. These

aspects of utility regulation and their effects on

the 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 as

a natural monopoly, utility practices are regulated

in the public interest. The primary form of such

regulation is the determination of the rates utilities

can charge for their services. State public service

commissions (PSCS) traditionally have controlled

rates for intrastate sales of electricity, while the

Federal Government has had jurisdiction over

sales for resale in interstate commerce since 1935.

State Regulation.–Each of the States (except

Nebraska, where all electricity is supplied through

a State-owned and operated utility system) has

a PSC established by law to regulate utilities. The

degree of State regulation varies. Ail PSCS regulate

the rates of IOUS, while 19 commissions have

some authority over publicly owned utility rates,

and 29 regulate cooperatives (30). Where the PSC

does not have such authority, public utilities are

self-regulating through the municipal or county

government.
Ch. 3—Context for Cogeneration ● 63

Determining the rates a utility charges for its

services is a two-step process. The PSC must

decide first, how much money the utility needs

(the revenue requirement) and second, how

those funds will be collected (the rate structure

or rate schedule). A utility’s revenue requirement

is the total number of dollars required to cover

its operating expenses and to provide a fair profit. The revenue requirement is usually expressed

in formula form as follows:

E + d + T + (V – D) R

revenue requirement

operating expenses

annual depreciation expense

taxes, including income taxes

gross valuation of the property serving

the public

accrued depreciation

rate of return (a percentage)

rate base (net valuation)

profit, expressed as earnings on the

rate base, plus interest on debt (53).

The rate schedule allocates the revenue requirement among a utility’s customers. The problem of cost allocation arises because most electricity is produced in jointly utilized equipment

and its cost must be assigned to the customer

classes involved (36). First, costs directly attributable to a particular class or customer (e.g.,

the distribution line from a substation to a facFigure 12.–Allocation

Total utility Costs are

$ costs attributed

for a given to major

year functions

tory) are identified and segregated. Second, the

remaining costs are arranged so that they can be

apportioned among the various groups of customers jointly responsible. Third, those costs are

distributed in accordance with some physically

measurable attribute of the customer class.

in accomplishing the last two steps, costs are

arranged according to function (such as production, transmission, and distribution), and then

either assigned to demand, energy, or customer

cost categories, or simply classified as fixed or

variable (see fig. 12). Demand costs (the fixed rate

base and expense items related to peak or average demand) are generally the most difficult to

allocate and have become controversial in the

setting of rates for backup service to cogenerators

(see discussion of rates in next section). Energy

costs can be directly allocated to customer classes

based on the number of kilowatt-hours consumed by the group, and thus do not pose a

problem (36).

Federal Regulation.–Federal regulation of

electricity prices began in 1920 with the authority

to set rates for interstate sales of power from

federally licensed hydroelectric projects. The

financial abuses of the 1920’s and early 1930’s,

however, revealed a need for a more extensive

national role, and the Federal Power Act of 1935

expanded Federal jurisdiction to include all sales

of electric energy at wholesale in interstate comof Electricity Costs

Costs are Costs are

divided into allocated to

three principal three classes of

categories customers

SOURCE: Office of Technology Assessment.
merce. The States retained exclusive jurisdiction

over intrastate and retail electricity sales until

passage of the Public Utility Regulatory Policies

Act of 1978 (PURPA), which required the Federal

Energy Regulatory Commission (FERC) to establish standards for PSCS to consider in setting retail

and certain wholesale rates (56).

The Federal Power Act of 1935 requires that

all rates and charges of any electric utility for the

transmission or sale of power subject to FERC

(formerly FPC) jurisdiction be just and reasonable

as well as nondiscriminatory. Each utility must

regularly file with FERC schedules that show such

rates and charges, and the classifications, practices, and regulations that may affect them. FERC

rate proceedings are similar to those of State commissions: FERC first determines the utility’s revenue requirement and then approves a rate

schedule designed to meet that requirement. In

such proceedings, FERC traditionally has employed the same cost-based formulae used by

PSCs (3).

Although only about 10 percent of the revenues realized by IOUS are from wholesale transactions subject to Federal jurisdiction, FERC still

has a broad opportunity to influence State ratemaking. For example, States may be reluctant to

introduce innovative rate structures for fear of

placing utilities within their jurisdiction at a competitive disadvantage. Innovation at the Federal

level can provide the experience necessary for

State adoption of innovative rate designs. Moreover, FERC’S ability to examine cost trends and

pricing practices on a regional or nationwide (as

opposed to local) scale may reveal to States opportunities for ensuring greater economy in electric power supply.

FINANCING

The second major factor in utility economics

is financing of new generating capacity. Utility

financing options vary widely depending on the

form of ownership, current economic conditions,

the type of project being financed, and similar

considerations. A summary of differences in

financing by form of ownership is shown in table

12. The general considerations related to utility

financing of capacity additions are reviewed here;

financing considerations specific to cogeneration

will be discussed in the following section.

Investor-Owned Utilities.– IOUS spend the

largest proportion of funds in the electric power

industry (see table 10) and, based on announced

plans for capacity additions (table 13), their share

of funds is likely to remain large. IOUS have four

basic options for securing those funds: long-term

debt, preferred stock, common stock, and retained earnings (see table 14).

The primary form of long-term debt financing

for IOUS is the mortgage bond, which is secured

by a conditional lien on part or all of the comTable 12.—Differences in Financing by Form of Ownershipa

Average return to

Ownership Capitalization Percent financing sources Tax treatment Financiability

Federal Debt

Retained earnings

Federal

Municipal Debt

Retained earnings

Municipality

Cooperative:

Distribution Dept

Equity

G&Ts

b Debt

Equity

Investor owned Debt

Preferred

Common

Retained earnings

27.8

9.1

63.1

73

25.5

1.5

66 (1977)

34 (1977)

96 (1977)

2 (1977)

50.3

12.5

24.9

12.3

7.25% (1977)

4.9

7.4 (1977)

10.7 (1977)

7.4 (1977)

10.7 (1977)

11.85

9.76

11.3

Tax exempt Federal

Taxed revenues

Interest on debt Electric

exempt from taxes revenues or

municipality

Taxed Federal loans

or 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 Total

1979 1980 1981 1982 1983 planned

Private . . . . . . . . . . . . . . . . 9,167 22,373 13,139 17,582 137,832 190,930

Public . . . . . . . . . . . . . . . . . 2,945 17,444 26,448 1,488 20,793 26,563

Cooperative . . . . . . . . . . . . 1,640 2,675 1,543 2,577 11,376 18,171

Federal . . . . . . . . . . . . . . . . 3,323 3,315 3,322 1,891 19,376 27,904

Total . . . . . . . . . . . . . . . . 17,075 30,107 20,652 23,522 187,377 263,658

SOURCE: 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 1960

Long-term debt . . . . . . . . . . . . . 52.3 54.8 53.0 51.0 50.5 50.4 50.4

Preferred stock . . . . . . . . . . . . . 9.5 9.8 12.2 12.5 12.4 12.5 12.3

Common stock. . . . . . . . . . . . . . 26.1 23.2 23.5 24.2 24,8 25.0 25.4

Retained earnings . . . . . . . . . . . 12.1 12.2 11.3 12.3 12.3 12.1 11.9

SOURCE: 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 percent of total average IOU capitalization was long

term debt. In the same year, IOUS issued around

$8.3 billion in long term debt (or 58 percent of

their 1980 long term financing), $7.85 billion of

which was new capital and the remainder refunding. For the last quarter of 1980, the average yield

on all IOU bonds was 14.11 percent, with a range

of 13.18 percent for Aaa bonds to 15.20 percent

for Baa bonds. For newly issued bonds, the average yield in 1980 was 13.46 percent (20).

Common stock equity represented about 25

percent of electric utilities’ total outstanding

capitalization in 1980. iOUs issued approximately

$4.1 billion of common stock in 1980, or around

28 percent of the long term financing obtained

by IOUS during that year. The average yield on

common stocks during 1980 was 12.01 percent.

The actual return on average common equity was

11.4 percent, while the authorized rate of return

averaged around 14.2 percent (20).

Preferred stock was about 12 percent of total

outstanding electric utility capitalization in 1980.

In the same year, approximately $2.0 billion of

preferred stock was issued by IOUS (or about 14

percent of total 1980 long-term financing), with

an average yield of 12.28 percent (20).

Finally, IOUS may use internally generated

capital or retained earnings to finance capacity

additions. The amount of retained earnings available for financing usually is reflected by the ratio

of dividends to net income, or the payout ratio.

IOUS have had to pay a major portion of their

net profits in dividends in recent years (75.8 percent in 1980), reducing their ability to finance

projects internally. In 1980, retained earnings

were the smallest source of capital available to

utilities (about 12 percent of total capitalization)

(20).

Publicly Owned Utilities.–Publicly owned

utilities’ advantages over IOUS in financing new

capacity include their smaller size and thus lower

capital needs, their self-regulating (in most cases)

and tax-exempt status, and their absence of concern about protecting shareholders’ equity. Yet

this does not mean that they are totally without

financing problems.

As with lOUs, the predominant form of municipal utility financing is long-term debt (73 percent

of total 1979 capitalization) —mostly electric revenue bonds or general obligation bonds. Municipal bonds are attractive to investors because of

their tax-free interest, but their average yield is

lower as a result (4.9 percent in 1979). Equity

financing for municipal utilities is a combination

of direct investment by the municipal government

and the retained surplus from operating revenues.

The retained surplus is extremely important for
66 . Industrial and Commercial Cogeneration

municipal’ ability to build a base for expansion;

it averages about 10 times the amount of direct

investment by the municipal government (18). In

1979, retained earnings represented an average

of 25.5 percent of municipal’ total capitalization

(25).

The primary sources of long-term financing for

cooperatives are insured loans and loan

guarantees from the Rural Electrification Administration (REA). REA makes insured loans to

the local distribution co-ops at interest rates of

2 to 5 percent, based on a revolving fund that

has a borrowing “floor” and “ceiling” specified

annually by Congress. Loans from the revolving

fund are repaid from borrowers’ operating revenues and from collections on outstanding REA

loans (16). Since 1973, REA also has been authorized to make 100-percent loan guarantees to

power supply borrowers–mostly G&Ts–for the

construction and operation of powerplants and

related transmission facilities. These guarantees

are made almost entirely by the Federal Financing Bank, which borrows money from the U.S.

Treasury. In fiscal year 1981, 34 REA loan

guarantee commitments were made to power

supply borrowers; they accounted for about 85

percent of REA’s total fiscal year 1981 electric

financing programs. Interest rates on REA loan

guarantees averaged about 15 percent (45).

REA insured loans are supplemented by money

raised by the National Rural Utilities Cooperative

Finance Corp. (CFC) in the public bond market.

Co-ops that receive REA insured loans are required to obtain from 10 to 30 percent supplemental financing from non-REA sources such

as CFC (which is a giant nonprofit co-op owned

by about 85 percent of the rural electric co-ops).

CFC bonds accounted for approximately 4 percent of all rural electric co-op financing in fiscal

year 1981 (see table 15).

Regulatory Considerations.–Almost all aspects

of utility finance are regulated at either the State

or Federal level or both. As in rate regulation, the

States have primary jurisdiction over intrastate

utility financial transactions while the Federal

Government regulates interstate financing arrangements as well as those with antitrust implications.

In general, State regulation focuses on prior

approval of IOU’S issuance of mortgage and debenture bonds and other long-term debts (e.g.,

notes over 1 year), and of common and preferred

stock. Some PSCS also regulate declarations of

dividends and budgets for capital expenditures.

For public utilities, the authority to issue bonds

derives from the State constitution or statutory

authority. In many cases, a municipality must also

obtain voter approval before issuing new bonds.

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

fiscal year)

REA

guarantee Other

Year REA 20/0 REA 5°A commitments CFC financing Total

1969 . . . . . . . . 100.0% — — — — 100.0 ’%0

1970 . . . . . . . . 100.0 — — — 100.0

1971 . . . . . . . . 96.6 — — 3.4% — 100.0

1972 . . . . . . . . 72.2 — — 15.3 12.5% 100.0

1973 . . . . . . . . 32.4 52.80/o — 13.6 100.0

1974. . . . . . . . 3.1 26.0 45.80/o 4.9 20.2% 100.0

1975. . . . . . . . 5.1 28.7 58.2 7.7 0.3 100.0

1976 . . . . . . . . 10.3 24.5 57.6 5.1 2.5 100.0

TQ . . . . . . . . . 7.6 22.5 64.8 3.3 1.8 100.0

1977. . . . . . . . 5.3 11.4 77.9 2.9 2.5 100,0

1978. . . . . . . . 5.1 20.8 66.2 6.0 100.0

1979. . . . . . . . 3.3 11.5 80.5 3.7 0.9 100.0

1980. . . . . . . . 2.0 11.3 81.4 4,3 0.9 100.0

1981 . . . . . . . . 2.8 10.6 78.7 4.0 3.9 100.0

SOURCE: 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 Electrlc

Comparative Association, peraonat communication to the OffIce of Technology Asaaaament.
Ch. 3—Context for Cogeneration . 67

Federal jurisdiction over electric utility ownership and financial operations includes regulation

of debt and equity financing of holding companies and their acquisition of other entities, sales

and purchases of utility property, and the issuance of securities by both the Securities and

Exchange Commission (SEC) and FERC. In general, SEC regulates holding companies* under the

Public Utility Holding Company Act of 1935

(PUI-ICA) in order to simplify their structures and

to prevent abuses similar to those that occurred

during the 1920’s. SEC also regulates IOUS under

the Securities and Exchange Commission Act of

1935 to protect investors and the public by providing accurate information about a wide range

of factors that may affect a utility’s financial position, and thus the relative risks associated with

investment in its securities. Finally, under the provisions of the Federal Power Act, no utility may

issue securities, or assume any financial obligation or liability (e.g., as guarantor, endorser, surety, etc.) with respect to securities, without authorization from FERC. FERC also must approve any

utility sale, lease, or other disposition of property worth more than $50,000, as well as mergers

or consolidations of such property, if it finds they

are reasonably necessary or appropriate for the

utility’s corporate purposes, are in the public interest, and will not impair the utility’s ability to

provide service. Utilities may file the same reports

on securities with both FERC and SEC in order

to eliminate unnecessary paperwork.

Taxation.–Like financing, utility tax liability

depends to a large extent on ownership. IOUS

are fully liable for all taxes—income, excise, property, and sales as imposed by various levels of

government–whereas Federal and municipal

utilities usually are exempt from all tax liability.

However, Federal and municipal utilities often

make payments to local governments in lieu of

property taxes (about 25 to 50 percent of the

otherwise exempted taxes). Cooperatives generally are exempt from income and excise taxes but

liable for property and sales taxes. In addition,

*Holding companies are defined in PUHCA as those that directly or indirectly control 10 percent or more of the outstanding voting

securities of a utility (or other holding company) or that, in the judgment of SEC, could exercise a controlling interest over the management or policies of a utility or holding company sufficient to make

regulation necessary in the public interest.

cooperatives that derive more than 15 percent

of their total revenues from nonmember services

are liable for income taxes. In 1980, tax payments

by IOUS averaged 12.7 percent of electric department operating revenues (20). The tax breakdown for 1980 is shown in table 16.

Taxation is primarily an issue in electric utility

finance and regulation to the extent it allows

special treatment that will reduce the cost of

capital investments. The primary forms of special

tax treatment are the investment tax credit and

accelerated cost recovery coupled with special

federally mandated accounting rules.

The investment tax credit (ITC) encourages investment in new, used, or leased business property that is placed in service after 1980 and that

has a useful life of at least 3 years. The property

must be depreciable (i.e., either tangible personal

property or an improvement to real property used

in qualifying manufacturing or service businesses). Buildings and real property are specifically excluded from eligibility. Since 1975, treatment

of utilities under ITC provisions has been roughly

equal to that of other businesses.

The amount of ITC depends on the accelerated

cost recovery (ACRS) for the property. Property

in the 3-year ACRS class (cars, light trucks, and

research and development equipment) is eligible for a 6-percent credit, and all other property

receives a 10-percent credit. There is a $125,000

limit for qualifying investments in used property

from 1981 through 1984, and a $150,000 limit

after 1984. If the available investment tax credit

Table 16.—Taxes Paid by Investor-Owned Electric

Utilities–Electric Department Only, 1980

Amount Percent o f

(millIons of operating

dollars) revenue

Federal taxes:

Income . . . . . . . . . . . . . . . . . . . . . . . . . . . . $1,242 1.5 ”/0

Deferred taxes on Income . . . . . . . . . . . 1,347 1.7

Other charges In lieu of taxesa . . . . . . . 1,392 1.7

Miscellaneous . . . . . . . . . . . . . . . . . . . . . . 1,492 1.9

Total Federal taxes charged to income . . 5,473 6.8

State 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 /rrdustry, 1980, (VWshlngton, D. C.: Edlaon Electric Inatltute, November

19s1).
68 ● Industrial and Commercial Cogeneration

exceeds a taxpayer’s liability in any year, the excess credit may be carried forward for 15 years

or backward for 3 years.

In addition to the standard ITC, an extra 10-

percent credit may be available for investments

in certain qualifying energy property (see table

17) through December 1982. This energy tax

credit is not available on that portion of an investment which is financed by tax-exempt or

other subsidized financing (e.g., industrial development bonds). Moreover, public utility property

(with the exception of hydroelectric equipment)

does not qualify for the energy tax credit. Other

than the exceptions outlined above, the rules pertaining to the energy credit generally parallel

those for the ITC.

The ITC and energy credit represent a direct

reduction in tax liability (for those businesses with

sufficient tax liability to benefit from it) that, in

Table 17.—Energy Property Eligible for ITC Under

the 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, or

other similar property defined in regulations,

4.

5.

6.

the principal purpose of which is to reduce the amount of

energy used in any existing industrial or commercial process and which is installed in an existing industrial or commercial facility.

Equipment used to sort and prepare for recycling or to recycle solid waste.

Equipment for extracting oil from shale.

Equipment for producing natural gas from geopressurized

brine.

SOURCE: OffIce of Technology Assessment.

effect, reduces the cost of equipment purchases.

Thus, these credits decrease the amount of investment capital needed without reducing the

basis for cost recovery purposes. At present,

many electric utilities have accumulated large

backlogs of excess credits due to the percentage

offset limitations and the accompanying carryback and carryforward provisions (see table 16).

If State regulators allow utilities to retain the

benefits of the ITC, they usually are used to help

defray the costs of construction of new generating

capacity rather than passed on to customers immediately.

The second form of tax treatment that can

reduce the cost of capital investments is accelerated cost recovery. The Internal Revenue

Code allows a deduction for “the exhaustion,

wear and tear (including a reasonable allowance

for obsolescence)” of business or investment

property. Accelerated cost recovery allows property to be written off before its useful life has

ended, either by shortening the useful life or by

concentrating larger deductions in the early years

of the asset’s useful life. Under the Economic Recovery Tax Act of 1981 (ERTA), cogenerators

placed in service after December 31, 1980, would

be in a 5-year cost recovery class, while public

utility property would be in a 5-, 10- or 15-year

class, depending on its depreciation class under

the previous tax laws.

In a competitive industry, much of the reduced

capital cost that results from accelerated cost

recovery would be passed on to customers in the

form of lower prices. With regulated utilities,

however, the State commissions have had to

decide whether the taxes incorporated into the

revenue requirement should be only those actually paid (i.e., the benefits of accelerated cost

recovery are “flowed through” to customers in

years of tax savings) or whether the taxes should

be “normalized” over the life of the investment

(i.e., the taxes included in the revenue requirement will be higher than actual taxes in the early

years and lower in later years and the benefits

are retained by the utility). Under ERTA, a public

utility that wants to take advantage of ACRS and

ITC must use normalization accounting to compute 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 tax

and ratemaking purposes.

In 1976, accelerated cost recovery is estimated

to have reduced customer rates by about $1.3

billion (2.2 percent) and utility tax payments by

about $2 billion (51 percent). The ITC reduced

rates to a much smaller extent (perhaps $200

million), but decreased utility taxes by $1.3

billion. The combined effect was a 2.6-percent

reduction in customer billings, an 84-percent

decrease in Federal tax payments by utilities, and

a 20-percent ($2 billion) increase in the cash flows

of normalizing utilities. In 1979, it is estimated

that tax incentives provided IOUS with $3 billion

per year additional construction funds (equivalent

to 15 percent of annual construction expenditures). In some cases, these tax incentives may

represent the only source of internal funds for

utilities (1 5).

Other provisions of Federal tax law that provide investment incentives for utilities include a

deduction for interest paid to bondholders that

reduces the cost of debt financing; a deduction

for IOUS of about 30 percent of the dividends

paid on preferred stock; and, a deduction for the

costs of repairs or improvements to depreciable

property based on a specified annual percentage

of the property’s cost.

REGULATION OF SERVICE AND OPERATIONS

The third major area of electric utility regulation is State and Federal jurisdiction over utility

service and operations. The primary concerns of

such regulation are to ensure adequate service,

to protect the public health and welfare, and to

further national policy goals related to fuel use.

Service Regulation.– State PSCS have broad

authority over utility services, including granting

the right to serve, defining service territories, and

approving major capacity additions. The primary

mechanism by which a PSC exerts control over

these activities is the certificate of public convenience and necessity, which essentially is a permit to operate a utility. In addition, many PSCS

also have jurisdiction over the operating characteristics of private (and some public) utilities, including authorizing or requiring interconnections,

requiring utilities to operate as common carriers,

ordering the joint use of facilities among two or

more utilities, and requiring line extensions within

a utility’s service territory (see table 18).

The Federal Government’s primary role in regulating utility service is through its authority over

interconnection and coordination among utilities.

Under section 202(a) of the Federal Power Act

of 1935, FERC (formerly FPC) was directed to

Table 18.—State Regulation of Utiiity Service and Operations

Number of PSCS according to -

type of utility regulated

Authority Investor-owned Public Co-op

Certificate of convenience and necessity

required for:

Generating capacity additions . . . . . . . . . . . . . . . . 25 9 15

Transmission line additions. . . . . . . . . . . . . . . . . . 28 14 20

Distribution system additions . . . . . . . . . . . . . . . . 20 11 13

Other plant additions . . . . . . . . . . . . . . . . . . . . . . . 16 8 11

Initiating service . . . . . . . . . . . . . . . . . . . . . . . . . . . 31 13 20

Abandoning facilities or service . . . . . . . . . . . . . . 34 17 21

Regulate State exports . . . . . . . . . . . . . . . . . . . . . . . . 6 2 3

Allocate unincorporated territory among utilities . 33 14 22

Establish standards for:

Voltage levels. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41 17 24

Safetv. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 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 the

voluntary interconnection and coordination of

facilities for the generation, transmission, and sale

of electric energy” in order to ensure an abundant supply of electricity throughout the United

States “with the greatest possible economy and

with regard to the proper utilization and conservation of natural resources.” Once these districts

were established, the Federal Government’s role

was limited to promoting and encouraging voluntary interconnection and coordination of facilities

within and among them.

PURPA expanded FERC’S authority in regard

to interconnection and coordination in a number

of ways. Section 205(a) of PURPA authorizes

FERC (either on its own motion or upon receipt

of an application) to exempt a utility from State

laws, rules, or regulations that prohibit or prevent voluntary coordination, including agreements for central dispatch, if the coordination is

designed to obtain the economic utilization of

facilities and resources in any area. Section 205(b)

directs FERC to study the opportunities for energy

conservation, increased reliability, and greater efficiency in the use of facilities and resources

through pooling arrangements. Where such opportunities exist, FERC may recommend to utilities that they voluntarily enter into negotiations

for pooling. Finally, PURPA expanded FERC’S authority to order interconnections to include those

with qualifying cogeneration and small power

production facilities, and to include wheeling

orders. These provisions are discussed in detail

in the next section.

Public Health and Welfare.–Regulation of

utility operations in the interests of protecting the

public health and welfare focuses on safety standards and on environmental protection. At the

State level, the primary responsibilities include

the implementation of federally mandated programs as well as the establishment and enforcement of minimum standards for voltage, metering accuracy, customer and employee safety, and

emergency situations and curtailments.

Such Federal legislation affects powerplant

siting and operation substantially through requirements for environmental impact assessments

and pollution monitoring and control, as well as

through provisions that limit the available sites

for large generating facilities. The most important

Federal programs in this area include:

The National Environmental Policy Act of

7969 (NEPA), which requires all Federal

agencies to include a detailed environmental impact statement on every major Federal

action significantly affecting the quality of the

human environment.

The C/can Air Act sets National Ambient Air

Quality Standards that are implemented

through standards of performance for new

stationary sources and guidelines for State

control strategies for existing sources, and

through guidelines for regulatory programs

designed to improve air quality in non-attainment areas and to prevent degradation of air

quality in clean air areas.

The Clean Water Act imposes effluent limitations on quantities, rates, and concentrations

of chemical, physical, biological, and other

constituents discharged into navigable

waters, and are implemented through ambient water quality standards, effluent standards for new and existing sources, standards

for thermal discharges, and permit programs.

The Resource Conservation and Recovery

Act of 1976 seeks to control the land disposal

of solid wastes (e.g., fly and bottom ash,

scrubber sludge) through a system of State

plans and permits for solid waste disposal.

The Atomic Energy Act, which includes comprehensive licensing and permitting procedures for both the construction and operation of nuclear powerplants.

The Occupational Safety and Health Act

(OSHAJ which establishes standards for the

protection of workers, requires recordkeeping, and sets up a process for periodic inspections and the filing of complaints.

The Endangered Species Act of 1973, which

requires that all Federal departments and

agencies consult with the Secretary of the interior to ensure that actions authorized,

funded, or carried out by them do not jeopardize the continued existence of these

species or result in the destruction or adverse

modification of their habitat.

The National Historic Preservation Act of

1970 which requires all Federal agencies to
Ch. 3—Context for Cogeneration ● 71

●

●

●

determine whether a proposed action will

affect a site or structure listed or eligible for

listing in the National Register and, if so, to

obtain comments from the Advisory Council on Historic Preservation.

The Fish and Wildlife Coordination Act of

1970, under which Federal agencies must

consult with the Department of the Interior’s

Fish and Wildlife Service and with the State

agency having jurisdiction over fish and

wildlife prior to taking any action potentially affecting surface waters.

Army Corps of Engineers requirements that

all projects affecting navigable waters obtain

a permit from the Corps.

The Coastal Zone Management Act, which

requires Federal agencies to obtain certification that proposed actions are consistent

with approved State programs.

Although this list of Federal programs is not allinclusive, it offers a general idea of the scope of

laws and regulations that affect the siting, construction, and operation of central station generating plants. These regulations can lengthen the

Ieadtime for siting and building a powerplant, require technological and other environmental controls in plant design and operation, and impose

significant monitoring and recordkeeping requirements during plant construction and operation, all of which increase the direct costs of electricity generation.

Regulation of Fuel Use.–Prior to 1973, the

choice of fuel for utility and industrial plants was

primarily a matter of resource availability, economics, and convenience, as influenced by indirect regulation through tax and environmental laws, and price controls. Then, natural gas

shortages and the 1973 oil embargo drastically

changed the economic and supply considerations

of fuel use and introduced direct Federal regulation. The primary Federal regulations on fuel use

that 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 encourage

greater use of coal and other alternate fuels as

the primary energy source in utility, industrial,

and commercial generation of electricity or thermal energy, and thus to conserve oil and gas for

other uses. To achieve these purposes, FUA prohibits the use of natural gas or petroleum as a

primary energy source in new electric powerplants and new major fuel-burning installations* and provides that no new electric

powerplants may be constructed without the

capability to use coal or any other alternate fuel

as a primary energy source. FUA also prohibits

existing powerplants from using natural gas as

their primary energy source after 1990 and, in

the meantime, from switching from any other fuel

to natural gas or from increasing the proportion

of natural gas used as the primary energy source.

Moreover, the Secretary of Energy can issue prohibition orders for the involuntary conversion of

existing powerplants to coal or another alternate

fuel if the owner or operator of the powerplant

commences the proceeding by filing an affirmative certification that the plant has the technical

capability to use coal or another alternate fuel,

or could have that capability without substantial

physical modification or reduction in rated capacity, and it is financially feasible for the facility to use coal or other non-premium fuels.

Through December 1980, FUA prohibition orders had been issued for 53 oil burning units–

mostly powerplants—and another 13 units were

undergoing voluntary conversion to coal. In addition, 33 powerplants and 15 major fuel-burning

installations (MFBIs) are subject to outstanding

conversion orders under an earlier law (the

Energy Supply and Environmental Coordination

Act of 1974). Together, these 114 units have the

potential to displace around 400,000 barrels (bbl)

of oil per day (19).

FUA prohibitions are subject to a wide range

of temporary and permanent exemptions. The

temporary exemptions are granted for a period

of 5 years; some of these can be extended to a

total of 10 years but in no case beyond December

31, 1994. The most widely used of these exemptions is a special public interest exemption for the

temporary use of natural gas in existing power-

*The provisions of FUA apply to powerplants and other ~tationav

units that have the design capability to consume any fuel at a heat

input rate of at least 100 MMBtu/hr or to a unit at a site that has

an aggregate heat input rate of at least 250 MMBtu/hr.
72 . Industrial and Commercial Cogeneration

plants that would otherwise burn middle distillates or residual fuel oils. The 1,058 petitions for

this exemption that have been granted or are in

process have the potential to displace 83,523

bbl/day middle distillate, 323,825 bbl/day residual

fuel oil with a sulfur content of 0.5 percent or less,

and 236,950 bbl/day residual with greater than

0.5 percent sulfur (or a total of 644,298 bbl/day)

(19).

The actual effect of FUA on fuel use in existing

and new powerplants and MFBIs is difficult to

determine without a case-by-case analysis. The

considerations imposed by the act must be

viewed in the context of economic, technical,

and managerial concerns. Absent a FUA prohibition order or exemption request, it is not always

possible to identify the determining factor in electric utilities’ fuel choice. Many energy analysts

argue that it became cheaper to convert existing

oil-fired plants to coal or to replace them with

new coal or nuclear plants when the price of

residual fuel oil reached $30 to $40/bbl (2,46).

However, the economics of displacing existing

oil-fired capacity may be outweighed by utilities’

financial problems and the costs of using alternate fuels. Thus, fully two-thirds of the capacity

that is economically feasible to convert has yet

to be converted. Moreover, of the 66 units being

converted under FUA, only 13 are doing so voluntarily (i.e., without a prohibition order), and

those 13 represent only about 4 percent of the

total potential oil displacement in the 66 units

(19).

NGPA was designed to increase energy supplies while reducing domestic consumption. In

general, the act distinguishes among a number

of different classes and categories of natural gas

according to the date the gas is committed to interstate commerce, whether the well is onshore

or offshore, and the depth and location of the

reservoir. Varying price schedules that would

eventually lead to decontrol are established for

the different classes and categories. These

schedules are supplemented with rules for allocation and pricing of gas to final consumers. Residential customers generally have first priority for

supplies under contract to interstate pipelines,

with any remaining supplies spread through various lower priority commercial and industrial customers. There are complicated resale price schedules for all customer classes, with the highest

priority generally being given the lowest of all

outstanding prices.

NGPA assigns the lowest priority industrial gas

users an incremental price equal to the new gas

wellhead price plus regulated pipeline transportation margins. This higher incremental price is

mitigated through a ceiling determined by the alternative fuel oil price. In some areas, the ceiling is based on number two distillate fuel and in

others on residual fuel. Several users that otherwise would be subject to the higher incremental prices are specifically exempted, including

small industrial boilers (using less than an average

of 300 MCF/day); agricultural uses for which alternative fuels are not economic or available;

schools, hospitals, and other institutions; electric

utilities; and qualifying cogeneration facilities

under section 201 of PURPA.

Current Status of Electric Utilities

Economic, energy, and utility analysts agree

unanimously that the electric power industry—

particularly the investor-owned portion-is in

trouble due to its deteriorating financial condition (34,64). The symptoms are abundant, including declining real returns on equity and interest coverage, increased capital spending and

debt/equity financing combined with high dividends per share, high payout ratios, and low

market-to-book values. This situation represents

a somewhat abrupt turnaround in the industry’s

financial health. During the two decades from

1945 to 1965, utilities accommodated rapid demand growth while continually lowering prices

by taking advantage of economies of scale in

generation as well as greater efficiency in

transmission and distribution. Capital expenditures remained relatively constant on a percustomer basis and utility costs actually declined

in some years although prices within the economy in general were rising. Return on equity rose

steadily, most utilities had high bond ratings, and

the market-to-book ratio more than doubled.

Moreover, during those two decades energy consumption in general moved in line with other

economic activity as electricity demand grew at
Ch 3—Context for Cogeneration . 73

roughly twice the rate of the economy and far

faster than energy usage as a whole. The price

of electricity declined on an absolute basis as well

as relative to prices as a whole and to the price

of competing fuels (34).

However, 1965 is considered the watershed

year for the electric utility industry. In that year,

stock prices, rate reductions, and interest coverage ratios peaked, while a number of events

reshaped utility capital investment such that

money spent would not necessarily lead to reduced costs. For example, the Northeast blackout

required expenditures to improve reliability of

service, but those expenditures would neither

reduce costs nor automatically be associated with

increased revenues. Similarly, the environmental movement required capital expenditures that

did not make plants more efficient or increase

capacity. The military buildup in Vietnam signaled the onset of high inflation rates and brought

construction delays and labor productivity problems. Emerging natural gas shortages caused utilities to shift to more capital-intensive types of powerplants, including coal and nuclear fueled plants,

that took longer to build, cost more, and operated

less efficiently (34).

As a result, capital spending accelerated, rate

base increased more rapidly than sales, and a

larger percentage of financing requirements had

to be met through new capital (i.e., sales of

securities). The combination of rising interest

rates, an increasing amount of debt, and relatively

slow growth in income resulted in decreasing interest coverage ratios and a decline in the quality of utility debt, and thus even higher interest

rates. The combination of higher interest rates

and lower return on equity pushed stock prices

down until they fell well below book values. The

average market-to-book ratio went from an alltime high of 2.35 in 1965 to a low of 0.67 in 1974,

and back up to 0.80 in 1978. Thus, during a

period when securities were claiming an ever

larger share of total capitalization, each new issue

further diluted the interests of shareholders. At

the same time, utilities began to capitalize an

allowance for funds used during construction

(AFUDC) in their income statements, which increased the non-cash portion of their reported

earnings. Therefore the overall decline in return

on equity was greater than was apparent from

the reported figures. The only available solution

to the problem was to increase rates (34).

in 1970, the average price of residential electricity increased for the first time in 25 years, and

has 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 average

price of all electricity also has risen–from a low

of $.0154/kWh in 1969 to a high of $.0437/kWh

in 1980 (4.72 WkWh for IOUS) (20). However,

the rate relief obtained in the last 10 years has

been inadequate to raise interest coverage and

return on equity to their previous levels and bond

ratings have fallen, increasing interest charges still

further. Moreover, although the price of electricity did not increase as rapidly as those of competing fuels, it did go up more than prices as a

whole throughout the economy.

The electric power industry’s problems up until

the early 1970’s were compounded by other factors during the last decade. First, the 1973-74 oil

embargo drastically changed both fuel supplies

and prices, and utility customers cut back on

electricity consumption. In 1974, electric usage

per customer decreased for the first time since

1946, and the previously steady pattern of rapid

growth (about 8 percent per year from 1947 to

1972) changed dramatically.** But the industry

had geared its capital spending and its expense

budget to the previous sales gains. Capacity additions begun before 1974 became excess capacity as these gains failed to materialize. Moreover,

much of the new capacity installed or announced

in the years immediately preceding the embargo

was oil-fired in response to environmental objections to coal and to uncertainties in natural gas

supplies. This decline in demand growth caught

utilities in a squeeze between high fixed costs and

declining base rate revenue due to falling sales

(34).

A second factor that dramatically affected utility

fortunes during the 1970’s was one utility’s omission of a common stock dividend—a first for the

utility 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.
74 ● Industrial and Commercial Cogeneration

utility stock average fell 18 percent, and by September had fallen 36 percent, the largest drop

in any calendar year since 1937. Also, 1974 was

the year that market-to-book ratios hit their low

of 0.67. The increased risk in utility stocks carried over to the market in lower quality bonds,

and for the first time, investors had to consider

the possibility of a financial risk in utility securities,

and utilities had to face the prospects of even

higher costs for new capital (34).

A third major event affecting the electric power

industry during the 1970’s was the accident at

the Three Mile Island (TMl) nuclear powerplant

in 1979. Even before TMI, some investors had

been leery of nuclear-oriented utilities because

of the huge sums involved in one project that

could be delayed or halted by a determined opposition. The TMI accident added another risk–if

an operating nuclear plant went out of service,

the power company might have to purchase far

more expensive electricity from other utilities. If

the regulators did not allow the purchased power

costs to be passed on to consumers, the utility

could suffer serious financial losses. General

Public Utilities, whose subsidiaries owned TMI,

was forced to omit its dividend and was unable

to place securities in the public market after the

accident. In conjunction with a weakened financial state and excess generating capacity in many

areas, the accident accelerated the cancellation

or deferral of nuclear projects by many electric

utilities (34).

Based on some indicators, the general economic and financial deterioration of the electric power

industry that began in the late 1960’s and continued through the 197o’s seems to have begun

to turn around. Electric utility earnings began to

rise sharply in late 1980 and continued to increase

through 1981. The gain in earnings lifted the average return on equity (for a sample of 85 electric

utilities representing 95 percent of IOU revenue)

to 12.3 percent by September 1981 —the highest

return earned since the late 1960’s. The proportion of capital spending financed with internally

generated funds (including common equity) rose

with the return on equity, reaching 43 percent

late in 1981, entirely offsetting the decline that

occurred during 1979 and early 1980 (63).

However, other indicators are not so favorable.

Even though the earned rate of return has increased steadily in the last 2 years, it still lags

behind the authorized return–estimated to be

about 14.2 percent in 1980. In addition, although

operating revenues have risen (by 18.3 percent

in 1980) due to a combination of increases in

rates, fuel adjustment clauses, and sales to

ultimate customers, the gains in revenues were

more than offset by increased operating expenses

(up 19 percent in 1980), primarily due to higher

fuel costs (20). Similarly, the increased percentage of equity financing has not been sufficient

to offset the record high interest rates. Utility interest expenses have continued to rise at more

than 20 percent annually while interest coverage

ratios (the ratio of net income and income taxes

to interest expense) have remained relatively

static for the last 2 years. In late 1981, the average

interest coverage ratio was 2.47 with AFUDC, and

2.01 without AFUDC. Common stock dividend

payout ratios have risen steadily, to a record 75.8

percent in 1980 (compared to a traditional IOU

payout ratio of 65 to 68 percent). Finally, sales

of stock have continued to dilute the book value

at a rate that more than offsets the contribution

of retained earnings (63).

As long as interest rates remain high and earned

returns on equity remain lower than authorized,

utilities will continue to have trouble regaining

their financial health. Without additional aggressive rate relief, growth in earnings is likely to

continue to lag behind that of revenues. The high

interest rates would continue to favor equity financing over long-term debt, and thus continue

to erode book value and increase payout ratios

to the detriment of stockholders’ interests. As a

result, IOUS are likely to continue having trouble

financing their construction budget.

Possibie Future Paths for

the Electric Power industry

A wide range of options are available to utility

planners today, perhaps wider than at any time

in the past. The menu of generating and other

technologies from which to choose, the array of

institutional arrangements for financing and

management, the possibilities for investment on
the customer’s side of the meter—all have expanded greatly in recent years. All of these options must be considered in the context of their

potential to reduce utility dependence on oil and

reduce capital expenditures and operating costs,

while enabling utilities to continue to provide

reliable service and protect investors.

Given the numerous unpredictable events that

have plagued the electric power industry over the

last 15 years, utilities will have to develop plans

with sufficient flexibility to handle a wide array

of contingencies in demand growth, technology

availability, and economic conditions. In many

cases, these plans will be substantially different

in character from traditional planning, either due

to their approach to the size and mix of generating technologies, or through planned controls on

the rate or type of demand growth.

One possible way to achieve such flexibility is

for a utility to diversify its energy mix. Thus, rather

than being heavily dependent on any one fuel

(e.g., coal, nuclear), the utility’s capacity would

be spread among the available options, reducing the risk of a capacity shortfall in the event of

unexpected fuel shortages (e.g., a coal strike, a

nuclear accident). Second, utilities will have to

plan for financing flexibility. Conventional large

baseload plants are extremely capital intensive.

Because of their size, they often lead to shortterm excess capacity until sales have a chance

to grow sufficiently to match the increased

capacity. In addition, their long construction leadtimes often mean high interest charges. As was

seen in the previous section, unless these large

baseload plants substantially increase system efficiency and reduce utility costs, they can contribute significantly to financial deterioration.

Smaller capacity increments, on the other hand,

are easier to phase in as demand develops, and

allow greater short-term financing flexibility. In

this sense, the smaller additions substitute financial optimization in planning for the engineering

optimization achieved in large conventional

plants.

A third option for utility planners is to invest

in energy and fuel efficiency at the point of use.

As was seen in the discussion of the current status

of electric utilities above, one of the factors that

contributed to current utility financial problems

was utilities’ need to make capital investments

(e.g., for environmental protection, increased

system reliability) that neither reduced costs nor

served new customers. Thus, overall system productivity declined as costs increased. In order to

reverse this trend, some utilities are planning to

invest heavily in technologies that contribute to

system efficiency (e.g., conservation, load management) in lieu of new capacity.

Beyond these three major options, there are

several other steps a utility can take to improve

its financial position with regard to meeting future

service needs. For example, joint action agencies

(see discussion of utility organizations, above)

allow a utility to benefit from economies of scale

while also receiving the advantages of investment

in small capacity increments, including financial

and planning flexibility. In some areas, conversion to public ownership may be an option for

improving utilities’ financial status, since publicly owned utilities have access to lower cost capital

and do not need to be concerned with protecting stockholders’ interests.

However, utilities’ system and financial planning is only one aspect of the future of the electric power industry. Without appropriate regulation, many of the options discussed above will

not be feasible and even well-managed utilities

could face financial and service dilemmas.

Utility regulators at all levels of government also

have a wider range of options than has existed

in the past. The problems faced by electric utilities

have led to a better understanding of utility economics and its regulatory implications. The result

has been a wide range of regulatory innovations

that could complement utility planning for flexibility. But if regulators fail to take advantage of

such options, or to ensure that utilities are compensated adequately for the increased risks they

will be facing, even the most innovative utility

planning will be to no avail.
76 ● Industrial and Commercial Cogeneration

REGULATION AND FINANCING OF COGENERATION

Historically, cogenerators faced three major institutional obstacles when seeking interconnected

operation with an electric utility. First, utilities

often were reluctant to purchase cogenerated

electricity at a rate that made interconnected

cogeneration economically feasible. Second,

some utilities charged very high rates for providing backup service to cogenerators. Third, a

cogenerator that sold electricity risked being

classified as—and therefore being regulated under

State and Federal law as–an electric utility. As

a result of these and other disincentives, cogeneration was not able to compete, except in large

stand-alone industrial applications, with electricity generated in central station powerplants plus

thermal energy from conventional combustion

systems.

In recent years, however, cogeneration has attracted a lot of attention as a means of increasing energy efficiency, easing utilities’ financial

stress, and reducing the amount of oil needed

to supply electric and thermal power to buildings

and industries. Where these benefits are available

(see chs. 5 and 6), recent changes in Federal and

State regulation and in financing practices may

improve cogeneration’s ability to compete with

conventional energy conversion systems. This

section describes the regulatory and financing

considerations that may affect utility, industrial,

or commercial firms’ decisions to install cogeneration capacity.

Federal and State Regulation

A number of recent legislative initiatives are intended to clarify the role of cogeneration within

national energy and environmental policy, and

to encourage its use under those circumstances

where it would save fuel or allow increased efficiency in electric utilities’ use of facilities and

resources. The most significant of these initiatives

include PURPA which provides guidelines for relations among cogenerators, utilities, and regulators; other parts of the National Energy Act that

address the use and cost of premium fuels; and

provisions of various environmental regulations

that have been adapted to cogeneration’s special

problems and opportunities.

The Public Utility Regulatory Policies Act

Title Ii of PURPA was designed to remove the

three obstacles to interconnected cogeneration

listed above. Under section 210 of PURPA, utilities are required to purchase electricity from, and

provide backup service to, cogenerators (and

small power producers) at rates that are just and

reasonable, that are in the public interest, and

that do not discriminate against cogenerators.

Section 210 also allows FERC to exempt cogenerators from state regulation of utility rates and

financial organization, and from Federal regulation under the Federal Power Act and PUHCA.

Electric utilities also are required to interconnect

with qualifying facilities and must offer to operate

in parallel with them. In order to qualify for these

and other benefits available under PURPA, cogenerators must meet the requirements of section 201 for operating characteristics, fuel use,

and ownership.

At this time, the fate of the PURPA provisions

is unclear. In January 1982, the U.S. Court of Appeals for the District of Columbia Circuit ruled

that portions of the FERC regulations implementing PURPA were invalid. Specifically, the appeals court vacated the FERC rules on rates for

utility purchases of cogenerated power, and on

interconnections between utilities and cogenerators, but upheld the FERC regulations on fuel

use and on simultaneous purchase and sale (1).

The Supreme Court has agreed to review the appeals court decision.

As a result of this pending case, it is not possible to say definitively what is the Federal policy

on cogeneration. Therefore this section will outline the statutory provisions of PURPA and the

FERC rules implementing those provisions, and

will review the relevant court rulings and their

effect on PURPA’S implementation.

REQUIREMENTS FOR QUALIFICATION

The benefits of PURPA are afforded only to

“qualifying facilities.” Section 201 defines a qualifying cogeneration facility as one that produces

electricity and steam or other forms of useful thermal energy for industrial, commercial, heating,
Ch 3—Context fo r Cogeneration-” 77

or cooling purposes; that meets the operating requirements prescribed by FERC (such as requirements respecting minimum size, fuel use, and fuel

efficiency); and that is owned by a person not

primarily engaged in the generation or sale of

electric power (other than cogenerated power).

Ownership Criteria.–The conference report

on PURPA makes it clear that Congress did not

intend to preclude electric utilities altogether from

participation in qualifying facilities (14). Thus,

either directly or through a subsidiary company,

an electric utility can participate in the ownership of a qualifying cogenerator. Rather, the thrust

of the ownership requirement is to limit the advantages of qualifying status to cogenerators that

are not owned primarily by electric utilities or

their subsidiaries. Under the FERC rules implementing section 201, the legal test is whether

more than 50 percent of the entity that owns the

facility is comprised of electric utilities or public

utility holding companies (70). This ownership

limitation does not apply to gas or other utilities.

Efficiency and Operating Standards.–The

FERC regulations require topping cycle cogeneration facilities to meet both operating and efficiency standards. Because “token” topping cycle facilities could produce “trivial amounts of either

useful heat or power,” an operating standard

was established to distinguish bona fide cogenerators from essentially single purpose facilities.

This standard specifies that at least 5 percent of

a topping cycle cogenerator’s total energy output (on an annual basis) must be useful thermal

energy (69). There is no operating standard for

bottoming cycle plants because they produce

electricity from otherwise wasted heat, and thus

do not have the same potential for “token” production.

The topping cycle efficiency standard is designed to ensure that an oil- or natural gas-fired

cogenerator will use these fuels more efficiently

than any combination of separately generated

electric and thermal energy using efficient stateof-the-art technology (e.g., a 8,500-Btu/kWh combined-cycle generating station and a 90-percent

efficient process steam boiler). The efficiency

standard established by FERC specifies that, for

topping cycle cogenerators: 1) for which any of

the energy input is oil or natural gas; and 2) for

which installation began on or after March 13,

1980, the useful electric power output plus onehalf the useful thermal energy produced must be,

during any calendar year, no less than 42.5 percent of the energy input of oil and natural gas.

However, if the useful thermal energy output is

less than 15 percent of the total energy production, the useful electricity output plus one-half

the useful thermal energy production must be no

less than 45 percent of the total oil or gas input.

Topping cycle cogenerators that were installed

prior to March 13, 1980, and those that use fuels

other than oil and gas do not have to meet any

efficiency standards in order to qualify under

PURPA (69).

The 2-to-1 weighting in favor of electricity production in these topping cycle efficiency standards reflects FERC’S view that “systems with high

electricity to heat ratios have the highest secondIaw’ energy efficiencies,” and their development

and use should be encouraged (see discussion

of the thermodynamic efficiency of cogenerators

in ch. 4) (76). This weighting will be more

equitable to the various cogeneration technologies than a standard that simply summed electric and thermal output on an equal basis, because the latter would have made it relatively

easy for steam turbines that produce little electricity to qualify, but would have penalized higher

E/S ratio systems through difficult heat recovery

requirements.

Because bottoming cycle facilities produce

electricity from normally wasted heat, the efficiency standard only applies to those with supplementary firing heat inputs from oil and natural

gas. In such facilities, the useful output of the bottoming cycle must, during any calendar year, be

no less than 45 percent of the energy input of

natural gas or oil for supplementary firing (i.e.,

the fuels used in the thermal process “upstream”

from the facility’s power production system are

not considered in the efficiency test) (69).

Environmental Criteria.– FERC’S original requirements for qualification under PURPA denied

qualifying status to diesel and dual fuel

cogenerators built after March 13, 1980, pending

environmental review. FERC’S final environmen-
78 ● Industrial and Commercial Cogeneration

tal impact statement (FEIS), released in April 1981,

acknowledged that “an increase in the number

of diesel and dual-fuel cogeneration facilities in

an air regime may cause significant environmental effects in the near term.” But the FEIS concluded that existing State and local air quality

monitoring and permit programs would be adequate to prevent such effects, and “unregulated

proliferation of diesel and dual-fuel cogenerators

is not a realistic scenario.” Based on these conclusions, FERC has declared diesel and dual-fuel

cogenerators eligible for PURPA benefits (28).

Fuel Use Limitations.—Section 201 of PURPA

specifies that a qualifying cogeneration facility

must meet “such requirements (including requirements respecting minimum size, fuel use,

and fuel efficiency) as the Commission may, by

rule, prescribe.” In implementing this section,

FERC interpreted the statutory language as discretionary and chose not to impose fuel use limitations on qualifying cogenerators. FERC offered

four arguments to support their position that this

decision was consistent with congressional intent

and national energy policy. First, FERC reasoned

that if Congress had intended to deny qualifying

status to oil- and gas-fueled cogenerators, PURPA

would have contained explicit restrictions on fuel

use similar to those that apply to small power producers. Second, Congress did include fuel use

restrictions on oil- and gas-fired cogenerators in

FUA, which was enacted at the same time as

PURPA. Therefore, FERC determined it would be

both unnecessary and inappropriate to impose

an additional set of fuel use regulations under

PURPA. Third, FERC argued that Congress recognized that qualifying cogenerators would burn

natural gas by expressly exempting such facilities

from the incremental pricing program under

NGPA (enacted at the same time as PURPA).

Fourth, FERC noted that the findings in section

2 of PURPA require “a program providing for . . .

increased efficiency in the use of facilities and

resources.” Thus, the commission argued that oil

and gas burning cogenerators should be granted

qualifying status to the extent that they provide

for more efficient use of these resources, and the

efficiency standards discussed above would be

sufficient to ensure such use (76).

FERC’S decision was upheld by the U.S. Court

of Appeals, which agreed with these four arguments and held that the statutory language is

discretionary and that the regulations promulgated by FERC were a reasoned and adequate

response to the congressional mandate.

UTILITY OBLIGATIONS TO

QUALIFYING FACILITIES

Under section 210 of PURPA and the FERC regulations implementing that section, electric

utilities have a number of obligations to qualifying cogenerators. These include the requirement

that utilities offer to purchase power from and

sell power to cogenerators at equitable rates (including simultaneous purchase and sale), that

they offer to operate in parallel with cogenerators,

and that they interconnect with cogenerators.

Obligation to Purchase.–Section 210 of

PURPA requires FERC to establish “such rules as

it determines necessary to encourage cogeneration,” including rules that require electric utilities

to offer to purchase electric power from cogenerators. FERC interprets this provision as imposing on electric utilities an obligation to purchase

all electric energy and capacity made available

from qualifying facilities (QFs) with which the

electric utility is directly or indirectly interconnected, except during system emergencies or

during “light loading periods” (see below) (75).

PURPA specifies that purchase power rates

must be just and reasonable to the electric

utilities’ consumers and in the public interest, and

must not exceed the incremental cost to the utility

of alternative electric energy. The FERC regulations use the term “avoided costs” to represent

these incremental costs, and define them as:

The incremental costs to an electric utility of

electric energy or capacity or both which, but

for the purchase from the qualifying facility, such

utility would generate itself or purchase from

another source (68).

The energy costs referred to in this definition

are the variable costs associated with the production of electricity, and include the cost of fuel and

some operating and maintenance expenses (see
discussion of rate structures in the previous section). Capacity costs are the costs associated with

providing the capability to deliver energy; they

consist primarily of the capital costs of generating

and other facilities (75). Thus, if by purchasing

electricity from a qualifying facility, a utility can

reduce its energy costs or can avoid purchasing

energy from another utility, the rate for the purchase from the QF must be based on those energy costs that the utility can thereby avoid. Similarly, if a QF offers energy of sufficient reliability and

with sufficient legally enforceable guarantees of

deliverability to permit the purchasing utility to

build a smaller less expensive plant, avoid the

need to construct a generating unit, or reduce

firm power purchases from the grid, then the purchase rates must be based on both the avoided

capacity and energy costs (75). In each case, it

is the incremental costs, and not the average or

embedded system costs, that are used to determine avoided costs.

One way of figuring the avoided cost is to calculate the difference between: 1 ) the total capacity and energy costs that would be incurred by

a utility to meet a specified demand, and 2) the

cost the utility would incur if it purchased energy

or capacity or both from a QF to meet part of

its demand and supplied its remaining needs from

its own facilities. In this case, the avoided costs

are the excess of the total capacity and energy

cost of the system developed in accordance with

the utility’s optimal capacity expansion plan excluding the QF, over the same total capacity and

energy cost of the system including the QF (75).

The FERC rules require utilities to furnish data

concerning present and anticipated future system

costs of energy and capacity to enable potential

cogenerators to estimate avoided costs.

The FERC rules outlined three primary considerations in determining avoided costs. The first

is the availability of capacity or energy from a

QF during system daily and seasonal peakloads.

If a QF can provide electricity during peak periods

when the utility is running its most expensive generating units, the electricity from the QF will have

a higher value to the utility than power supplied

during off-peak periods when only lower cost

units are running. The relevant factors in determining the QF’s availability include:

The utility’s ability to dispatch the cogenerator will enhance its ability to respond to

changes in demand and thereby enhance

the value of the cogenerated power (see discussion of interconnection in ch. 4).

The expected or demonstrated reliability of

the cogenerator (i.e., whether it may go out

of service during the period when the utility needs its power to meet system demand)

will determine whether the utility can avoid

the construction or purchase of alternative

capacity.

The terms of any contractor other legally enforceable obligation (including its duration,

termination notice requirements, and sanctions for noncompliance) also will provide

a measure of the QF’s reliability.

If maintenance of the QF can be scheduled

during the periods of low demand on the

utility system or during periods when the

utility’s own capacity will be adequate to

handle existing demand, it will enable the

utility to avoid the expenses associated with

providing an equivalent amount of capacity on peak.

If the QF can provide capacity and energy

during system emergencies, and can

separate its load from its generation during

such an emergency, it may increase overall

system reliability and thereby enhance the

value of the cogenerated power.

The aggregate or collective value of capacity from a number of small QFs may be sufficient to enable a purchasing utility to defer

or avoid scheduled capacity additions when

none of the QFs alone would provide the

equivalent of firm power to the utility.

The Ieadtimes associated with capacity additions from QFs maybe less than the leadtime required for a utility powerplant, and

thus the QF might provide savings in the utility’s total power production costs by permitting utilities to avoid the excess capacity

associated with adding large generating units

or by providing greater flexibility in accommodating changes in demand (see ch. 6)

(72).

The second consideration in a State regulatory

commission’s determination of avoided costs

under the FERC rules is the relationship of energy
80 . Industrial and Commercial Cogeneration

or capacity from a QF to the purchasing utility’s need for such energy or capacity. If an electric utility has sufficient capacity to meet its demand, and is not planning to add new capacity,

then the availability of capacity from a cogenerator will not immediately enable the utility to

avoid any capacity costs. However, a utility with

excess capacity may plan to build new plants in

order to increase system efficiency or reduce oil

and gas use. If purchases from a QF allow the

utility to defer or avoid these capacity additions,

the rate for such purchases should reflect these

avoided capacity costs as adjusted for the lower

energy costs the utility would have incurred if it

had added the new capacity (75), That is, if deferring new construction may actually increase

power costs, the qualifying facility may be credited only with the net of the deferred and increased costs.

Third, the utilities and State commissions must

take into account any costs or savings from

transmission line losses. Power produced by a

QF maybe nearer to or farther from the service

area than the utility-generated power it supplants.

Because all power is subject to transmission losses

as a function of distance, the rate for energy provided by the QF is to be net of line losses or gains.

In general, avoided costs are determined on

a case-by-case basis. However, for small QFs, individualized rates may have very high transaction costs. Therefore, the FERC rules require

utilities to implement standardized tariffs for

facilities of 100-kW electrical capacity or less, and

permit the use of such tariffs for larger units. These

tariffs must be based on the purchasing utility’s

avoided cost, as described above, but may differentiate among QFs on the basis of the supply

characteristics of the particular technology (72).

The net avoided cost concept leads to the possibility that, despite their inherent efficiencies,

QFs may at times produce power that is more

expensive than power produced by the utility

(e.g., when the utility is under a low load situation and operating only baseload plants). Thus,

if the utility has to reduce its baseload plant output in order to accommodate power purchases

from a QF, it may also have to utilize higher cost

peaking units when load increases or supplies

from qualifying facilities drop, due to the longer

startup times of baseload plants. A strict application of the avoided cost rules under such circumstances would mean a negative avoided cost

that would have to be reimbursed by the QF. To

avoid the anomalous result of forcing a cogenerator to pay a utility for purchasing cogenerated

power, the FERC rules provide that an electric

utility is not required to purchase power from a

QF when such a purchase would result in net increased operating costs to the utility. A utility that

wants to cease purchasing from a QF due to these

operational circumstances must notify each affected QF in time for the QF to stop delivering

energy or capacity. If the utility fails to provide

adequate notice of a light loading period, it must

reimburse the QF for energy and/or capacity as

if the light loading had not occurred. The existence of a light loading period is subject to

verification by the PSC (75).

The FERC rules for purchase power rates do not

preclude negotiated agreements between cogenerators and electric utilities on terms that differ

from the PURPA provisions. However, a QF that

needs a long-term contract to provide certainty

in return on investment can still obtain a purchase

rate based on the utility’s avoided costs, either

by establishing a fixed contract price for energy

and capacity at the avoided costs at the time of

the contract or arranging to receive the avoided

costs determined at the time of power delivery

(75).

Finally, the FERC rules do not preclude States

enacting laws or regulations that provide for purchase power rates that are higher than those that

would obtain under PURPA. However, the States

cannot require rates at less than full avoided costs

because such lower rates would fail to provide

the requisite encouragement to cogeneration and

small power production (75).

As mentioned previously, the FERC rules for

purchase power rates were challenged by the

American Electric Power Service Corp. (AEP) and

several other electric utilities, who argued that

FERC’S requirement that purchase power rates

equal the utility’s full avoided costs forecloses the

sharing of any of the benefits of the purchase with

the utility’s other customers, and thus contra-
venes the PURPA section 210 requirement that

such rates be “just and reasonable to the electric consumers of the electric utility and in the

public interest.” The U.S. Court of Appeals for

the District of Columbia Circuit held that Congress, in the statute, had clearly distinguished between a “just and reasonable” rate and one

based on the full avoided cost, and that, although

“the two may coincide,” FERC had not adequately justified its adoption of a uniform full avoided

cost standard (1).

In the preamble to its final rule on purchase

power rates, FERC states that:

The Commission interprets its mandate under

section 21 O(a) to prescribe “such rules as it determines necessary to encourage cogeneration and

small power production . . . “ to mean that the

total costs to the utility and the rates to its other

customers should not be greater than they would

have been had the utility not made the purchase

from the qualifying facility (75).

FERC considered several alternative standards

that would have set the purchase rate at less than

full avoided cost, including rate standards based

on a fixed percentage of avoided costs and on

a “split-the-savings” approach. The commission

noted that these pricing mechanisms would transfer to the utility’s ratepayers a portion of the savings represented by the difference between the

QF’s costs and those of the utility, and thus would

provide an incentive for the utility to purchase

cogenerated power (75). The same argument was

made by California utilities in opposing purchase

power payments based on full avoided costs, but

rejected by the Public Utilities Commission (see

discussion of PURPA implementation, below)

(lo).

However, FERC argued that, in most instances,

the resulting rate reductions would be insignificant for individual ratepayers, while if the full savings were allocated to the QF they would provide a significant incentive to cogenerate. Furthermore, FERC felt that a “split-the-savings” approach would require a determination of the

costs of power production in a QF—exactly the

sort of cost-of-service regulation from which QFs

are exempt under PURPA. FERC also argued that

a fixed percentage standard would lead QFs to

stop producing additional units of energy when

their costs exceeded the price to be paid by the

utility, and thus could force the utility to operate

less efficient generating units or consume more

premium fuels (l).

Based on these considerations, FERC determined that only a rate for purchases that equals

the utility’s full avoided costs for energy and

capacity would simultaneously satisfy the statutory requirements that the rate be just and

reasonable to ratepayers, in the public interest,

and not discriminate against QFs, and fulfill the

statutory mandate to encourage cogeneration.

The Court of Appeals ruled that FERC had appropriately rejected the split-the-savings approach

because that would “veer toward the public utilities-style rate setting that Congress wanted to

avoid” (1). However, the court recognized that

other alternatives to the full avoided cost standard might allocate benefits between cogenerators

and utilities more evenly without requiring an inquiry into the QF’s production costs, and that

FERC should take a harder look at these alternative approaches. In particular, the court stated

that FERC should reconsider the percentage of

avoided cost approach to determine whether it

would disproportionately discourage cogeneration. The court argued that the “bare unquantified possibility that a rule permitting rates at less

than full cost might be insufficient to encourage

the last kilowatthour of cogeneration” is inconsistent with the clear intent of PURPA, which

seeks to strike a balance among the interests of

cogenerators, electricity consumers, and the

public (l).

The court also outlined several additional ways

that the avoided cost standard could disadvantage utility ratepayers, and specified that FERC

should address these in its subsequent rulemaking. First, the commission should take into account, if possible, elements of utilities’ avoided

costs that cogenerators would not also have to

pay (e.g., where the utility is subject to higher

pollution control standards than a cogenerator,

when a utility pays taxes at a higher rate than

cogenerators). Second, FERC should consider a

utility’s capacity situation. If a utility has excess
82 ● Industrial and Commercial Cogeneration

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 cost

standard precludes consideration of competitive

market forces, that might encourage utilities to

purchase a substantial amount of cogenerated

power 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 establish different standards for a variety of cogeneration cases and methods. A general rule is acceptable, but the Commission must justify and

explain it fully, particularly in its balancing of the

interests 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 those

of the local nongenerating utility.

Similarly, if the local utility has excess generating capacity and/or relatively inexpensive coal

or other alternate-fueled baseload generation, its

avoided energy costs could be quite low and it

may not have any avoided capacity costs. A

neighboring utility, however, may have excess

load or expensive oil-fired baseload plants, and

thus relatively high avoided costs.

For circumstances such as these, the FERC rules

provide that a utility that receives energy or

capacity from a QF may, with the consent of the

QF, transmit that energy or capacity to a second

utility. However, if the QF does not consent to

transmission to another utility, the local utility retains the purchase obligation. Similarly, if the

local utility does not agree to transmit the QF’s

energy or capacity, it retains the purchase obligation. Because the transmission can only occur

with the consent of the utility to which the energy

or capacity is first delivered, this rule does not

constitute forced wheeling of power (75).

The FERC rule on transmission of cogenerated

power to other utilities specifies that any electric

utility to which such energy or capacity is delivered must purchase that energy or capacity under

the same obligations and at the same rates as if

the purchase were made directly from the QF.

As discussed above, these rates should take into

account any transmission losses or gains. If the

electricity from the QF actually travels across the

transmitting utility’s system, the amount of energy

delivered will be less than that transmitted, due

to line losses, and the purchase rate should reflect

these losses. Alternatively, the transmission can

be fictionalized (as in simultaneous purchases and

sales—see below). For instance, energy and/or

capacity from a cogenerator may displace bulk

power that would have been purchased by a nongenerating utility, as in the example cited above.

In this case, the energy from the QF may replace

a greater amount of energy than would have

been purchased from the supplying utility (since

the power from the latter is subject to greater line

losses than the power from the QF), and the purchase rate should reflect the net transmission gain

(72).
Ch. 3—Context for Cogeneration ● 83

obligation to SeIl.–Section 210(a) of PURPA

also requires that each electric utility offer to sell

electric energy to QFs. The FERC regulations interpret this obligation as requiring utilities to provide four classes of service to QFs: supplementary power, which is energy or capacity used by

a QF in addition to that which it generates itself;

interruptible power, which is energy or capacity that is subject to interruption by the utility

under specified conditions, and is normally provided at a lower rate than non interruptible service if it enables the utility to reduce peakloads;

maintenance power, which is energy or capacity supplied during scheduled outages of the QF–

presumably during periods when the utility’s

other load is low; and backup power, for

unsceduled outages (e.g., during equipment failure). A utility may avoid providing any of these

four classes of service only if it convinces the PSC

that compliance would impair its ability to render

adequate service or would place an undue burden on the electric utility (73).

PURPA requires that rates for sales of these

four classes of service be “just and reasonable

and in the public interest, ” and that they not

discriminate against QFs. The FERC regulations

implementing this requirement contemplate the

formulation of rates based on traditional cost-ofservice concepts (see discussion of rate regulation in the previous section), and specify that rates

for sales to QFs shall be deemed nondiscriminatory to the extent that they apply to a utility’s noncogenerating customers with similar load or other

cost-related characteristics (73).

Thus, the FERC rules provide that rates for sales

of power to QFs must reflect the probability that

the facility will (or will not) contribute to the need

for and use of utility capacity. If the utility must

reserve capacity to provide service to a cogenerator, the costs associated with that capacity may

be recovered from the cogenerator if the utility

normally would assess these costs to noncogenerating customers. If the utility can demonstrate,

based on accurate data and consistent systemwide costing principles, that the rate that would

be charged to a comparable non-cogenerating

customer is not appropriate, the utility may

establish separate rates for QFs according to these

data and costing principles. However, any such

separate rates must still be nondiscriminatory, so

that the cogenerator is not “singled out to lose

any interclass or intraclass subsidies to which it

might have been entitled had it not generated

part of its electric energy needs itself” (73).

The FERC regulations also specify that rates for

sales of backup and maintenance power may not

be based, without adequate supporting data, on

the assumption that all QFs will experience forced

outages or other reductions in output either

simultaneously or during the system peak. Thus,

QFs are to be credited for either interclass or intraclass diversity to the same extent as noncogenerating customers, because such diversity

will mean that utilities supplying backup or

maintenance power to QFs probably will not

need to reserve capacity on a one-to-one basis.

In addition, rates for backup and maintenance

power must take into account the extent to which

a QF can usefully coordinate maintenance with

the utility (74).

Simultaneous Purchase and Sale.–The FERC

regulations specify that a utility must offer to purchase all of a cogenerator’s electric power output at avoided cost rates regardless of whether

that utility simultaneously sells power to the QF

at standard retail rates (72). In effect, this rule

separates the electricity production and consumption aspects of QFs, and thus equalizes the

treatment of facilities which consume all the

power they generate with that of cogenerators

which sell some or all of their power (75).

AEP, et al., challenged this rule on the grounds

that it misconstrued the statutory terms “purchase” and “sale,” because it requires utilities

to treat cogenerators as if they have engaged in

a purchase and sale when in fact none might have

occurred. The Court of Appeals disagreed, holding that FERC’S rule is consistent with PURPA. The

court noted that the narrower construction of the

statute urged by AEP would result—anomalousIy–in discriminatorily different treatment for

cogenerators that use some or all of their power

onsite and those that sell all their electric output.

With such a narrow construction, cogeneration

could be uneconomical because utility retail rates

usually are lower than the utility’s incremental

energy and capacity costs and the cost of cogenerating.
84 ● Industrial and Commercial Cogeneration

AEP also argued that FERC did not adequately

consider and explain its decision to require utilities to engage in the simultaneous transaction fiction. The court found that FERC had considered

the impact of this rule on all interested parties

and thus that the rule had been adequately justified (l).

Obligation to Operate in Parallel.–The FERC

rules also require each electric utility to offer to

operate in parallel with a QF, provided that the

QF meets the State standards for protection of

system reliability (71). By operating in parallel,

a QF can automatically export any electric power

that is not consumed by its own load. Thus, the

same customer circuits can be served simultaneously by customer- and utility-generated electricity.

Obligation to Interconnect. -In their regulations implementing section 210 of PURPA, FERC

argued that electric utilities’ obligation to interconnect with QFs is subsumed within the purchase and sale obligations of section 210(a).

Moreover, FERC noted that it has ample authority

to require utilities to interconnect with QFs under

the general mandate of section 210 that the commission prescribe “such rules as it determines

necessary to encourage cogeneration and small

power production” (75). Consequently, the FERC

rules specified that “any electric utility shall make

such interconnections with any qualifying facility as may be necessary to accomplish purchases

or sales” (71).

AEP, et al., challenged this rule on the grounds

that it was inconsistent with sections 202 and 204

of PURPA (which became sec. 210 and 212 of

the Federal Power Act), as well as with PURPA

section 210 itself. Section 202(a)(l) provides:

Upon application of any electric utility, Federal

power marketing agency, qualifying cogenerator,

or qualifying small power producer, the Commission may issue an order requiring—

(A) the physical connection of any cogeneration facility, any small power production facility, or the transmission facilities

of any electric utility, with the facilities

of such applicant.

In issuing an order under section 202(a)(l), the

Commission must issue notice to each affected

party and afford an opportunity for a full evidentiary hearing under the Administrative Procedure

Act.

Section 202(c) states that FERC may not issue

an order under 202(a)(l) unless FERC determines

that the order:

(1) is in the public interest,

(2) would–

(A) encourage overall conservation of energy

or capital,

(B) optimize the efficiency of use of facilities

and resources, or

(C) improve the reliability of any electric utility system or Federal power marketing

agency to which the order applies, and

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

The requirements of section 204 are that FERC

determine that an order issued under section

202(a)(l):

(1) is not likely to result in a reasonably ascertainable uncompensated economic loss for

any electric utility, qualifying cogenerator, or

qualifying small power producer . . . affected

by the order;

(2) will not place an undue burden on an electric

utility, qualifying cogenerator, or qualifying

small power producer . . . affected by the

order;

(3) will not unreasonably impair the reliability of

any electric utility affected by the order; and

(4) will not impair the ability of any electric utility affected by the order to render adequate

service to its customers.

Finally, while section 21 O(e) of PURPA authorizes

FERC to exempt QFs from provisions of the Federal Power Act, it specifically excludes sections

202 and 204 from such exemption.

In the AEP case, FERC argued that compliance

with sections 202 and 204 of PURPA would impose an undue burden on cogenerators and thus

would be contrary to the entire thrust of sections

201 and 210. in particular, FERC noted that in

enacting sections 201 and 210, Congress had

already determined that QFs serve the purpose

of the act to optimize the efficiency of use of

facilities and resources by electric utilities, and

thus it would be both redundant and unduly burdensome to require QFs to meet all the requirements of sections 202 and 204 in order to

sell power to the grid.
Ch. 3—Context for Cogeneration ● 85

However, the U.S. Court of Appeals agreed

with AEP, holding that FERC’S rule requiring interconnection was inconsistent with PURPA. The

court noted that FERC, in promulgating an interconnection rule that is consistent:

need not impose substantial administrative

burdens on those facilities, but rather can adopt

streamlined procedures. If the Commission believes that even streamlined procedures are too

burdensome, the necessary amendment must

come from Congress (1).

In its petition for rehearing of the AEP decision,

FERC emphasized the basic intent of PURPA to

encourage cogeneration, and argued that, without the interconnection requirement, the obligation to purchase and sell is meaningless. FERC

also contended that PURPA section 210 is independent of, and does not amend, the Federal

Power Act, and thus the interconnection requirement must be read into PURPA and the section

202 and 204 provisions interpreted as an alternative means of obtaining interconnection.

If the AEP decision is upheld by the Supreme

Court, then QFs who cannot get a utility to agree

to interconnect will have to apply for a FERC

order under the procedures outlined in section

202(a)(l), and thus meet the evidentiary requirements of sections 202 and 204. However,

the requirements of sections 202(c) and 204

would be very difficult and expensive for a QF

to meet. Even in well-understood situations, the

expenses and delays associated with evidentiary

hearings under the Administrative Procedure Act

will deter all but those who have a pressing need

for an administrative order. But the multiple

stringent legislative tests of sections 202(c) and

204 are couched in new, broad language that will

have to be construed, first, by FERC and then,

in all likelihood, by the courts. Thus, these provisions pose a substantial deterrent to cogenerators that cannot get an electric utility to voluntarily interconnect with them–exactly the problem PURPA was intended to remedy. Options for

resolving this issue are discussed in chapter 7.

Under the FERC regulations implementing

PURPA, a QF must reimburse any electric utility

that purchases energy or capacity from the facility

for interconnection costs. These costs are defined

in the regulations as:

. . . the reasonable costs of connection, switching, metering, transmission, distribution, safety

provisions, and administrative costs incurred by

the electric utility and directly related to the installation and maintenance of the physical facilities necessary to permit interconnected operations with a qualifying facility, to the extent that

such costs are in excess of the corresponding

costs which the electric utility would have incurred if it had not engaged in interconnected

operations, but instead generated an equivalent

amount of electric energy itself or purchased an

equivalent amount of electric energy or capacity from other sources (68).

Interconnection costs must be assessed on a nondiscriminatory basis with respect to noncogenerating customers with similar load characteristics, and may not duplicate any costs included

in the avoided costs (74). Standard or class

charges for interconnection may be included in

purchase power tariffs for QFs with a design

capacity of 100 kW or less, and PSCS may also

determine interconnection costs for larger facilities on either a class or individual basis.

State regulatory commissions have the authority to ensure that utility requirements for system

safety equipment and other interconnection requirements and their associated costs are reasonable. In practice, utility interconnection requirements vary widely (see ch. 4) and few PSCS

have addressed the interconnection question

directly.

OTHER PURPA BENEFITS

Qualifying cogenerators are exempt from regulation as a public utility or a utility holding company under the Federal Power Act and PUHCA,

and from State laws regulating the rates, structure, and financing of utilities. However, if a regulated electric utility owns more than a 50-percent equity interest in a qualifying cogenerator,

the cogenerator will be subject to the traditional

jurisdiction of ratemaking authorities to the extent of utility ownership. In addition, qualifying

cogenerators may be eligible for an exemption

from the FUA prohibitions on oil and gas use and

from the incremental pricing provisions of NGPA.
IMPLEMENTATION OF SECTION 210

The FERC regulations on section 210 of PURPA

required State public utility commissions (PUCS)

to begin implementation of the regulations by

March 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 for

cogenerated power (see table 19). The State PUCS

have taken full advantage of the procedural latitude allowed by the FERC rules, using rulemaking, adjudication, and dispute resolution to esFrom QFs by State-Regulated Utilities

Capacity payments

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

Alabama

Alabama Power Co.

Arkansas

Arkansas Power & Light Co.

California

Pacific Gas & Electric Co.

Southern California Edison

San Diego Gas & Electric Co.

Connecticut

Connecticut Light & Power Co. and

Hartford Electric Light Co.

Idaho

Utah Power & Light Co.

Washington Water Power Co.

Idaho Power Co.

Illinois

Illinois Power

Commonwealth Edison

Central Illinois Light Co.

2.59 on-peak, June-October

2.17 off-peak, June-October

2.14 on-peak, November-May

2.05 off-peak, November-May

Reverse metering currently used

6.58 on-peak

6.219 mid-peak

5.553 off-peak

6.030 non-TOD

6.6 on-peak

6.0 mid-peak

5.8 off-peak

6.0 non-TOD

8.333 on-peak

7.069 mid-peak

6.225 off-peak

6.850 non-TOD

Firm power

6.7 on-peak (114.5% of fossil fuels cost)

5.4 off-peak (90.5% of fossil fuels coat)

Nonflrm power

6.6 on-peak (110% of fossil fuels cost)

5.2 off-peak (86.5% of fossil fuels cost)

Firm power 1,2

Non.firm power 2.6

Firm power 1.6

Nonfirm power 2.4

Firm power 1.639

Nonflrm power

1.41-3.86 (varies each month,

2.4 average)

2.42 on-peak summer

1.55 off-peak summer

2.65 on-peak winter

1.88 off-peak winter

Non-TOO:

1.89 summer

2.18 winter

5.31 on-peak summer

2.90 off-peak summer

5.17 on-peak winter

3.37 off-peak winter

34 kV or greater

2.3 on-peak

2.1 off-paak

12 kV to 34 kV:

2.4 on-peak

2.2 off-peak

Less than 12 kV:

2.5 on-peak

2.3 off-peak

$0.75-$1.50/kW-month

25% of full value

$0.70-$2.00/kW-month

88-268 Increasing with

contract length

4-35 years.

96-280 Increaslng with

contract length

4-35 years.

0.3cents/kWh

116-318 Increasing with

contract length

4-35 years.

Nuclear 24%, coal 58%, oil 1%, gas 3%, hydro 14%.

Off peak purchase rates are offered for utilities without

time-of-day metering. Rates are for facllities Iess than

100 kW.

Nuclear 17%, coal 9%, oil 44%, gas 10%, hydro 20°A

Comments on proposed rates were due by

June 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 approval of utlllty proposals. Percentage is tied to

monthly fuel adjustment. Firm power rates are for

facilities greater than 100 kW. Off-peak purchase

rates are offered for facilities without tlme-of-day

metering. No size restrictions apply to non-flrm

facilities.

Oil 1%, gas 3%, hydro 96%

The Idaho PUC has ordered UP&L to add some capacity credit to the non-flrm energy payment.

Rates are for facilities less than 100 kW.

The Idaho PUC has ordered IPC to add some capacity

credit 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 payments

utility 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 Public

Service Co.

Public Service Co. of Indiana

Southern Indiana Gee & Electric

Richmond Power & Light

Kansas

Kansas Power & Light

Massachusetts

Boston Edison

Commonwealth Electrlc

Eastern Edison

Massachusetts Electric

Cambridge Electric

Nantucket Electrlc

Manchester Electric

Fitchburg Gas & Eiectrtc

Western Massachusetts Electric

Michigan

Statewide purchase rate includes:

Consumers Power Co. and

Detroit Edison

Mlnnesota

2.45 on-peak, June-September

2.05 off-peak, June-September

2.19 on-peak, October-May

2.05 off-peak, October-May

1.978 on-peak summer (3 months)

1.620 off-peak summer

1.884 on-peak winter (3 months)

1.861 off-peak winter

1.805 on-peak (rest of year)

1.565 off-peak

2.30 on-peak

1.70 off-peak

Non. TOD:

1.77 summer

1.53 winter

TOO:

2.41 on-peak summer

1.36 off-peak summer

1.50 summer, weekends and holidays

1.86 on-peak winter

1.35 off-peak winter

1.35 winter, weekends end holidays

TOO:

1.36 on-peak

0.81 off-peak

Non.TOD: 0.81

1.14 general rate

Seaaonal:

1.19 on-peak summer

1.07 off-peak summer

1.28 on-peak winter

1.08 off-peak winter

2.62 on-peak summer

2.29 off-peak summer

2.61 on-peak winter

2.29 off-peak winter

Norr. TOD seasonal:

1.86 summer

1.83 winter

1.33

1.49 on-peak summer

1.02 off-peak summer

1.15 on-peak winter

1.00 off-peak winter

0.914

1.60

6.971 on-peak

4.047 off-peak

5.543 flat

7.16 on-peak

6.15 off-peak

6.51 flat

8.792 on-peak

5.161 off-peak

5.995 fiat

5.51 on-peak

4.79 off-peak

5.08 fiat

7.22 on-peak

5.91 off-peak

6.34 fiat

7.44

4.748

6.081 on-peak

3.313 off-peak

4,940 flat

5.813 on-peak

4.238 off-peak

4.979 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 months

when fuel adjustment is figured. QFs of 30 kW or less

can 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 or

April of 1982.

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

other 2%.
88 . Industrial and Commercial Cogeneration

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

Capacity paymenta

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

Northern States Power Co,

Montana

Montana Power

Montana-Dakota

Pacific Power & Light

Nebraska

Omaha Public Power District

Nevada

Idaho Power

Sierra Pacific

Nevada Power Co.

New Hampshire

Statewide rate

New Jersey 

Firm power

2.08-3.07 increasing with contract length

5-25 years.

TOD metering service:

2.15 on-peak

1.39 off-peak

Nonfirm power : 1.35

Occasional power 1.66

2.7842

Nonfirm power

2.21 on-peak

1.57 off-peak

Non firm, non-TOD: 1.91

Firm power:

1.97-3.08 (depending on contract length)

1.34-1.88

TOD metering:

1.60 on-peak summer

1.00 off-peak all year

1.20 on-peak winter

Standard rate: 1.10

1.71 (February)-

4.16 (August)

4.09

3.802 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 8.2

Nonfirm power 7.7

Jersey Central Power and Light Co. Approximate only:

6.0-7.5 on-peak

2.0-5.0 off-peak

Atlantic City Electric Co. Temporary rate: 2.5

New York

77.24 (25-yesr contract

only)

3.75-7.37 per kW-month

116.00-263.00 (1981)

6.1cents/kWh

8.55 on-peak

October 1981

0.07 off-peak

October 1961

0.14 on-peak

November 1981

0.00 off-peak

November 1981

0.14 on-peak

December 1981

0.00 off-peak

December 1981

Statewide minimum rate includes: 6.00 minimum

Long 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 others

North 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

month

2.074.04 off-peak 1.29-2.08 non-summer

months

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

months

1.78-3.91 off-peak 0.68=1.00 off-peak

months

Virginia 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-summer

2.82-5.77 all others

Nanthahala Power & Light Co. 2.05 2.50

North 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 studies

are completed. These rates are intended to comply

with PURPA requirements and are restricted to facilities less than 100 kW. Capacity credits are included

in firm power purchase rates. Non-firm power rates

take effect in the event that a firm producer does not

provide dependable generation. Occasional power is

limited 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 vary

by 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 marginal

energy rates for previous 3-month on-peak and offpeak hours. The rate appiies to facilities between

10 and 1,000 kW.

This October 1980 rate was greater than average

energy costs. The utility has proposed that buyback

rates may be set at time of interconnection.

Nuclear 13%, coal 8%, oil 83%, hydro 15%°, gas and

other 1%.

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

Rates increase with contract length.

Rates increase with contract length.

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. Capacity

payments 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 payments

Utlllty 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 rates

for various types of small power producers. Both

energy 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 of

capacity

Statewide rate schedule includes:

Oklahoma Gas & Electrlc Co.

Public Service Co.

Oregon Reverse metering currently used

Rhode Island

New England Power Co. 5.5247 on-peak

4.5339 off-peak

4.9643 average

Primary:

6.412 on-peak

4.642 off-peak

5.511 average

Secondary:

6.726 on-peak

4.965 off-peak

5.723 average

4.473 on-peak

4.093 off-peak

4.317 average

Blackstone Valley Electric Co.

Newport Electric Co.

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

other 1%.

Rates are for facilities less than 5 MW.

South Carolina

Carolina Power & Light Co.

Duke Power Co.

46.68 summer

40.20 non-summer

60.00 (Based on

integrated capacity

during peak months

June-September,

December-March).

2.60 on-peak

2.07 off-peak

1.96 on-peak

1.49 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 considered

case-by-case (up to 3.5cents/kWh).

Utah

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

C.P. National

Vermont

Statewide rate schedule

2.2 (temporary rate) 2.66cents/kWh

Nuclear 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 accounting practices of NEPOOL.

7.8 standard rate

TOD rates:

9.0 on-peak

6.6 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.

Wisconsin

Wisconsin Power & Light Co.

Madison Gas & Electric Co.

1.60 on-peak

1.75 off-peak (includes capacity)

2.75 on-peak summer

1.50 off-peak summer

2.22 on-peak winter

1.50 off-peak winter

Firm power:

3.65 on-peak summer

1.45 off-peak summer

3.45 on-peak winter

1.45 off-peak winter

Non firm power:

2.90 on-peak

1.45 off-peak

For 20 kW or less:

1.81 on-peak

1.14 off-peak

For 21-500 kW after 1986:

1.60 on-peak

1.14 off-peak

1.90

Wisconsin Electrlc Co.

Northern States Power Co. $4/kW/month Prior to 1966 the rates for 20 kW and less apply to

21-500 kW. No capacity credits will be paid until after

1966. Facilities greater than 500 kW are treated

case-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 facilities are considered case-by-case.

Wisconsin Public Service Corp. 1.65 on-peak

1.32 off-peak

To be determined

according to characteristics 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 purchase

Utah Power & Light Co.

rates are “experimental.”)

Non-firm power: 2.2

Firm power 2.6

Cheyenne Light, Fuel and 0.53

Power Co.

Tri-County Electric Association

Available on demonstration of demand

reduction.

1.07

0.405

This is a non-generating utility which has based its

avoided costs on wholesale supply rates.

Montana-Dakota Utilities Co. Available on demonstration of capacity displacement or demand

reduction 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 procedures have resulted in a wide diversity in State

approaches to PURPA as well as in the rates established thereunder. A comprehensive survey

of State implementation actions and cogeneration potential is beyond the scope of this assessment. Moreover, the status of these actions is

uncertain due to the Court of Appeals case discussed above. Therefore, this section will present

case studies based on the implementation of title

II in three areas: California, where cogeneration

has a potentially large market and the State government is actively promoting its use; Illinois,

where cogeneration’s technical potential could

be significant but the market will be limited by

the electric utilities’ large construction budget;

and New England, where existing excess capacity, extensive pooling agreements, and planned

conservation measures will influence cogeneration’s market potential. It should be emphasized

that these case studies do not typify the range of

State and utility actions on PURPA. Rather, they

represent examples of three kinds of planning

situations that will affect PURPA’S implementation. The same case study areas are used in the

analysis of cogeneration’s potential impacts on

utility planning and regulation in chapter 6.

California.—The dominant factor in California

utilities’ capacity planning is not demand growth,

but the need to reduce their dependence on oil.

Planning and construction of new coal and nuclear baseload facilities was limited during the

1970’s as demand growth declined, and cancellations and postponements of coal and nuclear capacity left the State’s utilities heavily dependent

on oil and natural gas. The California Energy

Commission’s (CEC) 1981 final report on electricity projects an annual energy growth rate (measured in GWh) of less than 1.5 percent through

1992, but a capacity growth rate of approximately

2.5 percent per year (5). The capacity growth rate

is higher because it includes a projected 30-percent reserve margin (in case the energy growth

rate is higher than 1.5 percent), the replacement

of retired powerplants and expired purchase

power contracts, and the reduction of utility oil

and gas consumption Statewide to one-half the

1979 level by 1992.

The CEC report identifies three priorities that

should be sufficient (according to the report) to

provide the needed energy and capacity for the

1980-92 period: 1) additional conservation and

power pooling; 2) geothermal and renewable resources (biomass, wind, solar, small hydro, and

existing reservoirs); and 3) cogeneration and interstate electricity transfers. CEC estimates that

cogeneration could provide up to 3,000 MW of

generating capacity by 1992. Their estimate is

bracketed by the California utilities’ long-range

resource plans, which project 1,900 MW of cogeneration capacity by 1992, and the Natural

Resources Defense Council estimate of 4,300

MW by 1995 (5).

State regulators in California had taken a number of regulatory actions favoring cogeneration

even before the FERC rules implementing PURPA

section 210 became final. The California Public

Utilities Commission (CPUC) investigated the role

of cogeneration in utility resource planning (see

fig. 13) and, in 1979, ordered Pacific Gas& Electric (PG&E), in particular, and all of the State’s

electric utilities in general, to adopt a specific

timetable for bringing cogeneration capacity into

the electrical system. Under the CPUC order,

PG&E was expected to bring 2000 MW of cogeneration into the resource base by 1985, principally through contracts tied to the avoided cost of

oil-fired utility capacity that is displaced (8). In

a companion decision (this time in a PG&E general rate case), CPUC imposed a rate-of-return

penalty on the company’s electric division for failure to implement cogeneration projects aggressively. The penalty, which represented over $7

million in annual revenues, or 0.2 percent in

return on equity, was to be restored if PG&E

brought 600 MW of cogeneration capacity under

contract by 1982 (7). Although PG&E was not able

to meet this goal, the CPUC staff recommended,

late in 1981, that the penalty be discontinued

because the utility’s performance in encouraging cogeneration has been adequate (41).

PG&E planners argue that the CPUC goals of

2,000 MW by 1985 are unrealistic. In a major

planning study, PG&E estimated the cogeneration market potential in their service area to be

between 204 and 903 MW of capacity additions
Ch 3—Context for Cogeneration ● 91

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 cells

160/0

Wind 2

Biomass 3

%

%

Fossil

cogeneration

Utility filing - 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 Energy

Commission, 19S1).

by 1990 (beyond the 472 MW already operating),

and their long range resource plan projects 190

MW additional cogeneration capacity by 1985,

and 600 MW by 1992. PG&E’s anaiysis suggests

that industry would have to commit approximately 12.5 percent of their total annual capital expenditures to cogeneration in order to meet the

CEC goal of 2,000 MW under contract by 1985

(41).

The California regulatory climate is unique. In

no other State has the public utility commission

participated so actively in capacity and resource

planning. Encouraging cogeneration is an explicit

policy expressed in price signals to the utility and

from the utility to the potential cogenerator. Despite these attitudes that favor cogeneration development, however, there remain significant

questions and uncertainties about the amount of

cogeneration capacity that can be counted on,

and thus about the other types of capacity additions that may be needed.

one major difficulty in assessing the extent of

future cogeneration development in California

lies in the special nature of the market, namely,

the potential for large enhanced oil recovery

cogeneration projects. The heavy oilfields in Kern

County, Calif., require steam injection or other

advanced techniques for economic production.

Converting existing steam boilers in these fields

to cogeneration would involve projects with 200

to 300 MW of generating capacity. CEC has studied at least six of these projects, and one contract has been signed for 66 MW. Aggregate cogeneration potential in the California oilfields has

been estimated by various sources to be between

700 and 10,000 MW or more, depending on the

price of oil and the cogeneration technology

employed (5,6,31 ,59).

In January 1982, CPUC issued their final decision on rates and other standards for cogeneration and small power production pursuant to the

FERC rules implementing sections 201 and 210
of PURPA. In general, this decision, known as

OIR-2, requires utilities to file standard offers applicable to QFs larger than 100 kw and tariffs for

smaller facilities. Both the standard offers and the

tariffs are complete packages that include prices

for power purchases and sales, requirements for

interconnection, and other relevant factors. Once

a utility’s tariff and standard offer terms are approved by CPUC, purchases can be made under

them without further administrative review, and

the utility can recover its expenses for such purchases through an energy cost adjustment clause

in the same manner as it recoups other purchase

power expenses (10).

Under OIR-2, utilities must file an array of

standard offers based on different terms and conditions in order to provide QFs larger than 100

kw with a sufficiently wide choice of options to

meet their particular needs, and thus to minimize

the use of nonstandard contracts that would have

to be reviewed individually by CPUC. In general,

these include standard offers for energy and

capacity delivered by a QF both “as-available”

and under a firm contract, and for energy and

capacity prices based on both the utility’s shortrun and Iongrun marginal cost.

Standard offers for “as-available” energy and

capacity are based on the utility’s avoided cost

at the time of delivery, which is the cost the utility

would have to incur to produce an equivalent

amount of power at that time, or the utility’s

shortrun marginal cost. The energy component

of this standard offer is defined as the highest

variable operating cost per unit of electricity produced at a given time, and equals the product

of: 1 ) the purchase price of oil used as the marginal fuel over the last 3 months, and 2) the

forecast incremental heat rates* of the plants actually used by the utility to follow load. The asavailable energy price also includes an aggregate

adjustment for transmission and distribution costs

and line losses or savings. In OIR-2, CPUC decided that it was not reasonable to treat these

costs on an individual basis except for facilities

larger than 1 MW at remote sites.

*Heat rate is a measure of thermal efficiency expressed in Btu

input per net kilowatthour output (see ch. 4). The marginal, or incremental, heat rate is calculated as the additional (or saved) Btu

to produce (or not produce) the next kilowatthour.

The as-available capacity payment equals a

marginal shortage cost that reflects the effects of

the added increment of production on reserve

margins and reliability, and is determined based

on the 1982 estimated cost of peaking capacity

(represented by a combustion turbine). This

capacity payment is in cents/kWh varying by time

of delivery, and is available only for energy

delivered through a meter to the utility. Thus,

simultaneous purchase and sale QFs will receive

the capacity value for all the electricity they

generate because their entire output is metered

at the generator before any goes to the QF’s load

or the utility. Other QFs will only receive the

capacity value of the electricity actually delivered

to the utility (10).

Standard offers for energy and capacity

delivered under long-term contracts can be

based on either the utility’s shortrun or Iongrun

marginal cost. For shortrun marginal costs, energy

prices can be contracted for up to 5 years based

on a forecast of the utility’s variable operating cost

(described above). The QF must commit to deliver all the electricity it produces to the utility

over the contract period. These contractual energy payments can be combined with either asavailable capacity payments or with firm capacity

payments based on shortrun marginal costs (1 O).

Firm capacity is equivalent to an increase in

supply with corresponding standards, termination

provisions, and sanctions regarding dispatchability, reliability, availability, and other factors

specified in the FERC rules. The value of each of

these factors is calculated based on the same performance standards utilities impose on their own

generating plants. If a QF exceeds utility standards, its capacity value should be increased correspondingly. The sum of each of these factors

determines the overall capacity value, which is

to be offered on both a $/kW/yr and a cents/kWh

basis (10).

Alternatively, QFs can choose a contract

period of up to 25 years with a firm pricing structure for energy and capacity based on the utility’s Iongrun marginal costs. This standard offer

option was included due to concerns that shortrun marginal costs would be too volatile to provide financial certainty and would not adequately

reflect a QF’s value in the utility’s long-range
resource plans. The longrun marginal costs are

estimated based on the fixed costs associated with

the utility’s resource plan and the corresponding

system projected marginal operating costs (10).

Standard tariffs for QFs smaller than 100 kW

provide for purchase power payments in

cents/kWh calculated in the same manner as the

as-available rates for larger facilities (described

above). These tariffs may be time-differentiated,

but if a small QF chooses not to buy a time-ofuse meter, the utility may offer capacity payments

that aggregate over 1 year to 50 percent of the

capacity provided by facilities with such meters

(lo).

Both standard offers and tariffs also provide for

sales of supplementary, backup, maintenance,

and interruptible power to QFs. The first three

normally are provided under the regular rate

schedules applicable to all customers of the same

class. However, the demand charges associated

with such rates are substantially lower for QFs

than for other customers, and may be waived if

the facility maintains an 85-percent on-peak

capacity factor. Interruptible rates apply to QFs

to the extent their generation is used to serve their

own load (10).

Finally, CPUC allows nonstandard offers (those

that vary from the terms described above) when

they are necessary to shift some of a project’s risk

from the QF to the ratepayers (e.g., in the case

of debt guarantees, Ievelized payments, or payment floors). in return for accepting such risks,

ratepayers are afforded some reduction on

avoided cost payments. In general, the reasonableness of nonstandard offers will be determined

during the annual review of energy cost adjustment clauses or other normal rate proceedings.

However, during the first 2 years of OIR-2’S implementation CPUC will provide advance review

of those nonstandard offers about which a utility has significant questions (10).

It is not clear how the California Public Utilities

Commission would revise OIR-2 in the event that

the FERC regulations implementing PURPA are

revised to require payments for QF power at less

than the utility’s full avoided cost. The utilities

have argued that full avoided cost payments

based on their highest variable operating cost,

as determined by the price of oil used on the

margin, does not reflect the utilities’ actual fuel

mix, and thus does not allow ratepayers to share

the benefits of QF generation at a cost potentially below the utility’s marginal cost, nor does it

compensate utilities or their shareholders for the

potentially higher risks of reliance on QF energy

and capacity. In issuing OIR-2, CPUC considered

arguments by the patties that full avoided cost

payments disadvantage ratepayers (the same argument accepted by the U.S. Court of Appeals

against the FERC rules, as discussed previously).

However, CPUC found that only full avoided cost

payments would parallel the prices that would

be established in a competitive market, and thus

give consumers an efficient price signal and “encourage the fullest possible efficient development

of QF resources that can effectively and economically compete with utility resources” (1 O).

On the other hand, CPUC did explicitly recognize that payments at less than the full avoided

cost are appropriate when some of the risk of investing in QFs is transferred to the ratepayers.

CPUC also requested comments from interested

parties on whether utilities should receive a

percentage of the avoided cost (e.g., one-half of

1 percent) as a brokerage fee for serving as intermediaries between QFs and electricity consumers. However, in such a scheme, the full

avoided cost would still be passed on to ratepayers through the energy cost adjustment clause

(lo).

It is instructive to contrast the California

cogeneration planning situation with roughly

analogous efforts in New York by the Consolidated Edison Co. (ConEd). The potential cogeneration market in ConEd’s service territory may

be large, but the principal ConEd customers likely

to cogenerate are large commercial buildings.

Their primary economic motive would be to

avoid high electricity bills, and they are less likely to sell excess power to the utility than California projects. Given the large number and homogeneity of ConEd’s potential cogenerators, it is

possible to analyze the market systematically.

Con Ed constructed a model of the cogeneration investment decision that calculates the costs

and benefits of investing in cogeneration and
measures the internal rate of return from such investments. Where this return, on an aftertax basis,

would be 15 percent or better over a 10-year

horizon, Con Ed assumed the investment would

be made. In order to estimate market size, this

model was applied to the load data describing

ConEd’s 4500 largest customers. Depending on

input assumptions, Con Ed found a high range of

up to 750 potential cogenerators with a combined

peakload of 1,483 MW, and an expected outcome or base case of 395 cogenerators with a

combined peakload of 1,086 MW. ConEd has

used this model to characterize the sensitivity of

market size to the policies that would reduce their

“loss exposure” to cogeneration (48).

ConEd’s loss exposure stems from a fixedcost/declining demand problem. Because demand is not expected to grow, cogenerators leaving the system will shift a burden of fixed costs

onto the other remaining customers. This would

not be a problem if there were enough new kWh

sales or customers to replace the cogenerators

leaving the system, but ConEd does not anticipate

such growth. Situations such as the fixed-cost/

declining demand problem, in which cogeneration has a potential to operate to the financial

detriment of utilities, are discussed in more detail

in chapter 6.

If State regulators are asked to protect utility

sales from loss exposure, the utilities must

demonstrate that the problem is real and substantial in magnitude. ConEd’s cogeneration model

purports to make such a demonstration. However, the New York Public Service Commission

(NYPSC) argued that the model results were extremely sensitive to input assumptions, and asked

Con Ed to run the model using slightly higher costs

for cogenerators but holding utility rates constant.

The result was an extremely small market potential, with only 27 customers (130 MW of peakIoad) 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 actual

market may be either smaller or larger than this

estimate, and until market penetration is more

certain, no policy changes are needed to protect

ConEd’s sales from loss exposure.

This loss exposure problem has not arisen in

California. Thus, while CPUC is creating a climate

favorable to large-scale cogeneration development, it also is encouraging or ordering utilities

to aggressively pursue conservation plans, including developing investment/finance plans for

residential weatherization and solar water heating

retrofit (9).

Illinois.–Electric utilities in Illinois currently are

engaged in a massive construction program that

began before the 1973 escalation in oil prices.

The largest companies, Commonwealth Edison

(CWE) and Illinois Power (1P) are most heavily involved in new construction. CWE has six nuclear

units at various stages of completion, while 1P,

a company roughly one-fifth the size of CWE, has

one.

The financial burden of this construction has

become increasingly onerous as utility kwh sales

growth has lagged behind expectations. In the

case of CWE, the strain has appeared in the rapid

decline of their bond rating. In June 1980, Standard and Poor’s lowered the rating on CWE debentures and pollution control bonds to BBB, the

lowest rating acceptable to institutional investors.

The rapid downgrading threatens to limit the

market for CWE debt securities, because investors

may not want to risk the possibility of further

rating cuts (35).

Moreover, in order to finance their $1 billion

per year construction program, CWE needs more

cash income. In 1979, CWE reported $297 million in net income to stockholders, but $222

million of this was for AFUDC. Thus, 75 percent

of net income did not represent cash (compared

to an industrywide 1979 average of 38 percent)

(13). To improve CWE’S cash flow (as well as that

of 1P), the Illinois Commerce Commission (ICC)

has allowed some portion of construction work

in progress (CWIP) to be included in the rate

base. 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 relatively few options for the utility and the State

regulators. ICC has initiated investigations into

electric load forecasting and reserve margin/

reliability issues, but the only feasible option is

delaying part of the CWE construction program.

With this option, the tradeoff is between extra
fuel savings and avoided escalation of costs from

completing construction, versus delayed fixed

charges by postponing it. The relative value of

these factors depends on the projected growth

rate in kWh sales. Lower sales growth means

smaller fuel savings and a decreased value of

completing construction. In its study of delaying

two of CWE’S nuclear units, the ICC staff found

that even with zero growth in kWh sales, it was

better to complete construction without delay

(65).

In contrast to the California regulatory system,

ICC has not developed an independent forecasting capability. Instead it has channeled its administrative resources into financial analysis and

production cost modeling to allow independent

regulatory assessment of the costs and benefits

of construction delays (albeit with many engineering assumptions determined by utility data). The

production cost modeling will provide a basis for

establishing purchased power rates as required

by PURPA section 210. By contrast, the California agencies have devoted relatively few resources to financial and production cost modeling, but instead have concentrated on demand

forecasting (35).

Given the lack of flexibility in any of the construction commitments of CWE and 1P, ICC has

chosen to avoid conflict over future demand

growth expectations. The sensitivity of ICC to the

financial strains of the utilities makes it unlikely

that any effort will be directed toward demand

reduction policies (35). The more relevant question in this jurisdiction is the extent to which ICC

can shelter the utilities from the damaging financial impacts of competition either from conservation measures or from cogeneration and small

power production.

ICC established purchase power rates for QFs

based on a time-of-day rate structure that reflects

avoided costs both on-peak and off-peak as well

as seasonal adjustments. These rates vary depending on the utility’s fuel mix. Thus CWE—which

is roughly 40 percent coal, 30 percent oil, and

30 percent nuclear—offers energy payments onpeak that are only slightly lower than those offered by PG&E (see table 19). However, the other

major Illinois utilities, which have 85 to 98 percent coal-fired capacity, have much lower

avoided costs. None of the Illinois utilities is offering capacity payments to QFs, due to the current excess capacity situation in that State (39).

The future avoided cost path for CWE depends

critically on the growth rate of kwh sales. High

growth will require continued reliance on oil and

gas for a significant fraction of annual energy requirements, but at an average annual rate of 2

percent or less the primary avoidable fuel will be

coal. Average avoided fuel cost estimates for CWE

during 1981-88 are shown in figure 14 for growth

rates of zero and 2 percent. Figure 14 illustrates

a situation of declining avoided costs; other CWE

calculations indicate a more conventional outcome, with increasing avoided costs over time

(35). While the declining cost outcome is by no

means 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/om

P/arm/rig and Regu/at/orr (contractor report to OTA, February 1981).
potential investor in cogeneration if economic

feasibility depends on sales of excess power to

the utility.

New England .–Electric power planning in

New England is dominated by the influence of

the New England Power Pool (NEPOOL), a regional pool that fully integrates both operations

and planning, and by the fragmented nature of

the regional utility industry. Most New England

utilities are small by national standards, and even

the larger New England systems are associations

of small companies. Under these conditions it

would be impossible for any individual company

to achieve the economies of scale offered by large

baseload units without undue risk and extra cost.

By cooperating in joint venture projects, however, the New England utilities are able to overcome the regional fragmentation and to capture

economies of scale. From a regional perspective

this has been a significant political achievement

(35).

The New England utilities also can purchase

capacity from NEPOOL for minimal cost due to

the substantial excess capacity on the system (the

NEPOOL reserve margin in 1979 was 38.6 percent or 5890 MW above the 15,278 MW winter

peakload) (17). A NEPOOL member can meet his

capacity responsibility by paying a “deficiency

charge” of $22/kW annually to the pool. If the

deficiency is above 2 percent, then an additional

$14/kW is required for this capacity (57). Even

allowing for some escalation in these charges, this

is a much lower opportunity cost of capacity than

that estimated for potentially capacity short

regions such as California. PG&E, for example,

is currently offering over $60/kW/yr for short-term

capacity contracts in the early 1980’s (54).

The principal problem facing NEPOOL and the

New England utilities is reducing oil dependence

in face of the deteriorating financial condition of,

and increasing opposition to, the region’s

planned nuclear power projects. With the substantial generation reserves in NEPOOL, approval

of new projects is more difficult politically. The

extreme regulatory risk is that completed projects

will not be entered into the rate base on the

grounds that they are unnecessary. Such a ruling has recently been made in Missouri (43).

Given the relatively large number of jurisdictions

in New England, the requirements for political

consensus on large-scale projects is severe. Barring such consensus, the economy of scale capacity expansion strategy will fail (35).

Within this planning context, the New England

States have adopted a variety of means of implementing PURPA, including two statewide approaches (New Hampshire and Vermont), and

one based on the cost differences between a

generating utility and its nongenerating subsidiaries (Massachusetts). Although most State

regulatory commissions have adopted standard

purchase power rates based on each individual

utility’s capacity mix and operating characteristics, nothing in PURPA precludes statewide or

even regional rates if they are appropriate and

they further PURPA’S goals of encouraging cogeneration and small power production and promoting the efficient use of utility facilities and

resources. Statewide or regional rates may be

perceived as advantageous when, as in New

England, the operations of utilities are closely integrated so that they effectively form a single

power system. In this case, a rate that reflects the

avoided costs of the system rather than of individual utilities may provide a better signal of

the value of QF power throughout the State or

region (38,75).

The New Hampshire PUC established a statewide rate for utility purchases of QF power that

uses, as a substitute for individual utility’s avoided

costs, the operating and maintenance costs of

“the most recently constructed and most efficient

oil generating station” (Newington) of the State’s

largest utility (Public Service of New Hampshire)

(38). Newington’s running costs were deemed to

be a “reasonable proxy” for statewide full

avoided costs because the other utilities in New

Hampshire also rely primarily on oil for electricity

generation from units with operating costs at least

as high as Newington’s.

The New Hampshire purchase rate can be

raised to reflect the avoided costs of less efficient

units when the load exceeds Newington’s capacity or when Newington is not operating. However,

the rate cannot be lower. That is, the PUC established a lifetime guaranteed minimum (or
Ch 3—Context for Cogeneration ● 97

“floor”) rate for all QFs that begin operation prior

to the completion of Seabrook I (a large nuclear

unit). The guaranteed minimum encourages oildisplacing QFs to come on-line as soon as possible rather than waiting to see how avoided costs

will be affected by the completion of Seabrook,

and provides assurance that QFs will have a

steady income stream despite the volatility in oil

prices. If avoided costs do drop after Seabrook

I is completed, QFs that come on-line before then

will be subsidized through the guaranteed minimum, but such subsidies are authorized under

the New Hampshire Limited Electrical Energy

Producers Act, the State’s “mini -PURPA.” Thus,

the primary question surrounding the guaranteed

minimum rate is whether future PUCS will be

bound by the decision of the present PUC or will

discontinue the guarantee (38).

The Vermont Public Service Board based their

statewide purchase rate on the estimated avoided

costs of NEPOOL, as determined by the average

of the actual operating costs of three of the

region’s most efficient oil-fired baseload plants.

The result was similar to that achieved in New

Hampshire (see table 19). The Vermont rates will

ensure that QFs are not paid more than the cost

of oil-fired units in operation at any time, and will

enable the State’s utilities to readily market QF

power either through NEPOOL or elsewhere. The

rates are subject to annual revision, but cannot

be decreased by more than 10 percent in any

year without a strong factual showing that a

greater reduction is justified (38). This procedure

does not provide as much protection against

changes in avoided costs as the New Hampshire

guaranteed minimum, but it does limit the rate

of decrease if NEPOOL’S avoided costs drop suddenly (e.g., if a new, more efficient baseload plant

comes on-line) and it conforms to the traditional

ratemaking practice of not subjecting consumers

to sudden, drastic changes in rates. As in New

Hampshire, the Vermont rate guarantee could

result in some subsidization of QFs, but probably

will average out over time and thus be within the

limits on such subsidies anticipated in the FERC

reguIations.

A third approach was necessary in Massachusetts to accommodate “all-requirements” contracts among the corporate members of the New

England Electric System, a public utility holding

company whose subsidiaries include a wholesale

generation and transmission company (New

England Power) and two retail distribution companies that have “all-requirements” contracts

with New England Power (a third distribution sub

sidiary purchases at least 75 percent of its electricity needs from New England Power). Under

the FERC rules implementing PURPA, avoided

cost calculations are supposed to be based on

the supplying utility’s costs if the power is actually

wheeled, and otherwise on the nongenerating

utility’s cost of purchased power. The Massachusetts Department of Public Utilities (DPU) petitioned FERC for avoided cost rates based on the

supplying utility’s costs, when the two utilities are

corporate affiliates, regardless of whether the

power actually is wheeled. DPU argued that such

rates would reflect “the true avoided costs of producing that power by the appropriate utility system,” rather than an intracorporate transfer price

that might be kept artificially low (38). Although

FERC has not issued a decision on the DPU petition, this approach does not seem to be precluded by the FERC rules so long as it encourages

QF generation. However, if this approach required DPU to look at the reasonableness of the

wholesale rates between two corporate affiliates,

it could infringe on Federal jurisdiction over such

rates under the Federal Power Act (38).

The basis for setting purchase power rates in

New England is likely to be tied to oil costs for

at least the next 10 years. There is, however, more

than one way to reflect oil dependence in PURPA

rates. The New Hampshire decision, for example, is based on projected rather than actual oil

costs. Presumably such a procedure is intended

to correct the accounting lags that occur when

actual costs are used and prices are rising rapidly. The California rates discussed above achieve

a similar result by indexing rates to the average

oil cost in the previous quarter (8,1 O). The California approach will match rates more closely with

avoided costs and eliminate the uncertainty of

projecting oil prices, but also will result in lower

payments.

Given the current excess capacity in New

England, any capacity payments made to cogenerators will be limited by NEPOOL deficiency
98 ● Industrial and Commercial Cogeneration

charges. For example, the New Hampshire and

Connecticut capacity payments of 5 mills/kWh

(the difference between the payments for firm

and nonfirm power) correspond roughly to the

NEPOOL deficiency charge of $22/kW, where

this capacity would be required 4,400 hr/yr

($22/kW / 4,400 hrs = 0.5 cents/kWh) (34).

The introduction of QF power into NEPOOL

interchanges raises the question of whether

NEPOOL billing procedures might reimburse the

Vermont utilities on a basis other than full

avoided cost. NEPOOL has a complex “split-thesavings” formula that allocates 50 percent of the

saving to cover NEPOOL overhead and apportions the remaining 50 percent among utilities

based on their volume of business with NEPOOL

over a certain period. Due to the relatively low

volume of business Vermont utilities do with

NEPOOL and the large difference between the

utilities’ incremental cost and NEPOOL’S decremental cost, in most cases Vermont utilities will

not receive the full NEPOOL avoided cost for QF

power they supply to the pool. If the utilities must

pay QFs the full NEPOOL avoided cost, but recover less than that from the pool, the utilities

must either absorb the difference as a loss or pass

it on to their ratepayers. The most obvious solution is for NEPOOL to recognize QFs as “sources

of power” to utilities under the pool agreement.

This is the approach adopted by New England

Power in several recent contractual arrangements

which identify dispatchability as the main operative distinction: a purchased power resource that

can be dispatched by the utility or NEPOOL is

a generation resource. Anything else is a negative

load (38).

Alternatively, NEPOOL could change its billing practices to accommodate full avoided cost

rates by treating QF power as its marginal power

rather than mixing it in with other power furnished by a utility. In this case, NEPOOL would,

in effect, directly purchase QF power at its full

avoided cost and the utility would merely serve

as a conduit. Thus, this approach is similar to the

FERC provisions for wheeling power through a

local utility to a more distant utility.

FUTURE AVOIDED COST PATHS

Given the wide regional variation in the economic and regulatory environment of electric

utilities, uniform implementation of PURPA section 210 pricing incentives is unlikely. The pattern of avoided costs over time will depend on

existing regional fuel mix and reserve margin, as

well as on regulatory policy toward rates and

capacity expansion. Figure 15 illustrates several

generic paths for average utility avoided costs.

A given company will start off on the left-hand

side of this figure with its fuel base dominated

by oil, coal, or nuclear steam generation. As current construction is completed and fuel costs continue to increase, the fuel base and its value will

change. The basis of PURPA payments, avoided

costs, also depends on future demand growth.

To the extent that supply and demand are out

of equilibrium, there will be cost implications for

cogenerators and small power producers. One

possibility of this kind is the potential for permaFigure 15.–Generic Paths for Average Avoided

Costs (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).
Ch 3—Context for Cogeneration ● 99

nent excess capacity; e.g., if State regulators

authorize construction of central station plants

to displace oil. Resulting reserve margins maybe

so great as to preclude PURPA payments for capacity. To examine the potential variety of outcomes, it is-helpful to trace out various pathways

through figure 15.

Starting at the upper left with the shortrun

marginal cost (SRMC) of oil, several developments are possible. At some point, this shortrun

marginal cost curve will intersect the Iongrun

marginal cost (LRMC) curve. If the utility must

continue to displace large amounts of oil at this

point, the avoided cost will continue to increase

at the oil price escalation rate. Two other alternatives are possible. The utility fuel mix may be

in equilibrium when SRMC (oil) = LRMC. In this

case avoided cost becomes Iongrun marginal

cost, which is likely to rise much more slowly

than oil prices. The third alternative is permanent

excess capacity. This could occur in any number

of ways; all that is required is for construction

commitments to exceed long-term demand. In

this scenario avoided costs level out over time

and converge ultimately to the shortrun marginal

cost of coal or nuclear plants (35).

Starting out from a fuel base of excess coal or

nuclear capacity, a utility’s average avoided costs

also will eventually reach equilibrium with longrun marginal cost. This may not occur very

smoothly, as figure 15 indicates. At some time

excess capacity will be exhausted and new facilities will be necessary. At this point the avoided

cost will take a major step upward. Addition of

new facilities in such circumstances would pose

the practical problem of allocating the Iongrun

marginal cost to capacity and energy for the purpose of designing rate schedules for purchased

power (35).

Regulation of Fuel Use

Cogenerators’ fuel choice may be influenced

by the FUA prohibitions on oil and gas use and

by the allocation and pricing rules of NGPA, as

well as by environmental requirements and tax

incentives (see following sections).

The Fuel Use Act.-A cogenerator may be subject 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 any

one site exceeds 250 MMBtu/hr), and if it comes

within the statutory definition of either a powerplant or a major fuel-burning installation. Under

FUA, a powerplant includes “any stationary electric generating unit, consisting of a boiler, a gas

turbine, or a combined-cycle unit that produces

electric power for purposes of sale or exchange,”

but does not include cogeneration facilities if less

than half of the annual electric output is sold or

exchanged for resale. A major fuel-burning installation is defined as “a stationary unit consisting

of a boiler, gas turbine unit, combined-cycle unit

or internal combustion engine.” However, the

prohibition against the use of oil and gas in new

major fuel-burning installations applies only to

boilers.

Cogenerators can seek any of four different exemptions from FUA. The one most likely to be

used is the cogeneration exemption. If this does

not apply, the permanent exemption for the use

of a fuel mixture or the temporary exemptions

for the future use of synthetic fuels or for public

interest considerations may be available.

FUA allows a permanent exemption for cogenerators if the “economic and other benefits of

cogeneration are unobtainable unless petroleum

or natural gas, or both, are used in such facilities.”

The Department of Energy (DOE) interprets the

phrase “economic and other benefits” to mean

that the oil or gas to be consumed by the cogenerator will be less than that which would otherwise be consumed by conventional separate electric and thermal energy systems. Alternatively, if

the cogenerator can show that the exemption

would be in the public interest (e.g., a technically

innovative facility, or one that would help to

maintain employment in an urban area), DOE will

not require a demonstration of oil/gas savings

(72). The regulations to implement the cogeneration exemption are in the process of being revised

in order to simplify the procedures for calculating

oil and gas savings. Therefore, it is uncertain how

difficult it will be to meet the exemption requirements, and thus how FUA will affect the

market penetration of cogeneration (67).

Although the permanent exemption for cogeneration is likely to be the preferred route for
100 ● Industrial and Commercial Generation

potential cogenerators subject to the FUA prohibitions, several other exemptions may be applicable in certain circumstances. First, a permanent exemption is available to petitioners who

propose to use a mixture of natural gas or

petroleum and an alternate fuel. Under this mixtures exemption, the amount of oil or gas to be

used cannot exceed the minimum percentage of

the total annual Btu heat input of the primary

energy source needed to maintain operational

reliability of the unit consistent with maintaining

a reasonable level of fuel efficiency. Second, a

temporary exemption is available to petitioners

who plan to use a synthetic fuel (derived from

coal or another fuel) by the end of the exemption period. Third, a temporary public interest

exemption may be obtained when the petitioner

is unable to comply with FUA immediately (but

will be able to comply by the end of the exemption). One of the cases where this public interest

exemption may be granted is for the use of oil

or gas in an existing facility during the ongoing

construction of an alternate fuel-fired unit (77).

NGPA grants an exemption from its incremental pricing provisions to qualifying cogeneration

facilities under section 201 of PURPA. However,

a similar exemption also is available to small industrial boilers and to utilities. Thus, the potentially lower gas prices should not affect the relative competitiveness of gas-fired cogeneration

significantly. Moreover, plants burning intrastate

gas may not realize any savings because the fuel

price is often at the same level as the incremental price. In addition, deregulation could largely

remove incremental pricing. These uncertainties

mean that NGPA probably will not be a major

factor in cogeneration investment decisions (58).

Environmental Regulation

Federal, State, and local requirements for environmental and safety regulation will affect

cogeneration, although not to the same degree

as they do central station powerplants. The principal effects will result from permitting requirements and from the multiple jurisdictional

responsibility for such permitting, which could

increase the cost and Ieadtimes for deployment

of cogenerators and impose additional burdens

on State agencies.

THE CLEAN AIR ACT

As discussed in chapter 6, cogeneration can

have significant impacts on air quality, especially in urban areas. Depending on a cogenerator’s

size and location, it may be subject to one or

more of the Clean Air Act provisions, including

new source performance standards (NSPS) and

programs for meeting and maintaining the National Ambient Air Quality Standards (NAAQS)

in nonattainment and prevention of significant

deterioration (PSD) areas.

At present, NSPS exist for two types of sources

that might be used for cogeneration, and have

been proposed for a third. NSPS have been implemented for electric utility steam units of

greater than 250-MMBtu/hr heat input. However,

cogeneration facilities in this category are exempt

from NSPS if they sell annually less than either

25 MW or one-third of their potential capacity.

The other promulgated NSPS is for gas turbines

of greater than 10 MMBtu/hr heat input at peakIoads, but units in the 10-to 100-MMBtu/hr range

are 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 emissions

from both gasoline and diesel stationary engines.

As proposed, they would apply to all diesel

engines with greater than 560 cubic inch displacement per cylinder. Finally, the Environmental Protection Agency is considering an NSPS for

small fossil fuel boilers. The agency is reportedly considering lower limits in the range of 50 to

100 MMBtu/hr heat input. However, regulations

have not yet been proposed. Thus, only the NSPS

for gas turbines and the proposed standards for

stationary internal combustion engines seem likely to affect cogeneration systems, and then only

if they are larger than the prescribed limits.

PSD regulations would apply to fossil fuel

boilers of greater than 250-MMBtu/hr heat input

that emit more than 100 tons per year (tpy) of

any pollutant, and also to any stationary source

that emits more than 250 tpy of any pollutant

(assuming that controls are in place). A PSD permit is only issued following a review of project

plans, and an assessment of project impacts on

air quality based on modeling data and up to 1
Ch 3—Context for Cogeneration • 101

year of monitoring. These modeling and monitoring requirements can be expensive. For instance,

one estimate suggests that the requisite modeling and other PSD requirements add from

$35,000 to $80,000 to the installation costs of a

3-MW diesel cogenerator in New York City (1 2).

The application of the nonattainment area requirements to cogenerators also depends on system size; here the trigger is the capability of emitting 100 tpy of a pollutant. Sources with higher

emissions must meet the lowest achievable emission rate (LAER), secure emissions offsets, and

demonstrate companywide compliance with the

Clean Air Act. Smaller sources must use reasonably available control technology and are subject to the general requirement for “reasonable

further progress” toward the NAAQS in nonattainment regions.

OTHER FEDERAL REQUIREMENTS

In addition to the potentially extensive permitting requirements for cogenerators under the

Clean Air Act, facilities with any cooling water

discharges may also need National Pollutant Discharge Elimination System (NPDES) permits

under the Clean Water Act. The NPDES permit

generally specifies the applicable technological

controls or effluent limitations required to achieve

the water quality standards for the receiving

waters. These permits are only likely to be required for large industrial cogenerators.

Because the only major Federal permit or authorization requirements for cogenerators are

those under the Clean Air and Water Acts, they

are not likely to be subject to the NEPA process

or to the other environmental requirements applicable to central station powerplants. However,

operating cogeneration facilities can come under

the purview of OSHA, especially with regard to

noise standards and the general OSHA recordkeeping requirements. Any restrictions imposed

should not be sufficiently burdensome to discourage the deployment of cogenerators.

STATE REGULATION*

State governments are required to implement

the Federal permit processes under the Clean Air

*Except where noted otherwise, the discussion in this section is

drawn from Energy and Resource Consultants, Inc. (22).

and Water Acts. States may or may not have other

environmental or safety regulations beyond those

mandated by Federal law, and State implementation of the Federal requirements may vary widely, depending on their orientation toward regulation as well as on the regional environmental

quality. A survey of all State requirements for environmental and safety regulation of cogenerators

is beyond the scope of this report. However,

some general trends are noted below with a specific comparison of a State with more rigorous

requirements (California) and one that has few

requirements beyond those mandated by Federal

law (Colorado).

Colorado.–The permitting process in Colorado

closely tracks the requirements of Federal laws

(described in the previous section). One Colorado

environmental law deserving some explicit attention is the Colorado Air Quality Control Act

(CAQCA), which deviates from the Federal requirements in three ways. First, CAQCA requires

essentially all new or modified sources to file an

Air Pollution Emission Notice (APEN). Second, all

new or modified sources must apply for an emission permit which is required for both nonattainment and PSD areas, and which applies to virtually all fossil fuel facilities except small stationary

internal combustion engines and gas burners with

less than 750,000-Btu/hr heat input. Third,

CAQCA’S significance levels for nonattainment

areas are considerably lower than those specified

under the Federal program (e.g., 10 tpy of particulate or sulfur dioxide (S02

) rather than the

40 tpy under Federal regulations). Otherwise, the

permitting procedures under the Colorado Act

are essentially the same as those under the Federal requirements.

The length and complexity of the permitting

process for cogeneration in Colorado will depend

on the choice of site. Important site-specific factors may include whether Federal or State lands

are involved, impacts on surface waters, and ambient air quality levels. Permitting agencies should

be contacted simultaneously in order to reduce

the time required for licensing and decrease the

amount of paperwork.

For this assessment, the Colorado permitting

process was applied to two hypothetical cogeneration facilities: a large cogeneration unit consisting of a new coal-fired boiler of 200-MMBtu/hr
102 . Industrial and Commercial Cogeneration

heat input, with steam turbine topping capability, located in an urban area and not selling any

excess electricity to the grid; and a small cogeneration unit, represented by a commercial firm’s

retrofitting a 15-MMBtu/hr diesel engine to supply

a maximum of 2-MW electrical output with excess power available to the grid during times of

peak demand.

Large Cogeneration Project-Air Permits: Much

of the front range area in Colorado is nonattainment for particulate; however, with only minimal control, the 200-MMBtu/hr boiler will not

emit over 100 tpy of particulate and thus would

not be subject to the strict nonattainment area

requirements. Because the entire State is in attainment for S02 the plant would require a PSD

permit only if it emits more than 250 tpy. Assuming a 70 percent load factor and the use of coal

with a 1 percent sulfur content, the uncontrolled

S02 emissions could approach 1,000 tpy, which

would not meet the S02 emission rate of less than

1.2 lb/MMBtu for an emission permit under the

new fuel burning equipment regulations. Thus,

the sponsors for this hypothetical project must

choose between achieving a 75-percent reduction in S02 emissions or going through the PSD

permit process. Note that under the bubble concept for PSD, the source may have some emission credits from the existing boiler.

Large Cogeneration Project– Water Permits: If

the boiler’s cooling system were to result in

discharge to surface waters, a waste discharge

permit would be required, as part of the State implementation of the NPDES program. Although

existing sources can negotiate a compliance

schedule for achieving discharge limits, new

sources must meet those limits from the start.

Small Cogeneration Facility: The small

cogenerator will have to file an APEN and apply

for an emission permit. A 15-MMBtu/hr diesel unit

does not qualify as a major source under either

the PSD or new source review programs for particulate or S02

, and at present no NOX standard

has been promulgated for diesels. However, it

will be subject to the (as yet undefined) minor

source requirements for particulate because it

is located in a nonattainment area.

There is little experience with which to judge

the impacts of the Colorado permitting process

on cogeneration facilities. There are only three

cogeneration units in the State, and none is interconnected with the utility grid. Colorado has

no special laws, procedures, or exemptions that

might suggest a State “policy” toward dispersed

generating technologies. Rather the existing regulations derive principally from Federal mandates, which (except for PURPA and the cogeneration exemption under FUA) make no special

recognition of dispersed facilities. Thus, the

regulatory obstacles to dispersed facilities in Colorado are not severe. Most of the required permits and approvals can be secured in less than

6 months and at modest expense, and, furthermore, have cost and time requirements commensurate with the project size. The only regulatory

obstacles would likely be the nonattainment area

and PSD requirements for large cogeneration

units, and the time the developers will have to

spend determining what permits will be necessary

for their facilities. At present, there is no central

clearinghouse dispensing information on the permitting process.

California.– Regulation of cogeneration in

California is complex, but highly organized. The

increased complexity arises in two ways: first, due

to the large number of agencies and commissions

with regulatory responsibility in California; and

second, due to the regionalism of major regulatory programs, notably air, water, and coastal

zones. For example, the California Air Resources

Board (CARB) administers the Clean Air Act in

California. Yet 46 local and regional air pollution

control districts (APCDS) are responsible for controlling pollution from stationary sources through

permitting, enforcement, and the adoption of

control standards (often more stringent than those

required by CARB). Similarly, although the State

Water Resources Control Board administers the

Clean Water Act in California, most decisions

regarding permits and enforcement are made by

nine regional boards and their staffs.

The high degree of organization of the permitting process in California stems from the role

played by the Office of Permit Assistance (located
Ch. 3—Context for Cogeneratlon . 103

in the Governor’s Office of Planning and Research), which helps project sponsors identify and

meet regulatory requirements. The office screens

permit applications and acts as an intermediary

between projects and agencies. Another unit with

the Office of Planning and Research, the State

Clearing House, attempts to coordinate the preparation of, and comments upon, environmental

statements—either environmental impact reports

under the California Environmental Quality Act

(CEQA), or joint statements under CEQA and

NEPA.

The permitting process in California centers

around the requirement for an environmental impact report (EIR) under CEQA. If the lead agency decides that an EIR is required, one is prepared

by that agency in consultation with all other permitting agencies, who must propose definite

measures to mitigate any significant impacts identified in the EIR. The entire process is subject to

a schedule, defined by statute, such that all decisions on a project must be complete within 18

months of the date the initial application was accepted by the lead agency.

The permitting process in California was analyzed for the same hypothetical large and small

cogeneration facilities as discussed for Colorado,

above.

Large Cogeneration Project–Air Permits: Every

source of air pollution in California requires a

two-stage permit. The first stage is an authority

to construct based on a review of project plans,

and the second stage, following construction, is

a permit to operate based on a performance test.

The authority to construct and permit to operate

require compliance with the emission limitations

set by the local APCD. New source review rules

also will apply if the source triggers any nonattainment area requirements. Although the basic

nonattainment area rules (such as LAER, emission

offsets, and companywide compliance) apply

across all APCDS, each APCD determines the trigger levels, in terms of pounds of emissions per

day, for nonattainment areas. Although conceptually straightforward, the regulations generated

by 46 APCDS for several classes of sources and

half a dozen individual pollutants are voluminous.

Most APCD trigger levels for new source review

in nonattainment areas are more stringent than

the Federal requirements. Much of California is

in attainment for S02

, but the industrial areas are

generally nonattainment for TSP and NOX

. Assuming that the 200-MMBtu/hr coal boiler has

NOX emissions of 0.7 lb/MMBtu, it would emit

140 lb/hr of NOX

, thus triggering the LAER requirement. In addition, an EIR under CEQA may

be required. In any event, a final decision by the

APCD whether to issue an authority to construct

must be made within 1 year.

Large Cogeneration Project–Water Permits:

California’s waste discharge requirement program

predates the Clean Water Act but encompasses

the same sources as the NPDES and section 401

programs. For a point source discharge to surface waters, the State waste discharge requirement serves as an NPDES permit. Similarly, requests for a section 401 Water Quality Certificate

will result in either a waste discharge requirement

if the proposed project would affect water quality,

or a letter to the effect that no certificate is required because no impacts are anticipated. All

permitting is done by the regional boards in accordance with general standards and criteria

developed in their water pollution control plans

and, in the case of sources subject to NPDES,

using the various Federal technological standards.

The waste discharge requirement applies to all

point source discharges and additionally to any

discharges onto land or to a private pond, and

would thus be required for most large cogeneration projects.

Srnall Cogeneration Facility: in addition to an

authority to construct, the small cogenerator may

need to meet nonattainment area requirements

for NOX

. A 15-MMBtu/hr heat input cogenerator

with emissions of 3.5 lb/MMBtu would result in

over so lb/hr of NOX emitted. These would be

offset (under the bubble concept) by the emission level of the diesel engine before the retrofit

(if any); so the net increase mayor may not exceed the applicable trigger level.

The differences between environmental regulation in California and Colorado primarily result

from the environmental review process mandated by CEQA, and California’s aggressive but
104 ● Industrial and Commercial Cogeneration

helpful approach to regulating energy development. The guidelines under CEQA and NEPA for

conducting environmental review are quite similar; in fact, many projects will prepare statements

acceptable under both guidelines even if CEQA

alone is thought to apply. However, the impact

of CEQA in California, as compared to NEPA in

Colorado, is greater because the environmental

review process can be triggered by State, county, and municipal actions, whereas NEPA is triggered only by Federal action. Thus, many more

projects may need to prepare environmental reviews in California than in Colorado. This puts

more projects into the public arena, but should

not result in delays so long as the statutory schedules for permitting are followed.

On the other hand, there are several initiatives

in California that encourage cogeneration and

may help shorten part of the permitting process.

First, new State legislation makes it easier for 50

MW or smaller cogenerators to obtain air quality permits. Under this legislation, cogenerators

will receive an emissions credit equal to the emissions that would have come from a powerplant

generating the same amount of electricity. In addition, the statute requires CARB and the APCDS

to develop a procedure to determine the availability and magnitude of the offsets which result

when cogeneration facilities displace powerplants. Thus, in effect, the statute shifts the burden

of acquiring nonattainment area offsets from the

potential cogenerator to the APCD (1 1).

As a further aid to cogeneration, two special

administrative offices have been established to

assist prospective cogenerators with regulatory

requirements: the Cogeneration Desk of the Office of Permit Assistance, and the Project Evaluation Branch of the Stationary Source Control Division in CARB. Both of these offices are designed

to provide assistance in obtaining permits and

meeting air quality requirements. Moreover, the

Governor’s Task Force on Cogeneration (which

includes directors from CARB, the Office of Planning and Research, the California Energy Commission, and the public Utilities Commission) is

actively seeking ways to encourage cogeneration

in the State. Each of these agencies has special

personnel available to assist potential cogenerators with all aspects of their project, including

legal and technological problems. The experiences of recent California cogeneration projects suggest that environmental and other regulatory requirements are not a major obstacle,

especially for smaller facilities. However, potential cogenerators may perceive the permitting

process to be onerous, and the principal task for

State agencies is likely to be convincing potential cogenerators that the regulatory requirements

are not insurmountable.

Financing and Ownership

The basic aspects of financing electric utility

capacity additions (reviewed in the previous section) are applicable to cogenerators. A number

of other elements special to cogeneration are

discussed below, including the tax and financing aspects of cogeneration and considerations

related to the different ownership categories:

private investors, IOUS, tax-exempt entities, and

rural electric cooperatives. *

General Considerations

General considerations related to financing and

ownership of cogeneration technologies include

the ownership and purchase and sale terms of

PURPA (discussed above), the utility financing

provisions of the National Energy Conservation

Policy Act (NECPA) of 1978 (as amended by the

Energy Security Act of 1980), tax incentives of the

National Energy Act, the Windfall Profits Tax Act,

and the Economic Recovery Tax Act, aspects of

project financing and lease relationships, and

capital recovery factors.

The most important sections of the Energy

Security Act for the purposes of this assessment

are contained in title IV—Renewable Energy initiatives, and title V—Solar Energy and Energy Conservation. Title IV establishes incentives for the

use of renewable energy resources including

wind, solar, ocean, organic wastes, and hydropower; only those provisions related to the use

of organic wastes as fuel are applicable to cogenerators. Funding of $10 million in fiscal year 1981

was established to promote renewable energy re-

*Except where noted otherwise, the analysis in this section is from

L. W. Bergman & Co. (37).
Ch. 3—Context for Cogeneration • 105

sources under a 3-year pilot energy efficiency

program.

Title V set up a Solar Energy and Energy Conservation Bank in the Department of Housing and

Urban Development to make payments to financial institutions in order to reduce either the principal or interest obligations of owners’ or tenants’

loans for energy conserving improvements to residential, multifamily, agricultural, and commercial buildings. For commercial buildings, the eligible improvements specifically include cogeneration equipment. Direct grants to owners and

tenants of residential or multifamily buildings also

were authorized but were limited to lower income people. No investment tax credits (only

energy credits) were allowed for any projects installed under loans from the Solar Bank, and expenditures were to have been made after January

1, 1980. The bank was intended to continue operations through September 30, 1987, but the

fiscal year 1981 budget eliminated all funding for

the Bank and its future is, at best, highly

uncertain.

The Energy Security Act also amended NECPA

to permit utilities to supply, install, and finance

conservation improvements or alternate energy

systems (including cogenerators) as long as independent contractors and local financial institutions are used and no unfair competitive practices are undertaken by the utility. Utilities are

eligible to qualify as lenders and receive subsidies

to pass on to customers. Local governments and

certain nonprofit organizations are eligible borrowers.

In addition to the regular investment tax credit

of 10 percent on most capital investments, several

energy incentives have been passed in recent

years. Under section 48(1) of the Internal Revenue Code a number of “energy properties” are

defined and set aside for special treatment under

the investment tax credit (see section on “Taxation, ” above). Property is not eligible for these

special incentives to the extent that it uses subsidized energy financing (including industrial

development bonds), or is used by a tax-exempt

organization or governmental unit other than a

cooperative. public utility property (that for which

the rate of return is fixed by regulation) is excluded from these energy incentives even if it

utilizes solar, wind, biomass, or other alternative

sources of energy such as synthetic liquid or

gaseous fuels derived from coal.

The methods of project finance are particularly

appropriate to the financing of distributed electricity generation. project financing looks to the

cash flow associated with the project as a source

of funds with which to repay the loan, and to the

assets of the project as collateral. For successful

project financing, a project should be structured

with as little recourse as possible to the sponsor,

yet with sufficient credit support (through guarantees or undertakings of the sponsor or third party) to satisfy lenders. In addition, a market for the

energy output (electrical or thermal) must be assured (preferably through contractual agreements), the property financed must be valuable

as collateral, the project must be insured, and all

Government approvals must be available (47).

With the adoption of PURPA, a source of revenues (rates for power purchases) has become

available for small-scale energy project finance.

However, the uncertainty surrounding future

rates for power purchases (due to the 1982 Court

of Appeals decision discussed previously and the

pending Supreme Court review of that decision)

has chilled the interest of potential financial

backers of cogeneration and small power projects. The revenue stream from utility purchases

of cogenerated power is used to secure the project financing. Because the future level of that

revenue stream is in doubt, bankers and other

investors are reluctant to commit funds until the

issue is resolved.

Leasing is a form of project finance because

fixed payments are used to amortize capital

equipment. Two types of lessors may be involved

in project financing: sponsors of a project who

lease to the project company, and third-patty

leasing companies that are in the finance business. The third-party lessors may have more attractive rates because they utilize the tax benefits

of owning the equipment.

The Economic Recovery Tax Act of 1981

substantially changed the tax treatment of leasing 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 take

advantage of tax credits (e.g., already has a low

tax liability), the tax advantages can be transferred

to another party under the safe harbor leasing

provisions of ERTA. In essence, these provisions

allow the property to be sold for tax purposes

only to a corporation in a higher tax bracket. The

corporation would give the cogenerator a cash

payment (e.g., 25 percent of the property’s value)

and a note for the remainder of the purchase

price, and then lease the equipment back to the

cogenerator. Payments due under the note would

be matched exactly by the lease payments. Thus,

no money actually changes hands after the initial cash payment, and with the exception of the

tax difference between lease payments (which are

expensed in full) and income from the note

(which reflects only its interest component), the

transaction is extremely advantageous to both

parties (33).

The capital recovery factor, as used in this section, is the cost per kilowatthour which the owner

of a cogenerator must receive to recover its

capital in a given period of time. Table 20 compares capital recovery factors for four classes of

ownership that reflect different income tax structures: a nonutility investor with a 50-percent

marginal tax rate; a utility with a 50-percent

marginal tax rate; a utility with a 10-percent

marginal tax rate that is unable to take advantage

of investment tax credits because it already has

an excess of such credits; and a nontax-paying

entity. In all cases the capital recovery factors are

greatest for utilities in the high tax brackets and

lowest for nontaxable entities.

One way for an investor to get around high

capital recovery factors is to use long-term bond

financing. With high leverage, the equity investor

is able to recover his investment in a shorter

period of time because the bond holder is willing to wait to recover his capital. However, high

leverage increases the risk to the equity investor

and therefore also increases the required return

on equity. Thus, depending on the terms of debt

and equity markets, debt financing can make

these investments more attractive. It is also important to note that utilities are more comfortable

with longer capital payback periods than nonutility equity investors, and that nonprofit entities

have a different set of criteria for evaluating

investments.

Industrial, Commercial, and Private

investor Ownership

Industrial, commercial, vendor, and private

ownership share (for the most part) a common

tax status and will be discussed together. As noted

previously, energy tax credits, coupled with

regular investment tax incentives and the PURPA

benefits, encourage private firms to enter small

power production. The ability to obtain up to

25-percent investment tax credits offers an enormous boost to cash flow early in the project’s life.

These tax credits can be further magnified, in relation to invested equity, by debt leverage by a factor of 4. PURPA provides a guaranteed market

for the power output and it encourages the development of contractual relationships between

cogenerators and utilities. In project finance, such

contracts are preferable to operating under a tariff

structure because contractual relationships are

less subject to arbitrary cancellation or alteration

of the terms of delivery.

While the incremental investment tax credit for

cogeneration is limited (particularly if the cogenerator 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 paying

investor utility utility utility

5 year . . . . . . . . . . . . . . . . . . . 3.6cents 4.2cents 3.Ocents 2.8cents

10 year . . . . . . . . . . . . . . . . . . . 1.6 1.9 1.5

15 year . . . . . . . . . . . . . . . . . . . 1.1 1.2 0.99 0.93

20 year . . . . . . . . . . . . . . . . . . . 0.77 0.91 0.74 0.70

a

1980 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 report

to the Office of Technology Assessment, February 19S1).
Ch. 3—Context for Cogeneration ● 107

some experience with cogeneration and now

have the added advantage of PURPA’S purchase

and sale requirements. Continued Federal and

State Government support of simultaneous purchase and sale at full avoided costs is viewed by

some as the single most important factor in overcoming industry indecision to cogenerate (27).

Existing and potential industrial cogeneration

participants include industrial parks, integrated

pulp and papermills, other process industries

(e.g., chemicals, petroleum refining, steel, food

processing, textiles), and heavy oil recovery projects (see analysis of industrial cogeneration in ch.

6).

Financing options for industrial cogeneration

may be quite varied depending on the size and

financial strength of the industrial firm. These options include:

●

●

●

●

●

●

●

retained earnings;

debt issues (including bonds, bank loans, and

private placements with insurance companies, pension funds, and similar institutions);

equity issues;

joint ventures with other industrial firms (see

case 1 ) or with utilities;

joint partnership with equity investors such

as insurance companies (who may be both

lenders and equity investors) and tax shelter

syndicates (see case 2);

leasing arrangements with third parties and

vendors, including leveraged leases and safe

harbor leases (under ERTA); and

joint ventures and operating relationships

with tax-exempt entities such as municipalities and public power companies. Taxexempt parties can raise lower cost debt

while transferring tax ownership and tax

benefits to the private parties.

The incentive to commercial firms to invest in

cogeneration will rest heavily on a comparison

between the cost of cogenerated electricity (especially the fuel cost) and the price the commercial cogenerator pays for its electricity and heat

(comparative basis). Because of their smaller size,

commercial firms often do not have financial

resources equivalent to those of industrial firms

and will be less interested in large scale projects

unless they can be cooperatively owned (50).
708 ● Industrial and Commercial Cogeneration

Sources of financing for commercial cogeneration would be similar to those for industrial

cogeneration with the following qualifications:

● banks will be a more important source of

funds than for industrial firms;

. there will be a greater dependence on outside developers and financial packages;

● joint venture funding will be very useful for

regional malls, large buildings, and commercial parks; and

. vendors and third-party lessors will be quite

important, particularly for diesel cogeneration (see case 3).

Private investors may be interested in cogeneration because of the unusual tax incentives

available and the possibility of an above investment return in unusually promising situations.

Joint venture relationships will be most advantageous to private investors, including tax shelter

syndicates that provide the equity portion of a

leveraged lease and shift tax ownership among

the partners. Vendors might provide financing

and traditional lease arrangements, particularly

in the case of diesel cogenerators, or third parties could take advantage of ERTA’s-safe harbor

leasing provisions.

Where the owner (industrial, commercial, private investor) is a single entity and no outside

joint ventures are involved, project financing via

equity, secured or unsecured bank loans, debt,

or lease arrangements is straightforvvard. Certain

assurances or guarantees will be needed, however, in structuring the financing. These might

include:

contractual arrangements with a utility for

electricity purchases under a take-or-pay contract;

contractual arrangements with the thermal

energy purchaser; or

trustee relationships between the lender and

revenue source with excess revenues over

fixed charges remitted to the project owner.

Finally, some IOUS may also have financial assistance programs for industrial, commercial, and

other private investors in cogeneration. For example, Southern California Gas Co. offers, funding assistance of up to $100,000 or 20 percent

of the capital cost (excluding installation labor)

for their cogenerating customers. Southern California Gas will co-fund upto$10,000 for the feasibility study (or 10 percent of the study’s cost,

whichever is less). If the feasibility study is

positive, then the company will co-fund up to

$40,000 (or 50 percent) of the cost of the design

phase of the project, leaving $50,000 for installation and startup (62).

lnvestor-Owned Utility Ownership

Because almost all electric IOUS are in the business of generating electricity, they are logical

potential owners of dispersed generation facilities.

The small size, shorter Ieadtimes, and lower capital requirements of cogeneration systems may

provide short-term advantages to utilities in planning for uncertain demand growth. However, the

PURPA limitations on utility ownership discourage utility investment in cogeneration. Moreover,

most large utilities do not see dispersed generating facilities—including cogeneration—as having

the ability to replace future central generating stations, and the low-earned utility rates of return

in recent years may not be high enough to en-
Ch. 3—Context for Cogeneration ● 109

courage utility investment in technologies with

uncertain electricity output.

Full (100 percent) utility ownership may be

very advantageous if a utility faces revenue losses

due to industrial or commercial cogeneration (see

ch. 6). For instance, Arkansas Power & Light

(AP&L) estimates that if their 35 industrial customers who are prime cogeneration candidates had

cogenerated in 1981, AP&L’s estimated revenue

loss for that year would have been almost $40

million. However, if AP&L developed and owned

the cogeneration systems for those 35 industrial

customers, not only would they retain that industrial market for electricity, but they would have

an additional revenue stream from steam sales—

potentially $500 million in the mid-1980’s (44).

Moreover, if potential industrial or commercial

cogenerators are unable to burn coal (e.g., due

to space or environmental limitations), or are unwilling to assume the risk of advanced technologies (e.g., gasification), utility ownership with

electricity and steam distribution can centralize

the burden of using alternate fuels. However, the

full incremental ITC is not available for utilityowned cogenerators nor are PURPA benefits

available if an IOU owns more than 50 percent

of the cogeneration facility. (The potential advantages and disadvantages of full utility ownership

are discussed in detail in ch. 7.)

Alternatively, a utility may decide to participate

in a joint venture for a cogeneration facility (see

cases 4 and 5) in order to structure the ownership in such a way that the investment tax credit

and other tax benefits are diverted to the nonutility participants. in addition, financing can be

structured so that any debt related to the facility

(with the exception of relatively small amounts

for working capital) will not appear on the utility’s balance sheet. This structuring would be appropriate for utility-financed industrial cogeneration or biomass projects.

Tax= Exempt Entities

The key advantage enjoyed by municipalities

in issuing debt is the tax-free status of the interest

paid on their obligations, which results in a lower

interest rate than that paid on taxable securities.

The current spread in yields between new AAA

long-term IOU bonds and AAA municipal general

obligation bonds is around 375 basis points (100

basis points equals 1 percentage point); between

the same utility bonds and revenue bonds the

spread is around 330 basis points.

Section 103 of the Internal Revenue Code sets

out the provisions for a security to receive taxexempt interest treatment. Section 103(a) exempts the interest on an obligation of a State or

political subdivision (which would include general obligation bonds). Section 103(b), however,
110 . Industrial and Commercial Cogeneratlon

denies tax-free status for industrial development

bonds (IDBs) except for specific exemptions. In

order for IDBs to qualify for tax-exemption, more

than 25 percent of the proceeds of an obligation

must be used by a nonexempt person for business

purposes; a major portion of the principal or interest must be secured by business property; and,

in the case of a take-or-pay contract with an electric facility, the contract must be with a nonexempt person and in exchange for payments totaling more than 25 percent of the total output debt

service. Moreover, the facilities financed by taxexempt IDBs must be for general public use and

for specified activities including:

solid waste disposal facilities for the local furnishing of electric energy;

air or water pollution control facilities; and

acquisition or development of land for industrial parks, including development for

water, sewer, power, or transportation purposes.

Under the Windfall Profits Tax, solid waste-toenergy facilities are eligible for tax-exempt financing with IDBs if over half of the fuel is derived

from solid waste, and the facility is owned by a

governmental authority, although year-to-year

management contracts with business corporations are allowed.

Perhaps the most important exemption for taxfree financing is the small issue exemption, under

which up to $1 million in IDBs (or $10 million

provided total capital expenditures do not exceed

$10 million) can be issued for any trade or business for the acquisition of land or property subject to depreciation. However, if all of the proceeds of a bond issue are used to finance a project for which an Urban Development Action

Grant (UDAG) has been made, then the capital

expenditure can be $20 million, of which $10

million must come from sources other than taxexempt obligations. Renewable energy property is eligible for a special exemption if the bonds

used to finance it are general obligations.

Cogeneration is not eligible for special energy

tax incentives if over 25-percent fueled from oil

or gas. As the technology becomes available,

coal-fired cogeneration plants will qualify for

special tax incentives and be economically attractive. In the meantime, the best financing strategy

for municipalities to foster cogeneration development using available technologies may be to maximize the use of tax-exempt financing (see case 6).

Industrial parks also are an excellent application in which municipalities can foster the development of cogeneration. Tax-exempt IDBs can

be issued without limit under a specific exemption for the acquisition of land for industrial parks

and its upgrading including water, sewage, drainage, communication, and power facilities prior

to use. Cogeneration facilities (including steam

distribution lines) presumably would fall into this

specific exemption. The requirements encourage

joint ventures between the exempt entity and

businesses, but the funds must be used by the

nonexempt entity in a trade or business and

payments secured by an interest in property used

in a trade or business. Moreover, some State laws

prohibit municipalities from entering into corporate relationships with the private sector, but

independent public bonding authorities usually

can be established to get around such prohibitions.

Any number of lessor-lessee relationships also

are possible between a municipality and a corporation. An important aim of the financing structure would be to allow the corporation to pick

up the lo-percent investment tax credit (see case

7).
Ch. 3—Context for Cogeneration . 111

Finally, an innovative financing option for

municipal utilities and other local government

agencies that has attracted a lot of attention in

California is the municipal solar utility (MSU). As

originally conceived, an MSU would reduce the

capital and maintenance costs of solar hot water

systems (or other alternative energy or conservation measures) by: 1) only charging customers

for their installation; 2) spreading that charge over

the lifetime of the system in the monthly electric

bills; and 3) providing continued maintenance

(28). More recently, the MSU concept has been

expanded to include programs such as brokerage

of different financial and service packages,

dedicated deposits of city funds in local banks

for low interest alternative energy loans, or

technical assistance and other community outreach programs (60).

Rural Electric Cooperative Ownership

Rural electric cooperatives are finding it more

difficult to purchase additional electricity from

their traditional sources (IOUS and Federal power

authorities) and consequently are being forced

to build or participate in new generating capacity. Within this context, dispersed facilities (including cogeneration) may be advantageous due

to the shorter construction times, greater planning flexibility, and lower capital costs. In addition, alternate energy projects are more readily

financed at favorable terms. Such financing includes 35-year loans for feasibility studies under

the REA insured loan program, and is designed

to help overcome the lack of engineering expertise and other resource constraints faced by small

distribution co-ops that wish to add generating

capacity. As with other electric utilities, co-ops

will prefer projects that provide most of their additional capacity during peak demand periods

and whose electricity output is not intermittent

(e.g., biomass, hydroelectric, and industrial

cogeneration projects).

For a project with IOO-percent co-op ownership, all the benefits accrue to the cooperative’s

members (e.g., no taxes are paid and no profits

are distributed to investors). Capital is raised

through an REA guaranteed loan, which means

that the cost of capital will be lower than for a

private investor because the U.S. Government

has guaranteed the loan. Other financing options

for cooperatives include joint ventures with local

governments or with industrial concerns (see case

8).
112 ● Industrial and Commercial Cogeneration

1.

2.

3.

4.

5.

6.

7.

8.

9.

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Chapter 4

Characterization of the

Technologies for Cogeneration

Contents

Page

introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . 117

Cogeneration Technologies . . . . . . . . . . . . . . . 122

Steam Turbines. . . . . . . . . . . . . . . . . . . . . . . . 122

Open-Cycle Combustion Turbines . . . . . . . . 125

Closed-Cycle Combustion Turbines . . . . . . . 127

Combined Cycles . . . . . . . . . . . . . . . . . . . . . . 129

Diesels . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 131

Rankine Cycle Bottoming . . . . . . . . . . . . . . . 133

Fuel Cells . . . . . . . . . . . . . . . . . . . . . . . . . . . . 137

Stirling Engines . . . . . . . . . . . . . . . . . . . . . . . . 139

Use of Alternative Fuels in Cogeneration . . . . 142

Fluidized Bed Combustion Systems . . . . . . . 142

Gasification . . . . . . . . . . . . . . . . . . . . . . . . . . . 143

{interconnection . . . . . . . . . . . . . . . . . . . . . . . . . 146

Power Quality . . . . . . . . . . . . . . . . . . . . . . . . 146

Metering . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 151

Controlling Utility System Operations . . . . . 151

Safety . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 153

Liability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 154

Summary of Requirements

Quality of interconnection

Page

. . . . . . . . . . . . . . 154

Equipment . . . . . 154

Guidelines for interconnection ~ . . . . . . . . . . 155

Costs for interconnection . . . . . . . . . . . . . . . 157

Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 158

Thermal and Electric Storage . . . . . . . . . . . . . . 159

Thermal Storage.. . . . . . . . . . . . . . . . . . . . . . 159

Electric Storage.. . . . . . . . . . . . . . . . . . . . . . . 161

Cogeneration and District Heating. . . . . . . . . . 163

Chapter preferences . . . . . . . . . . . . . . . . . . . . 165

Tables

Table No. Page

21. Thermal Analysis of ldeal and Real

Heat Engines . . . . . . . . . . . . . . . . . . . . . . . . 118

22. Performance Characteristics of Alternative

Electricity-and Steam-Production

Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . 119
Table No. Page

23.

24.

25.

26.

27.

28.

29.

30.

Summary of Cogeneration Technologies. . 120

Diesel Engine Characteristics . . . . . . . . . . . 131

Estimates of Steam Bottoming Cycle

Operation and Maintenance Costs . . . . . . 136

Cogeneration interconnection Sample

costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 157

Interconnection Costs for Three Typical

Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . 158

Thermal Energy Storage Capacity

Range v. Plant Size. . . . . . . . . . . . . . . . . . . 160

Cost and Performance Characteristics of

Advanced Batteries . . . . . . . . . . . . . . . . . . . 162

Expected Technical and Cost

Characteristics of Selected Electrical

Energy Storage Systems . . . . . . . . . . . . . . . . 163

Figures

.

Figure No. Page

16. Comparison of Energy Utilization in a

Cogeneration System and a Conventional

Powerplant. . . . . . . . . . . . . . . . . . . . . . . . . . 119

17. Steam Turbine Topping System in a

Cogeneration Configuration . . . . . . . . . . . . 123

18. Estimated Steam Turbine Cogenerator

System Installed Costs With Different

Heat Sources . . . . . . . . . . . . . . . . . . . . . . . . 124

19. Combustion Turbine . . . . . . . . . . . . . . . . . . 125

20. Schematic of a Simple Open-Cycle

Combustion Turbine in a Cogeneration

Application . . . . . . . . . . . . . . . . . . . . . . . . . 126

21. Combustion Turbine Cogenerator Cost

Estimates for the Prime Mover and

Total Installed System . . . . . . . . . . . . . . . . . 127

22. Closed-Cycle Gas Turbines With and

Without Regeneration . . . . . . . . . . . . . . . . . 128

23. Closed-Cycle Gas Turbine Cogenerator

Installed Cost . . . . . . . . . . . . . . . . . . . . . . . . 129

24. Schematic of a Combined-Cycle

Cogenerator. . . . . . . . . . . . . . . . . . . . . . . . . 130

Figure No. Page

25. Total Installed Costs for CombinedCycIe Cogenerator Systems . . . . . . . . . . . . 131

26. Diesel Engine Cogenerator . . . . . . . . . . . . . 132

27. Diesel Cogenerator Total Installed

Costs for Current and Advanced

Prime Movers . . . . . . . . . . . . . . . . . . . . . . . 133

28. Steam Rankine Bottoming Cycle . . . . . . . . 133

29. Organic Rankine Bottoming Cycle. . . . . . . 134

30. Organic Rankine Bottoming Cycle

Efficiency-Variation With Peak Cycle

Temperature . . . . . . . . . . . . . . . . . . . . . . . . 135

31. Typical Energy Balances for Steam

Rankine Bottoming Systems . . . . . . . . . . . . 135

32. Estimated Installed Costs for

Condensing and Non-condensing Steam

Rankine Bottoming Systems . . . . . . . . . . . . 136

33. Estimated Installed Costs for Organic

Rankine Bottoming System. . . . . . . . . . . . . 136

34. Schematic Diagram of a Fuel Cell . . . . . . . 137

35. Schematic ofa Fuel Ceil Powerplant. . . . . 138

36. Representative Performance of Fuel

Cell Powerplants . . . . . . . . . . . . . . . . . . . . . 139

37. Future Estimates of Total Installed

Costs for Fuel Cell Powerplant Systems. . . 140

38. Schematic of a Stirling Cycle Engine . . . . . 140

39. Waste Heat Availability From Different

Engines . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 141

40. Future Installed Costs for Stirling

Engine Cogenerator Powerplants . . . . . . . . 141

41. Possible Power System Additional

Equipment Requirements to Serve

Qualifying Facilities . . . . . . . . . . . . . . . . . . . 155

42. Low-Temperature Thermal Storage

Cost per kWht v. Storage Capacity . . . . . . 160

43. High-Temperature Thermal Storage

Cost per kWht v. Storage Capacity.. . . . . . 161

44. European Cogeneration District

Heating System . . . . . . . . . . . . . . . . . . . . . . 164

Box

A. Thermodynamic Efficiency of

Cogeneration. . . . . . . . . . . . . . . . . . . . . . . . . 118
Chapter 4

Characterization of the Technologies for Cogeneration

INTRODUCTION

Cogeneration systems recapture otherwise

wasted thermal energy, usually from a heat engine producing electricity (such as a steam turbine, gas turbine, or diesel engine), and use it for

space conditioning, industrial processes, or as an

energy source for another system component

(31 ). This “cascading” of energy use is what distinguishes cogeneration systems from conventional separate electric and thermal energy systems (e.g., a powerplant and an industrial boiler),

or from simple heat recovery strategies. The automobile engine is a familiar cogeneration system

that provides mechanical shaft power to move

the car, produces electricity with the alternator

to run the electrical system, and recirculates the

engine’s otherwise wasted heat to provide comfort conditioning in the winter.

This chapter characterizes the technical features of cogeneration systems, including an overview of the general fuel use and energy production considerations common to all cogenerators,

a description of the operating characteristics and

costs of both commercially available and promising future cogeneration technologies, and a discussion of ancillary systems such as those for

interconnecting cogenerators with the utility grid,

for improving cogenerators’ fuel flexibility, and

for storing the electric or thermal energy. A more

detailed characterization of cogeneration technologies may be found in volume II of this report.

The principal technical advantage of cogeneration systems is their ability to improve the efficiency of fuel use in the production of electric

and thermal energy. Less fuel is required to produce a given amount of electric and thermal energy in a single cogeneration unit than is needed

to generate the same quantities of both types of

energy in separate, conventional technologies

(e.g., turbine-generator sets and steam boilers).

This is because waste heat from the turbine-generator set, which uses a substantial quantity of

the fuel used to fire the turbine, becomes useful

thermal energy in a cogeneration system (e.g.,

process steam) rather than being “wasted. ” To

be sure, this usually requires some reduction in

the amount of electricity produced compared to

a stand-alone turbine generator, but this “sacrifice” usually is acceptable to gain the 10- to

30-percent increase in overall fuel efficiency

offered by cogeneration (31 ). To see more clearly

how this gain is achieved, box A provides a detailed look at the thermodynamics of cogeneration.

The relative efficiency of cogenerators and conventional powerplants is shown in figure 16. In

a conventional steam plant (which generally uses

a Rankine cycle), energy must be added to the

feedwater in the boiler in sufficient amounts to

raise it up to point A in figure 16 (steam for power

generation). However, due to inherent inefficiencies in the Rankine cycle turbine, the condensing turbines that drive the generators can only

utilize the amount of energy between points A

and C in the figure (steam at the boiling point)

to generate electricity. Thus, the large amount

of energy from the boiler feedwater level to point

C is lost as the steam is condensed by cooling

water, carrying off the heat, and rejecting it to

the environment.

In the cogeneration plant in figure 16, the energy from A to B (steam) is used to generate electricity, the energy from B to D (water at boiling

point) is used as process steam, and only the energy from D down to the feedwater level is rejected to the environment. Thus, the cogenerator

allows use of some of the energy that the conventional powerplant otherwise would waste. Level

B is determined by the temperature required for

the process steam.

Different types of cogenerators have differing

fuel use characteristics and produce different proportions of electricity and steam. The electricityto-steam (E/S) ratio refers to the relative proportions of electric and thermal energy produced by 

a cogenerator. The E/S ratio is measured in kilowatthours 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 System

and 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 — —

Feedwater (energy added) — —

Electricity only

(conventional powerplant)

Electricity

(cogenerat

and steam

ion plant)

SOURCE: Dow Chemical Co., et al., Energy industrial Canter Study (Washington, D. C.: National Science Foundation, June 1975).
120 ● Industrial and Commercial Cogeneration

different types of cogeneration technologies (see

table 23).

The total heat rate refers to the total amount

of fuel (measured in Btu) required to produce 1

kwh of electricity, with no credit given for the

use of “waste heat.” The net heat rate (also

measured in Btu/kWh) credits the thermal output and denotes the fuel required to produce

electricity, beyond what would be needed to produce a given quantity of thermal energy in a separate facility (e.g., a boiler). In a central powerplant, where no heat is recovered, an average

total heat rate is 10,500 Btu/kWh (60). Cogenerators have a net heat rate of about 4,300 to 7,500

Btu/kWh depending on the characteristics of the

thermal energy produced. Thus, depending on

the cogenerator type and how completely the

thermal output is utilized, electricity can be produced by a cogenerator with about one-half to

three-fourths the fuel used in central power generation (45,60). Fuel use efficiency for a cogenerator gives credit to the thermal output; hence it

is the ratio of electric output plus heat recovered

in Btu to fuel input in Btu.

Table 21 presents a numerical example of heat

rates and fuel efficiency-based on modern steam

turbines—that compares: 1 ) an ideal engine exhausting to a low temperature, 2) a real engine

exhausting to a low temperature (typical of a utility powerplant), 3) a real engine exhausting at a

higher temperature with the heat wasted (something that is best to avoid), and 4) a real engine

exhausting at a higher temperature with the heat

utilized (as with a cogenerator). it is noted that,

in the example in table 21, the fuel use efficiency

varies from 35 percent for the utility powerplant

to 75 percent for the cogenerator.

Table 23.—Summary of Cogeneration Technologies

Part-load

Full-load (at 50°/0 load)

Average annual electric electrlc Total Net heat Electriclty-toFuels 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 4,500-6,000

topping

30-75

residual, coal, wood,

solid waste/coal- or biomass-derived gases and

Iiquida.

Natural gas, distillate,

treated resldual/coal- or

biomass-derived gases

and liquids.

Externally fired—can use

most fuels.

Natural gas, dlstlllate,

resldual/coal- or blomassdertved gases and liquids.

Natural gas, distillate,

treated residual/coal- or

biomass-derived gases

and liquids, slurry or

powdered coals.

B. Open-cycle gas 100 kW-100 MW

turbine topping

90-95 24-35 19-29 9,750-14,200 5,5004,500 140-225

G. Glosed-cycle gas 500 kW-100 MW

turbine topping

D. Comblned gas 4 MW-1OO MW

turbine/steam

turbine 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

6,300-10,300 350-700

F. Rankine cycle

bottoming:

Steam 500 kW-10 MW Waste heat. 90 10-20 Comparable

to full load

Comparable

to full load

3745

34-40

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 MW

H. Stirling engine 3-100 kW

topping (expect

1.5 MW by

1990)

Hydrogen, distlllate/coal.

Externally fired—can use

most fuels.

90-92

Not knownexpected to be

similar to gas turbines and diesels,

37-45

35-41

7,500-9,300

8,300-9,750

4,300-5,500

5,500-6,500

240-300

340-500
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 lifetime

Technology 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 25-35

topping

Mature technology —commercially available In large

quantities.

This Is the most commonly

used cogeneration technology. Generally used in

industry and utility applications. Best suited for

where electric/thermal

ratio is low,

Potential for use in residential, commercial, and

industrial sectors if fuel

is available and cost

effective.

Best suited to larger scale

utility and industrial applications. Potential for

coal use is excellent,

Most attractive where

power requirements are

high and process heat requirements are lower,

Used in large industrial

applications such as

Steel, chemical, and

petroleum refining

industries.

Reliable and available, can

be used in hospitals,

apartment complexes,

shopping centers, hotels,

Industrial centers if fuel is

available and cost effective, and if can meet environmental requirements.

B. Open-cycle gas

turbine topping

320-700 0.29-0.34 2.5-3.0 0.75-2 20 natural gas

15 distillate

Mature technology —commercially available in large

quantities.

C. Closed-cycle gas 450-900 5 percent of Included in 2-5

turbine topping acquisition fixed cost

cost per year

20 Not commercial in the

United States; is well developed in several European countries.

Commercially available;

advanced systems by

1965.

D. Combined gas 430-600 2-3

turbine/steam

turbine 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 —commercially available in large

quantities.

F. Rankine cycle

bottoming:

Steam 550-1,100 1,6 3.7-6.9 1-3 20 Commercially available Industrial and utility use

almost exclusively. Although efficiency is low,

since it runs on waste

heat no additional fuel

is consumed. Can reduce

overall fuel use.

Same benefits/limitations

as steam Rankine bottoming except that it can use

lower-grade waste heat.

Organic Rankine bottoming is one of the few

engines that can use

waste heat in the 2000

600”F range.

Modular nature, low emissions, excellent part-load

characteristics allow for

utility load following as

well as applications in

commercial and industrial

sectors.

High efficiency and fuel

flexibility contribute to a

large range of applications Could be used in

residential, commercial,

and industrial applications. Industrial use

depends on development

4.9-7.5 1-2 20 Some units are commercially

available but technology

is still in its infancy.

Organic 600-1,500 2.8

G. Fuel cell topping 520-840 C 0.26-33 1.0-3.0 1-2 10-15 Still in development and

experimental stage. phosphoric acid expected by

1965, molten carbonate by

1990.

H. Stirling engine 420-960 C

topping

5.0 8.0 2-5 20 Reasonably mature technology up to 100-kW capacity

but not readily available.

Larger sizes being

developed.

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.

SOURCE: Office of Technology Assessment from material in ch. 4.
122 • Industrial and Commercial Cogeneration

COGENERATION TECHNOLOGIES

Most cogeneration systems can be described

either as “topping” systems or “bottoming” systems, depending on whether the electrical or

thermal energy is produced first. * In a topping

system—the most common cogeneration mode—

electricity is produced first. The thermal energy

that is exhausted is captured and used for such

purposes as industrial processes, space heating

and cooling, water heating, or even producing

more electricity (18). Topping systems would be

used in residential/commercial and most industrial cogeneration applications.

In a bottoming system, high-temperature thermal energy is produced first for applications such

as steel reheat furnaces, glass kilns, or aluminumremelt furnaces. Heat is extracted from the hot

exhaust waste stream and transferred to a working fluid, generally through a waste heat recovery

boiler. The fluid is vaporized and used to drive

a turbine (Rankine cycle) to produce electrical

energy (18). Bottoming cycles are used mostly in

industries where high-temperature waste heat is

available, and thus are limited to a few industrial

processes. Further, they tend to have a higher

capital cost than topping systems.

The cogeneration systems described below are:

1) steam turbine topping, 2) open-cycle gas turbine topping, 3) closed-cycle gas turbine topping,

4) combined-cycle (gas/steam turbine) topping

systems, 5) diesel topping, 6) Rankine cycle

(steam and organic) bottoming, 7) fuel cell topping, and 8) Stirling engine topping. A fuel cell,

being a chemical device, is the only technology

that is not a heat engine although it is considered

a topping cycle cogeneration system.

These technologies include small systems (75

kW to 10 megawatts (MW)) that might be used

to supply electricity and heat for a single building

or a building complex such as a shopping center;

intermediate size cogenerators of several to tens

of megawatts for industrial applications; and large

*Operating and efficiency standards for topping and bottoming

cycle cogenerators promulgated by the Federal Energy Regulatory

Commission under the Public Utility Regulatory Policies Act are

discussed in ch. 3.

centralized systems that could supply electricity

to the utility grid and distribute steam to nearby

industries or to district heating systems. Potential cogeneration applications in industry, commercial buildings, and rural areas are discussed

in detail in chapter 5.

The steam turbine, open-cycle gas turbine,

combined-cycle, diesel, and steam Rankine bottoming cogenerators represent commercially

available technologies although advanced models

with improved efficiency, lower cost, and greater

fuel flexibility are under development. The

closed-cycle gas turbine is available in other

countries and could be introduced in the United

States at any time. Organic Rankine bottoming

cycles, fuel cells, and Stirling engines are not

commercially available in the United States, but

are sufficiently well developed to be considered

“near term” cogeneration technologies (available

within 5 to 15 years). As with all predictions of

commercial readiness for developing technologies, however, care must be exercised and actual progress observed closely–as noted from the

long and difficult history of Stirling engines.

The general operating and performance characteristics and costs of these cogeneration technologies are summarized below and in table 23.

Detailed technology descriptions may be found

in volume Il.

Steam Turbines

Historically, steam turbines have been the primary cogeneration technology, providing mechanical and electric power and steam for a variety of industrial processes. A schematic of a steam

turbine in a cogeneration application is shown

in figure 17. The system consists of a boiler and

a back pressure turbine. Mechanical energy is

produced as the high-pressure steam from the

boiler drives the turbine. The mechanical energy

is then converted to electricity by turning a generator rotor attached to the turbine. The steam,

which leaves the turbine at a reduced pressure

and temperature (300° to 700° F), can be used

in 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 of

steam turbines present both advantages and disadvantages relative to other types of cogenerators. Steam turbine engines are available in a wide

range of sizes, from 500 kW to well over 550

MW, although 100 MW is probably a reasonable

ceiling for most industrial applications. Currently,

steam turbine boilers can accommodate a wider

variety of fuels than other available cogeneration

systems (including oil, natural or synthesis gas,

coal, wood, solid waste, and industrial byproducts), although individual boilers can only be designed to accommodate two fuel sources at one

time (i.e., dual-fueled boilers can be built to use

oil or gas, coal or oil, gas or coal). Steam turbine

cogenerators also have extremely high unit reliability, availability, and service lifetime. With respect to reliability, steam turbines have a maximum forced outage rate of around 5 percent.

Their unit availability also is quite high (90 to 95

percent) because scheduled maintenance requirements are relatively low. The expected service lifetime of steam turbine cogenerators is from

25 to 35 years.

A final technical advantage of steam turbine cogenerators is their high overall fuel efficiency,

which ranges from 65 to 85 percent, and generally is not affected by turbine inlet temperatures

or by part-load operation (when less than the

maximum possible amount of electricity is being

produced). However, steam turbines’ efficiency

of electricity generation increases with increasing inlet temperature and pressure ratio, and with

size up to about 30 MW.

On the other hand, steam turbine cogenerators

have relatively long installation Ieadtimes–12 to

18 months for smaller systems and up to 3 years

for larger units—from the time equipment is ordered until operation begins. This is due primarily

to the time required to certify and install high-

-pressure boilers. For coal burning systems, the

installation of fuel handling equipment can add

significantly to the Ieadtime.
124 • Industrial and Commercial Cogeneration

Steam turbines also have relatively low ratios

of electric-to-thermal power production (E/S ratio)

because they have a relatively low upper temperature limit. It is this temperature which, in combination with the desired steam temperature, determines the amount of electricity that can be

generated. Of the 85 percent useful energy obtainable in steam turbine cogeneration systems,

typically 14 percent would be electric power and

71 percent process heat. However, the E/S ratio

will vary according to the amount of high-pressure steam that is directed from the boiler for

process heat. Thus, an increase in process steam

temperature corresponds to a decline in electric

power production and an increase in heat production. Overall fuel utilization (power plus heat)

remains relatively constant at a variety of process

temperatures. All that changes is the proportion

of total fuel use devoted to electric generation

and process heat. Research and development

(R&D) efforts are underway on advanced steam

turbine models that would operate at higher temperatures and pressures and thus would be more

efficient generators of electricity.

The costs of steam turbine cogenerators vary

depending on the size of the system, the kind of

fuel it uses, and its combustion source (e.g., boiler, fluidized bed combustor, gasifier). Figure 18

presents total installed costs for steam turbine

systems. Coal-fired steam turbines with flue gas

desulfurization (FGD) (for environmental control

purposes) range in cost from $800 to $1 ,600/kW

installed capacity. These systems constitute the

most expensive steam turbine option, with costs

generally $200/kW greater than turbines with fluidized bed boilers, which would not need FGD

in order to meet air quality standards. Oil-fired

boilers for steam turbines constitute the least expensive option, with installed cost estimates ranging from $550 to $800/kW—about $200 to $600/

kW below the expected costs for atmospheric

fluidized bed (AFB) boiler turbines. * Economies

of scale are evident for steam turbine cogenerators larger than about 10 MW.

*lt should be noted that estimates for steam turbine system costs

vary greatly according to the data source. The degree of accuracy

of the different estimates is difficult to verify without actual construction of the various systems.

Figure 18.—Estimated Steam Turbine Cogenerator

System 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 prime

movers also differs according to the size of the

unit. For smaller units (less than 5 MW), advanced

steam turbine installed costs may be $150 to

$200/kW greater than the cost of current steam

turbines. For 1O-MW units, the incremental cost

of advanced steam turbines is approximately $5o

to $100/kW greater, while for 100-MW units, the

prices are approximately the same as currently

available systems (55).

Estimates for variable operation and maintenance (O&M) costs for steam turbine topping

cycles (excluding fuel cost) vary from 3.0 to 8.8

milis/kWh depending on the source of the estimate. For a residual oil-fired steam turbine, in

general, a 4.0 mills/kWh O&M cost appears to

be a reasonable estimate. Estimates of O&M costs

for large steam turbines are 6.0 mills/kWh with

FGD, 4.2 mills/kWh without FGD, 5.2 mills/kWh

with 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 range

from $1.6 to $1 1.5/kWh of installed capacity.

Open= Cycle Combustion Turbines

Most combustion turbines are open-cycle systems in which air is drawn in from the atmosphere and exhaust gases are released to the atmosphere (i. e., the air or other working fluid is

not recirculated). Figure 19 provides system schematics for both simple and regenerative opencycle gas turbines. Figure 20 presents the configu ration a simple open-cycle combustion turbine

with a heat recovery unit would take in a cogeneration application. For both simple and regenerative turbine types, air is compressed, then

heated in the combustion chamber to the required turbine inlet temperature, and expanded

through the turbine. The primary difference between 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.: US

Department of Energy, DOEIPE 03871-01, November 1979).
126 . Industrial and Commercial Cogeneration

1,100

Figure 20.-Schematic of a Simple Open-Cycie Combustion Turbine in a Cogeneration Application

Process

100,000 lb steam/hour

700o

F, 600 psi

T = 770o

F

P

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 hot

exhaust gases are used to preheat the high-pressure compressor discharge air in a regenerator.

The waste heat boiler system recovers heat from

the hot gas produced by the turbine and generates high- and low-pressure thermal energy to be

utilized in industrial processes or for space conditioning.

Simple open-cycle combustion turbine systems

with waste heat boilers currently are available in

size ranges from 100 kw to 100 MW. Regenerative turbines are available in sizes from about 16

MW to 70 MW. Most combustion turbines burn

natural gas or diesel oil, and can be converted

from one to the other in about 1 day. Because

turbine blades in open-cycle systems are exposed

to the products of combustion, these products

must be free of impurities (e.g., sodium, potassium, calcium, vanadium, iron, sulfur, and particuIates) that can cause corrosion, and the residual

solids must be small enough to avoid erosion of

the turbine blades. As a result, currently available

open-cycle combustion turbines cannot use solid

fuels (coal, biomass) directly (i.e., without first

liquefying or gasifying them), and cannot burn

residual oil or liquid or gaseous fuels from coal

or biomass without an auxiliary fuel cleaning

system (see discussion of fuel flexibility in the next

section).

Open-cycle combustion turbine cogenerators

have a shorter installation Ieadtime than steam

turbines—around 9 to 14 months for gas turbines

up to 7 MW, and as long as 2 years for larger

units. The reliability of combustion turbines and

their average annual availability should be comparable to that of steam turbines, although units

that burn liquid fuels or that are operated only

intermittently will require about three times more

maintenance—and thus will have a lower percent

availability—than those that use natural gas. On

the other hand, the expected useful service life

of open-cycle combustion turbines tends to be

lower than that of steam turbines–typically 15

to 20 years—and poor maintenance, the use of

liquid fuels, or intermittent operation can reduce

the service life substantially.

Open-cycle combustion turbine cogenerators

tend to have slightly lower overall fuel efficiency

than steam turbines, but the most efficient combustion turbines can have a higher overall efficiency than the least efficient steam turbines. on

the other hand, open-cycle combustion turbines

have much higher E/S ratios than steam turbines

(typically 140 to 225 kWh/MMBtu for combustion turbines, as compared to 30 to 75 kWh/.

MMBtu for steam turbines), and a higher electric generating efficiency at both full- and partIoad operation (see table 23). Unlike steam tur-
Ch. 4—Characterization of the Technologies for Cogeneration . 127

Figure 21.—Combustion Turbine Cogenerator Cost

Estimates for the Prime Mover and

Total Installed System

800

700

500

300

200

100

0

0 10 20 30 40 50 60 70 80 90 100

Electric power output (MW)

SOURCE: Office of Technology Assessment.

low and tend to be about $0.29/kW for simple

cycles 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 heated

to the required inlet temperature by a heat exchanger. This arrangement ensures that both the

working fluid and the turbine machinery are isolated from both the combustion chamber (heat

source) and the products of combustion, and thus

erosion and corrosion problems in the turbine

are avoided. This external combustion design
128 . Industrial and Commercial Cogeneration

thus permits greater fuel flexibility than is possible in currently available open-cycle turbines.

Closed-cycle systems can burn coal, industrial or

municipal wastes, biomass, or liquid or gaseous

fuels derived from them. Nuclear or solar energy

may be used for these systems in the future. Figure 22 presents schematics of closed-cycle combustion turbine systems with and without regenerators. In the regenerative closed cycle, heat

from the working fluid that is leaving the turbine

is used to preheat the working fluid that is leaving the compressor. Closed-cycle combustion turbine cogenerators have not been commercially

available in the United States in the past, but have

been successful in Europe and Japan and could

be introduced here at any time.

The actual configuration of closed-cycle combustion turbine systems will vary according to the

heat source. Likely heat sources for these systems

include coal-fired AFB combustors and liquidfueled high-temperature furnaces. The installation Ieadtime for a 25-MW system with an AFB

is estimated to be 4.5 to 5 years, with an expected

service life of about 20 years.

In closed-cycle systems, any gas can serve as

the working fluid. Air has the advantage of reducing sealing requirements and mechanical complications. Heavy molecular weight gases (such as

argon) reduce the size of the turbomachinery but

increase that of the heat transfer components,

while light molecular weight gases (such as helium) require more extensive turbomachinery and

minimize the size of heat transfer equipment. This

flexibility’ contrasts sharply with open-cycle combustion turbine systems, which are limited to the

hot combustion gases as the working fluid.

Closed-cycle combustion turbines are thus

physically smaller than open cycles, but require

more piping and heat exchangers. In addition,

the small physical size of the turbomachinery Iimits the power of closed-cycle turbines. Consequently, systems with capacities below 500 kW

are not considered economically attractive. Electric capacity in currently operating closed-cycle

gas turbine systems (in Europe and japan) ranges

from 2 to 50 MW.

The average annual reliability and availability

of closed-cycle combustion turbines is expected

to be at least as good as that for open cycles once

sufficient operating experience has been accumulated with the former. However, because the

closed-cycle configuration reduces wear and tear

on the turbine blades, closed-cycle systems may

require less maintenance (and thus have a higher

availability) than open cycles.

The overall fuel efficiency of closed-cycle combustion turbine cogenerators also is expected to

be 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 Administration, 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 regenerator with a closed cycle will increase electricity output but reduce the temperature of the recovered heat. Unlike open-cycle systems, however, part-load operation of a closed-cycle gas turbine cogenerator does not reduce electric generating efficiency, and may actually increase it

when a regenerator is used. In this case a closedcycle system is much like a steam turbine in that

the working fluid and the combustion gases are

separate. This allows more control, which in turn

makes possible more constant part-load operation. The effect of part-load operation on overall

fuel efficiency will depend on the part-load efficiency of the heat source (e.g., fluidized bed, hot

gas furnace). Finally, overall efficiency will tend

to increase slightly with system size up to about

25 MVV.

Detailed installed cost information for closedcycle combustion turbine cogenerators is limited

due to the lack of experience with these systems

in the United States. Figure 23 presents estimates

for various size systems showing a range for total

installed costs (exclusive of heat source) from

$450 to $900/kW. Economies of scale are significant for larger systems (approximately 25 MW

Figure 23.—Closed-Cycle Gas Turbine Cogenerator

Installed 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 incremental cost of fuel handling equipment with increasing capacity.

The lack of U.S. operating experience with

closed-cycle combustion turbine cogenerators

precludes any definitive estimate of O&M costs.

A representative estimate for fixed plus variable

O&M costs in the literature surveyed is 5 percent

of installed cost per year of operation.

Combined Cycles

The term “combined cycle” is applied to systems with two interconnected cycles operating

at different temperatures. The higher temperature

(topping) cycle rejects heat that is recovered and

used in the lower temperature (bottoming) cycle to produce additional power and improve

overall conversion efficiency. Currently available

combined-cycle cogenerators use a combustion

turbine topping cycle in combination with a

steam-bottoming cycle.

A schematic of such a combined-cycle plant

is shown in figure 24. The major components of

the system are the combustion turbine generator,

the heat recovery boiler, and the steam turbine.

Note that this system is like the combustion turbine cogeneration systems discussed previously

except that steam from the heat recovery boiler

is used first to generate electricity and then exhausted for process heat and ultimately waste

heat. In most combined-cycle systems, extra fuel

is burned in the heat recovery boiler to supplement the heat in the combustion turbine exhaust,

The high percentage of oxygen (17 percent) in

the combustion turbine’s exhaust guarantees efficient supplemental combustion under the heat

recovery boiler. Supplemental firing generally improves thermal efficiency at part-load operation,

but makes combined-cycle plant operation control more complex and thus increases maintenance costs.

Combined-cycle cogenerators typically are

available in sizes ranging from 22 to about 400

MW. However, smaller units have been installed,

and at least one company currently is developing small, prepackaged combined-cycle units in

the 4-to 11 -MW size range (50). Installation time

from the date the equipment is ordered ranges
130 ● Industrial and Commercial Cogeneration

Figure 24.—Schematic of a Combined-Cycle Cogenerator

SOURCE: United Technologies Corp., Cogeneratlon Technology Alternat/ve Study (CTAS)– Volume I-VI (Cleveland, Ohio: National Aeronautics and Space Administration, Lewis Research Center, and Washington, D. C.: US. Department of

Energy, DOE/NASA/0030-’60H -6, January 1980).

from 2 to 3 years. It is generally possible to have

a two-stage installation in which the combustion

turbine system can be operable within 12 to 18

months. The steam turbine can then be installed

while the combustion turbines are in operation.

Combined-cycle systems require less floor

space than separate combustion or steam turbines producing comparable amounts of electric

power. Advanced combined-cycle systems

(which will consist of advanced combustion turbines and current technology steam turbines) will

be even smaller. Reduced space requirements

should increase the potential cogeneration applications for combined-cycle systems.

Fuels employed by available combined-cycle

cogenerators are the same as those used by commercial combustion turbines—natural gas, light

distillate oil, and other fuels that are free from

contaminants. Heavy fuels, such as residual oil,

heavy distillates, and coal-derived fuels that are

contaminated with trace metals can be used but

must be cleaned first. Advanced combined-cycle

systems will be able to incorporate fluidized bed

combustors that can burn coal (or almost any

other fuel). Systems utilizing indirect firing and

heat exchangers (i.e., closed cycles) also will be

able to run on a wider variety of fuels, because

the combustion turbine blades will be isolated

from the corrosive influence of fuel combustion.

The maintenance requirements for a combined-cycle system are similar to those for the

separate turbines, and average annual availability

is lower than for either technology alone (77 to

85 percent). Reliability is around 80 to 85 percent. Economic service life is between 15 and 25

years. However, as with open-cycle combustion

turbines, poor maintenance, lower quality fuels,

and intermittent operation will decrease the availability, reliability, and service life.

The electric generating efficiency of combinedcycle cogenerators is greater than for simple combustion turbine systems because of the additional

electricity generated by the steam turbine. Current combined-cycle systems achieve electric

generating efficiencies of between 34 and 40 percent, with 37 percent being typical. This increased efficiency, however, is achieved at the

expense of total fuel use (additional fuel is used

for supplemental heating of the heat recovery

boiler). While available combustion turbines

equipped with waste heat boilers typically have

a fuel use efficiency of approximately 80 percent,

overall fuel efficiency for combined-cycle systems

usually is below 60 percent. The electric conver-
.

Ch. 4—Characterization of the Technologies for Cogeneration . 131

sion efficiency of combined cycles increases with

capacity up to around 80 MW and remains constant above that size.

As with open-cycle combustion turbines, partIoad operation reduces the efficiency of combined cycles. As the gas turbine’s generating efficiency drops, more waste heat is supplied to the

steam turbine and its percentage of electric load

increases. However, the overall efficiency declines because of the increasing amount of waste

heat from part-load operation that cannot be recovered.

Typical E/S ratios for combined cycles are 175

to 320 kWh/MMBtu—significantly higher than

those for steam turbine topping cycles, and comparable to or slightly higher than open-cycle combustion turbines. However, as mentioned above,

as E/S ratio in a combined-cycle system increases

the overall fuel efficiency decreases.

Figure 25 presents estimates of total system installed costs for combined cycles. These costs

range from approximately $800/kW for a 4-MW

unit down to approximately $430/kW for 100-

MW units, Combustion turbines represent a larger percentage of the prime mover installed costs

than do the steam turbines in these systems.

Figure 25.—Total Installed Costs for CombinedCycle 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 system are directly related to the type of fuel used.

The lowest maintenance costs are associated with

natural gas use, while using residual oil in the

combustion turbine will result in the highest

maintenance costs, primarily because of the necessity to clean the fuel. Variable O&M cost estimates for combined-cycle systems range from 3.0

to 5.1 mills/kWh while annual fixed O&M costs

are from $5.0 to $5.5/kW installed capacity.

Diesels

The diesel engine is a reciprocating internal

combustion engine and is a fully developed and

mature technology. Cogeneration systems using

diesel engines are topping systems and are classified according to whether the diesel engine operates at high, medium, or low speed. Table 24

summarizes the engine speeds for each type of

diesel, its capacity range, and its usual applications. All three types have been used in electric

power generation—medium- and low-speed diesels by electric utilities for intermediate and peakIoad use, and high-speed diesels in the “total

energy systems” of the past.

A typical diesel engine topping cogenerator is

shown in figure 26. The major system components include an engine, generator, heat recovery

unit, fuel handling equipment, and environmental controls. The engine is cooled with water and

the heated water used for process steam, heat,

or hot water applications. Exhaust gases can be

used 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

Capacity

Type RPM (MW) Uses

High speed . . . . 1,200-3,600 0.075-1.5 Smaller vehicles

Medium speed. . 500-1,200 0.5-10 Marine, rail

Low speed . . . . . 120-160 2-30 Marine propulsion and industrial 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; “Electric

Power Generation,” McGraw-H/l/ Yearbook of Science and

Techno/ogy(New York: McGraw-Hill Book Co., 1980); Joel Fagenbaum,

“Cogeneration: An Energy Saver,” IEEE Spectrum, August 1980, pp

30-34; and Alan J. Streb, “Cogeneration-What’s Ahead?” Energy

Eng/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, September

1978).

capability. Two-stroke low-speed diesels also can

burn untreated low grade residual oil (58). Research is underway on the use of coal-based fuels

in large (low-speed) diesels, including processed

solid or liquid coal-derived fuels, or direct coal

firing with either a coal/oil or coal/water slurry

medium or a dry powdered coal. Slurry-fired diesels may become operational in 5 to 6 years and

commercially available in 8 to 10 years. However,

additional equipment may be required to control the increased particulate and sulfur dioxide

emissions resulting from burning coal or coalderived fuels. Whether coal burning diesels will

be economically competitive is yet unknown.

R&D on diesels also is directed toward increasing the temperature of the cooling water so that

steam can be generated, and toward higher supercharge capability and higher charge air cooling. Such advances could result in a 50-percent

increase in power output per cylinder (23). Advanced diesels will be ready for wide-scale cogeneration application between 1985 or 1990. “Adiabatic” (or very low heat loss) diesels, which use

ceramic parts, also are under development. The

principal advantage of the adiabatic diesel would

be that all the waste heat would be in the exhaust

stream and would be available at high temperature (as with combustion turbines). This technology could significantly improve the versatility of

the diesel as well as lead to greater overall fuel

use efficiency (61 ), but is not expected to be commercially available until after 1990.

Installation Ieadtimes for presently available

diesel cogenerators range from 9 months for

smaller high-speed systems to 2.5 years for larger

low-speed units. Maintenance is performed on

typical low- and medium-speed diesels every

1,500 hours, and more frequently on high-speed

diesels. Average annual availability ranges from

80 to 90 percent. Expected service lifetimes vary

from 15 to 25 years depending on unit size, fuel

burned, and quality of maintenance.

E/S ratios for diesels are high–from 350 to 700

kWh/MMBtu. Low-speed diesels typically are designed for peak efficiency at 75 percent of full

load. Part-load performance for current and advanced technology high-speed diesels is excellent. Medium-speed diesels, whose rated capacities overlap high-speed diesels at the small scale

and low-speed diesels at the large scale (see table

24) follow the same trends.

Total installed costs for current and advanced

diesel prime movers are given in figure 27. Costs

range from $350 to $800/kW for current units,

with large advanced systems being slightly higher

and smaller ones significantly higher.

Estimates for O&M costs for current and advanced diesels vary significantly depending on
Ch. 4—Characterization of the Technologies for Cogeneration ● 133

Figure 27.— Diesel Cogenerator Total Installed Costs

for Current and ‘Advanced Prime Movers

800

700

600

400

\\ Advance d

.

0 3 6 9 12 15 18 21 24 27 30

Electric power outlet (MW)

SOURCE: Office of Technology Assessment.

the fuel, the unit’s size, and the level of emission

control. Fixed O&M costs vary from $6.0 to $8.0/

kW annually. Estimates for variable O&M costs

range from 1.5 miIls/kWh for large low-speed

units to 16 mills/kWh for small high-speed units,

with 5.0 to 10.0 mills/kWh being a common

range.

Rankine Cycle Bottoming

All bottoming cogeneration systems are based

on the conventional Rankine cycle (which is the

same cycle used in steam turbine topping systems), and are classified according to whether

they use steam or organic working fluids. The

steam cycle (see fig. 28) uses steam produced in

a heat recovery boiler to drive a steam turbine

that generates electricity and high- and low-temperature waste heat. This, of course, is just the

low-temperature end of the combined-cycle systems discussed before. The high-temperature heat

is condensed and either used in process applications or fed back into the boiler through a closed

loop. Low-temperature waste heat is lost to the

surrounding environment. An organic Rankine

cycle (see fig. 29) converts heat energy into

mechanical energy by alternately evaporating an

organic working fluid (such as toluene) at high

pressure and using this vapor to produce shaft

power by expanding it through a turbine. The vapor is then recondensed for either process use

or reinfection into the heat recovery boiler.

Organic working fluids are used when only lower

temperature heat sources (200° to 600° F) are

available because these fluids vaporize at very

low temperatures.

Figure 28.—Steam Rankine Bottoming Cycle

SOURCE: Thermo Electron Corp., Venture Analysis Case Study—Steam Rankine Recovery Cycle Producing Electric Power

From Waste Heat (Waltham, Mass.: Thermo Electron Crop,, TE4231-1 17-78, December 1978).
134 ● Industrial and Commercial Cogeneration

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, September

1978).

Rankine cycle engines have several characteristics that make them particularly appealing to dispersed electricity generating systems. They are

one of the few engines that can effectively utilize

heat at temperatures in the 200° to 600° F range.

This allows the engines to use a variety of heat

sources including solar energy, industrial waste

heat streams, geothermal energy, and hot engine

exhausts. Rankine engines also can be designed

for use over a wide range of capacity levels, from

as low as 2 kW for onsite solar applications up

to 10 MW for waste heat applications.

The installation time required for organic and

steam bottoming cycles generally depends on the

size of the plant. For steam Rankine engines, installation times will be similar to those for comparably sized steam turbine topping cycles. Very

small organic Rankine units (less than 50 kW),

particularly those in commercial applications, will

require minimal installation time (4 to 8 months)

(2), while larger units are expected to take 1 to

2 years.

Maintenance requirements and reliability for

the steam Rankine bottoming cycle also should

be comparable to those of steam turbine topping

systems (i.e., average annual availability of about

90 percent). Organic Rankine bottoming cycles

are a relatively new technology, and information

on maintenance schedules and system reliability

is not readily available for these systems, but developers of this technology expect availability to

be from 80 to 90 percent. Expected service lifetime for both types of bottoming cycles is around

20 years.

Figure 30 shows organic Rankine cycle efficiency as a function of boiler outlet temperature. Note

that operation for inlet temperatures below 150°

F (about 75o C) is possible. Depending on these

parameters, cycle efficiency will range from 5 to

30 percent, with 10 to 20 percent being representative of actual operating conditions. However, because these organic Rankine cycle systems are bottoming systems that operate on the

waste heat these efficiencies are not significant
Ch. 4—Characterization of the Technologies for Cogeneration ● 135

Figure 30.—Organic Rankine Bottoming Cycle Efficiency—Variation

With Peak Cycle Temperature

0.4

0.3

0.2

0.1

0

100 200 300 400 500 600 700 600

Boiler outlet temperature (“F)

SOURCE: Resource Planning Associates, Cogeneratlorr: Tecfrn/ca/ Concepts, Trends, Prospects (Washington, D. C.: U.S. Department of Energy, DOEIFFU-1703, September 1978).

as far as total fuel use is concerned, because the

addition of an organic Rankine bottoming cycle

will increase the power output of the system without any increase in fuel consumption.

Figure 31 .—Typical Energy Balances

An analogous situation holds true for steam

Rankine bottoming cycles. Figure 31 indicates

typical energy balances for both condensing and

noncondensing steam Rankine systems. Although

for Steam Rankine Bottoming Systems

E/S Ratio: 25.1 kWh/10 Btu

SOURCE: Thermo Electron Corp., Venture Analysis Case Study—Steam Rankhre Recovery Cycle ProduchrgElectrlc Power

From Waste Heat (Waltham, Maas.: Thermo Electron Corp., TE4231-117-78, December 1978).
figure 31 shows an electric generating efficiency

of only 6 percent for the condensing configuration and 14. s percent for the noncondensing, it

must be remembered that additional electricity

is being generated from heat that normally would

have been wasted. Therefore, both configurations

will result in substantial fuel savings. Because the

noncondensing system produces steam as well

as electricity, and hence has a higher overall fuel

utilization efficiency, it saves about 150 percent

more fuel than the condensing system. The noncondensing system would be used, therefore,

when heat requirements and fuel saving considerations override the need for increased electricity production.

Figures 32 and 33 present estimated installed

costs for condensing and noncondensing steam

Rankine bottoming systems and for organic systems. The costs of the steam systems are roughly

comparable to steam topping cycle cogenerators

because most of the components are the same

for both types of systems. Installed costs for

organic Rankine cycles are more uncertain beFigure 32.—Estimated installed Costs for

Condensing and Noncondensing Steam

Rankine Bottoming Systems

01234567 8 9 10

Electric power output (MW)

SOURCE: Office of Technology Assessment.

Figure 33.—Estimated Installed Costs for Oraganic

Rankine 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 2.0

Electric power output (MW)

SOURCE: Office of Technology Assessment.

cause mass production of the units has not yet

begun. However, available estimates suggest that

the organic Rankine cycles will have a higher installed cost than steam cycles, primarily due to

the special materials (e.g., stainless steel) needed

to prevent corrosion of system components and

the precautions that must be taken against leaks

of the organic working fluid.

Estimates of variable O&M costs for condensing and noncondensing steam bottoming systems

up to 3 MW are presented in table 25. For larger

units, variable O&M costs are estimated to be beTable 25.-Estimates of Steam Bottoming Cycle

Operation and Maintenance Costs

Condensing Noncondensing

MW Mills/kWh MW Mills/kWh

0.5 6.86 0.5 6.17

1.0 4.57 1.0 5.03

1.5 4.17 1.5 4.17

2.0 3.87 2.0 3.71

3.0 3.71 3.0 3.71

SOURCE: Therrno Electron Corp., Venture Analysis Case Study-Stearrr Rankine

Recovery Cycle Producing E/ectr/c Power From Waate Heat (Waltham,

Mass.: Thermo Electron Corp., TE4231-117-78, December 1978).
Ch. 4—Characterization of the Technologies for Cogeneration ● 137

tween 3 and 5 percent of the installed cost. Annual fixed O&M costs are approximately $1 .60/

kw of installed capacity.

Fuel Cells

A fuel cell is an electrochemical device that

converts the chemical energy of a fuel into electricity with no intermediate combustion cycle (see

fig. 34). Hydrogen and oxygen react to produce

water in the presence of an electrolyte and, in

doing so, generate an electrochemical potential

that drives a current through an external circuit.

In addition, the reaction produces waste heat.

The hydrogen required for the ceil is obtained

from fossil fuels, usually methane, CH4. Because

methane occurs naturally only in natural gas, fuel

conversion is necessary if coal or biomass are the

ultimate sources of the hydrogen. Fuel cells may

be attractive for industrial and commercial cogeneration or for utility peaking applications because

of their modular construction, good electric load

following capabilities without a loss in efficiency,

automatic startup and shutdown, low pollutant

emissions, and quiet operation. An individual fuel

cell has an electric potential of slightly less than

1 volt (determined by the electrochemical potential of the hydrogen and oxygen reaction), but

single cells can be assembled in series to generate

practically any desired voltage, and these assemblies, in turn, can be connected in parallel to provide a variety of power levels (e.g., 40 kW to 25

MW). A fuel cell powerplant (see fig. 35) includes

the cell stack, an inverter (to convert direct current to alternating current), and a fuel processor

(to remove impurities from the hydrocarbon fuel

and convert it to pure hydrogen). The recovered

thermal energy in a fuel cell cogenerator can be

either all hot water, or part steam and part hot

water depending on the pressure.

The only fuel cell technology currently operating commercially is based on a phosphoric acid

electrolyte operating at 350° F. In general, acid

systems are favored because they do not react

with carbon dioxide and may thus use air as the

source of oxygen. Phosphoric acid cells are preferred because water removal is relatively easy

to control in these systems. However, phosphoric

acid fuel cells depend on platinum catalysts. The

present demonstration fuel cell powerplants require a platinum catalyst loading of approximately

6.2 grams per kilowatt of electric power output

(27), which, at today’s prices, adds $65 to $75/kW

to the cost of the fuel cell. A production level of

750 to 1,000 MW of phosphoric acid fuel cells

per year (the level one developer suggests will

be achieved in the next 10 to 15 years) would
138 . Industrial and Commercial Cogeneration

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. Department

of Energy, DOE/NASA/OO~OH-6, January 1980).

correspond to approximately 4.7 to 9.3 tonnes

of platinum annually, or around 35 to 70 percent

of domestic platinum production (including recycling) in 1979, and 3.5 to 7.5 percent of total U.S.

consumption in 1979 (9). Because of the small

amount of domestic platinum reserves, and limited U.S. refinery and recycling capacity, it is likely that a significant increase in platinum demand

for fuel cells would be supplied from foreign

sources—primarily South Africa and the U.S.S.R.

—and could lead to increases in the price of platinum. R&D efforts are underway to reduce the

platinum loading needed for fuel cells (developers

estimate future requirements to be about 1.9

grams per kilowatt), to synthesize catalysts that

do not depend on platinum, and to develop advanced cells based on molten salt electrolytes (9).

A second limitation of phosphoric acid fuel cells

is that hydrogen is the only fuel that can be oxidized at acceptable power levels in the cell, and

a clean fuel (e.g., methane or naphtha—a light

petroleum distillate) is required to generate the

hydrogen. Advanced phosphoric acid cells may

be able to use desulfurized No. 2 fuel oil as the

source of hydrogen. Second generation molten

carbonate electrolyte fuel cells, using advanced

fuel conversion technology, would make less

stringent demands for a clean fuel, and possibly

could be integrated with coal gasifiers.

Developers of fuel cells estimate an installation

Ieadtime of 1 to 2 years for cogenerators based

on either the phosphoric acid or molten carbonate cells (assuming mass production). useful service lives are projected to be 10 to 15 years. Maintenance requirements are uncertain due to the

limited experience with demonstration plants, but

average annual availability is expected to be

around 90 percent.

The overall chemical reaction in a fuel cell defines the maximum electric energy that it can produce. Because no thermomechanical work is involved, the energy conversion efficiency is not

limited by the Carnot cycle. However, voltage

losses are associated with internal resistance,

mass transport limitations, and the kinetics of the

electrode reactions. Electric generating efficiency

ranges from 30 to 40 percent, depending on operating temperature and fuel quality (see fig. 36).

At half-load operation, electric generating efficiency equals or even exceeds the efficiency at

full load. Thus, fuel cells could be installed for

load following duty without a loss in efficiency

in order to enable other types of generators to

operate at their most efficient rates. E/S ratios for

fuel cells are relatively high–from 240 to 300

kWh/MMBtu.

The installed costs for fuel cell powerplants are

currently too high to compete with other elec-
Ch. 4—Characterization of the Technologies for Cogeneration ● 139

Figure 36.-Representative Performance of Fuel Cell Powerplants

Low- High- Hightemperature temperature temperature

coal-derived coal-derived coal

distillate distillate

SOURCE: 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-MW

demonstration plant, being built in New York

City, will cost $60 million, or an equivalent of

$12,500/kW).” Fuel cell developers project that

total installed costs should range from $520 to

$840/kW of electrical capacity once the technology is being produced on a large scale (see fig.

37). It is likely that between 500 and 1,500 MW

of 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. As

shown in figure 37, the cost of a fuel cell prime

mover is not affected significantly by the capacity rating. However, substantial economies of

scale are observed with the balance-of-plant costs

per kilowatt, including fuel handling costs and

electric and control system costs.

Estimates of variable O&M costs for both types

of fuel cells fall within the range of 1.0 to 3.0

mills/kWh. Fixed annual O&M expenses may

range from $0.26 to $3.3/kW installed capacity,

Stirling Engines

Stirling engines are a potentially advantageous

alternative to diesel, combustion turbine, and

steam turbine cogenerators due to their potentially higher thermal efficiency, greater fuel flexibility, good part-load characteristics, low emissions, and low noise and vibrations. Figure 38

shows a schematic of a Stirling cycle engine. Gas

(e.g., hydrogen, helium) entrapped by a piston

alternately is compressed and expanded to turn

a crankshaft. Because the pressure during the hot

expansion step is significantly greater than during the cool compression step, there is a net work

output from the engine.

Historically, Stirling engines have been investigated for their potential use in automobiles, so

developmental work has been directed toward

smaller engines, which currently are available in

a size range of 3 to 100 kw. A 350-kW Stirling

engine is under design, and developers expect
140 . Industrial and Commercial Cogeneration

Figure 37.– Future Estimates of Total Installed

Costs for Fuel Cell Powerplant Systems

900 f

750

600

300

150

I

“ o 5 10 15 20

Electric power output (MW)

SOURCE: Office of Technology Assessment.

capacities up to 1 to 1.5 MW, with service

times of 20 years to be available by 1990.

25

lifeAlthough installation Ieadtimes are hard to predict

at present, they could range from 2 to 5 years

if and when Stirling cycle cogeneration systems

become commercial.

Because Stirling engines are still in the development stage, information about their maintenance

and reliability is not readily available, but developers project maintenance requirements (and

thus average annual availability) to be comparable to diesels and combustion turbines. Due to

the external combustion, closed-cycle configuration of Stirling engines, its moving parts are not

exposed to the products of combustion, and the

wear and tear on the engine should be minimal.

However, Stirling engines do require a complex

system of piston rod seals and surface barriers to

contain the high-pressure hydrogen and prevent

oil from leaking into the working gas space. The

durability of the piston seals, which are exposed

to a pressure differential of several thousand

pounds per square inch, is a recognized reliability

Figure 38.-Schematic of a Stirling

Cycle Engine

or

SOURCE: Application of Solar Technology to Today’s Energy Needs,

Volurnes / and// (Washington, D. C.: U.S. Congress, Office of

Technology Assessment, 1978).

issue, and the seal systems must be improved

before Stirling engines can be used widely.

A major advantage of the Stirling engine is that

its external combustion system enables it to use

a wide variety of fuels, including coal, coalderived gases and liquids, municipal solid wastes,

and possibly biomass-derived fuels such as wood

chips and biogas. In addition, Stirling engines can

change fuels without adjustment to the engine,

interruption of its operation, or loss of either power or efficiency. This flexibility will allow Stirling

engines to be used as components of solar energy

systems, as adjuncts to fluidized bed combustors

and nuclear reactor systems, etc.

A second advantage of Stirling engines, relative

to available cogenerators, is their greater efficiency. The Stirling cycle is much closer to the Carnot cycle than are the Rankine or combustion turbine cycles, and Stirling engines have one of the

lowest percentages of waste heat, and thus one

of the highest overall fuel use fractions of any heat

engine. Figure 39 shows how waste heat available

from Stirling engines compares with waste heat

from other engine types. The overall efficiency

of Stirling engines is relatively independent of

system size; electric generating efficiency and
Ch. 4—Characterization of the Technologies for Cogeneration ● 141

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 changes

is the composition of the waste heat (hot water

and steam percentages) (55). Present full-load

electric generating efficiency is similar to that of

diesel cogenerators (35 to 40 percent). However,

as development efforts increase the heat input

temperature of Stirling cycles (e.g., through improved metals or ceramic coatings in the heater

heads), efficiencies approaching so percent may

be obtained over a wide output range (a few kilowatts to several megawatts). Part-load performance of current Stirling engines is equivalent to

full-load efficiency, and thus is superior to that

of available prime movers. E/S ratios also are very

high–from 340 to 500 kWh/MMBtu.

It is difficult to give precise cost estimates for

Stirling engines because they are not yet available

commercially. Current installed cost estimates for

large industrial Stirling engines are approximately

20 percent higher in cost than comparably sized

diesel engines (from $420 to $960/kW; see fig.

40). As with fuel cells, successful development

work and mass production would be required to

Figure 40.-Future Installed Costs for Stirling

Engine Cogenerator Powerplants

(extrapolated to 30-MW scale)

“O 3 6 9 12 15 18 21 24 27 30

Electric power output (MW)

SOURCE: Office of Technology Assessment.
142 ● Industrial and Commercial Cogeneration

realize these costs. Thus, Stirling cycles could be Due to the limited operating experience with

competitive 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 is

cent. Otherwise, installed costs would have to 8.0 mills/kWh (higher than for most prime movbe reduced even further before Stirlings could be ers) (2), while annual fixed O&M costs are

considered competitive. estimated to be $5.O/kW.

USE OF ALTERNATIVE FUELS IN COGENERATION

Cogeneration’s ability to reduce the use of premium fuels (oil and natural gas) depends on its

fuel use flexibility. If cogenerators use nonpremium fuels (e.g., coal, synthesis gas, biomass, industrial or municipal waste) at the outset, or have

the capability to switch readily to such fuels, their

viability obviously will be enhanced. However,

of the available cogeneration technologies described in this chapter, only steam turbines can

burn nonpremium fuels directly. Although R&D

efforts are underway to improve the fuel flexibility

of other available cogenerators (e.g., advanced

combustion turbines and diesels), these improvements may not become commercial until the late

1980’s or early 1990’s. Similarly, advanced prime

movers (such as Stirling engines) that can use

alternative fuels are not likely to be widely available for 5 to 10 years. As a result, many potential cogenerators are looking to alternative fuel

combustion or conversion systems that can be

used in conjunction with current cogeneration

technologies to increase fuel flexibility. Two types

of such systems—fluidized bed combustors and

gasifiers–are discussed below. The use of these

systems in industrial, commercial, and rural cogeneration applications is discussed in chapter 5.

Fluidized Bed Combustion Systems*

In fluidized bed combustion, coarse particles

of fuel (about 1/4 inch in diameter) are burned in

a bed of limestone or dolomite at temperatures

of 1,500° to 1,750° F. The fuel and limestone (or

other 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 evenly throughout the bed area. Feeding is continuous

to ensure steady combustion conditions. The fuel

particles are kept in suspension and in turbulent

motion by the upward flow of air, which is injected from the bed bottom and passed through

a grid plate designed to distribute the air uniformly across the bed. During combustion, the system

resembles a violently burning liquid and the bed

of particles is considered to be “fluidized. ” This

fluidized state of the burning fuel produces extremely good heat transfer characteristics both

among the agitated particles and in the heat transfer surfaces immersed in the bed. Residual materials are drained from the bed continually to allow

for steady operating levels.

There are two major types of fluidized bed

combustors. In atmospheric fluidized beds

(AFBs), fuel combustion occurs at atmospheric

pressures. In pressurized fluidized bed (PFB)

systems, a pressurizing gas turbine elevates pressures in the combustion chamber to 10 to 15 atmospheres. The pressurized system allows a more

compact boiler design and should produce fewer

emissions than AFBs. However, development of

the PFB is behind that of the AFB, and its availability will follow AFBs by several years.

AFBs are commercially available in sizes that

produce from 50,000 to 550,000 lb of steam per

hour, which corresponds to 5- to 55-MW electricity generating capacity (7). A 200-MW demonstration plant currently is under construction by the

Tennessee Valley Authority (TVA), and is expected to come on-line by 1987. TVA estimates

that a 800-to 1,000-MW plant could be built and
Ch. 4—Characterization of the Technologies for Cogeneration ● 143

in operation by 1991. Because of the lack of construction and operating experience with fluidized

beds beyond a 10-MW capacity, however, potential users currently are reluctant to install larger

systems.

Only 10 PFB systems are either planned or in

operation around the world, the largest being a

30-MW unit currently operating in Great Britain.

No commercial vendor of pressurized systems

has been identified, and, as mentioned previously, the availability of pressurized systems is expected to be several years behind that of atmospheric systems (7).

The space requirements for atmospheric and

pressurized fluidized beds are drastically different.

The pressurized combustion process allows for

a more compact boiler design, which significantly

reduces its space requirements. The area required

for a PFB system is approximately one-fifth that

of an AFB of equal thermal output capacity (23,

55). The smaller area occupied by PFBs will be

particularly important for applications where

space is limited or very expensive (e.g., in cities).

Fluidized beds can burn coal, wood, lignite,

municipal solid waste, or biomass. The primary

fuel used to generate electricity with fluidized

beds is coal, and all fluidized bed pIants currently

in operation use coal as their fuel source. Large

(800-Mw) fluidized bed plants are now being designed to use Illinois No. 6 coal, which has a relatively high sulfur content (around 4 percent).

Fluidized bed boilers can burn such high sulfur

coal without flue gas desulfurization because a

large percentage of the sulfur (up to 90 percent)

is trapped by the limestone particles within the

fluidized bed. Flue gas from the fluidized beds

flows through cyclone separators that remove 95

percent of the solid matter in the gas streams.

Electrostatic precipitators remove the remaining

ash to the level required by emission standards.

The ability to burn high sulfur coal economically represents an important advantage of fluidized

bed boilers over the conventional coal combustion systems. However, fuel handling requirements for fluidized beds are more complex than

they are for conventional coal boilers. Both the

coal (or other fuel) and the limestone with which

it burns must be pulverized to a size that can be

fluidized easily. Moreover, present fluidized beds

designed for a particular fuel will require substantial modification of the fuel handling and injection equipment to convert to another fuel. Advanced fluidized bed boilers may be designed so

that they can accommodate different fuel types

more easily.

Due to the lack of experience in the operation

of fluidized bed boilers, information on their

maintenance and reliability is limited. Developers

expect the reliability of both fluidized bed types

to be similar to that of a coal-fired boiler. However, as experience with fluidized bed technology increases, its maintenance requirements may

become less stringent than those for current technologies.

R&D for fluidized bed boilers is directed towards overcoming the basic market barriers to

their use. Current R&D focuses on: 1) installing

larger demonstration plants; 2) determining the

reliability, economic, and environmental characteristics of fluidized bed technology; and 3) demonstrating satisfactory erosion and corrosion behavior in the bed.

Gasification

Gasifiers convert solid fuels into a fuel gas, commonly known as synthesis gas, whose fuel components are principally carbon dioxide and hydrogen, with smaller quantities of various other

substances. * The gasification process consists of

heating or partially burning the solid fuel and, in

some cases, reacting the gas or solid with steam.

The resultant gas is a low- or medium-energy gas

that contains less than about 500 Btu per standard cubic foot (SCF). This gas is not suitable for

blending with natural gas (1,000 Btu/SCF), but it

can be transported economically over relatively

short distances (usually less than 100 miles) in

regional pipelines and used for most of the applications for which natural gas is used (e.g., as a

boiler fuel, for process heat, for cooking, for

space and hot water heating, or as a combustion

turbine fuel).

*The gas from air-blown gasifiers also contains considerable

amounts of nitrogen from the air used in the process.
144 ● Industrial and Commercial Cogeneration

This section analyzes the gasification of three

solid fuels—coal, wood, and municipal solid

waste—to produce a fuel for open-cycle combustion turbine and reciprocating internal combustion engine cogenerators. These solid fuels are

analyzed because they are relatively abundant

and are suitable for gasification. Combustion turbines and internal combustion engines are discussed because, of the commercially available

cogeneration technologies, these currently have

the least fuel flexibility, and because they require

a relatively small investment for equipment (an

important consideration for small, dispersed cogenerators). However, gasifiers also could be

used in conjunction with larger systems such as

steam turbines or combined cycles (see discussion of industrial cogeneration applications in ch.

5). Differences in the gases from each solid fuel

are described first, followed by a consideration

of the implications of these differences for combustion turbine and internal combustion engine

cogeneration systems.

Coal

Coal can be partially burned with air to produce a low-energy gas (50 to 150 Btu/SCF) or with

oxygen and steam to produce higher energy synthesis gas (300 to 400 Btu/SCF). As described below, the low-energy fuel gas is considerably less

efficient as a gas turbine fuel than the synthesis

gas, and it may be unsuitable as a fuel for internal combustion engines. However, a coal gasifier

that produces synthesis gas requires an oxygen

generator, which increases the system cost. Furthermore, both low- and medium-Btu gas from

coal contains sulfur (hydrogen sulfide), ash, and

other impurities that may have to be cleaned from

the gas before it is used. Commercially available

low-temperature gasifiers also produce a gas that

contains some aromatic compounds and other

relatively large compounds that can result in particulate when the gas is burned. High-temperature gasifiers are being demonstrated, and the

technological obstacles to their production do not

appear to be severe.

Wood

Wood has a relatively high oxygen content and

can be gasified completely to synthesis gas (300

to 400 Btu/SCF) by heating it (pyrolysis) without

the need for an oxygen plant. Pyrolysis usually

requires a longer residence time in the gasifier

than air-blown gasification, which increases pyrolysis equipment costs, but probably not enough

to offset the savings from eliminating the oxygen

plant. More rapid pyrolysis gasification is possible, but can result in the formation of considerable quantities of relatively large organic compounds in the gas that would tend to form particulate when burned. Wood gasification also can

be accomplished with air being used to partially

burn the wood. If properly controlled and designed, air-blown wood gasification can produce

a fuel gas containing over 200 Btu/SCF.

Because wood contains sodium and potassium

salts, the resultant fuel gas often contains these

elements as impurities, which can damage or reduce the life of certain turbine blades. Thus, as

with coal gas, wood gas may have to be cleaned

before it is used.

Municipal Solid Waste

Municipai solid waste (MSW) contains large

amounts of paper, plastic, metals, and other materials. The heavier materials can be separated

economically from the paper in MSW, but most

plastics cannot. Thus, for practical fuel purposes,

MSW is a mixture of paper and plastic.

Like wood, MSW can be pyrolyzed to synthesis

gas or partially burned to a lower energy gas in

an air-blown gasifier. However, because much

of the plastic in MSW contains chlorine (e.g.,

polychlorinated biphenyl plastics) the resultant

fuel gas will contain hydrogen chloride (in aqueous form, muriatic or hydrochloric acid), which

is extremely corrosive. Consequently, gasifiers

and other equipment in contact with the gas must

be constructed of expensive, acid resistant steel.

Ceramic-coated metals that can be used in MSW

gasifiers are under development. As a result of

the problems introduced by plastics, MSW fuel

gas currently is not economical. Furthermore, because paper is the only part of MSW that serves

as a good gasifier feedstock, MSW gasification

only partially solves waste disposal problems.
Ch. 4—Characterization of the Technologies for Cogeneration ● 745

Combustion Turbines

As discussed in the previous section, reliable

and efficient operation of open-cycle combustion

turbines requires a high quality fuel that is relatively free of particulate and metallic impurities.

None of the fuel gases described above fully satisfies these criteria. Coal gas contains sulfur and

some heavy metal impurities, and low-temperature gasification of coal can produce a gas that

is high in particulate when burned. Wood gas

contains sodium and potassium and, in some

cases, may produce particulate when burned.

MSW has a much lower sodium and potassium

content, but contains corrosive hydrogen chloride. If untreated, all of these fuels can damage

commercially available turbines and reduce their

useful life. Consequently, extra equipment is

needed to purify these gases. The technical problems of turbine lifetime probably can be solved

if ceramic coatings for turbine blades are successfully developed. However, environmental controls still would be required to prevent the release

of heavy metals (from coal) and particulate (from

all fuel types).

The energy content of the gas also can pose

problems for combustion turbines. Low-energy

gas (perhaps less than 150 to 200 Btu/SCF) can

lower the efficiency of combustion turbines.

Thus, wood and MSW gasifiers must be properly

designed and operated to ensure that the energy

content of the gas is greater than 200 Btu/SCF,

while coal gasifiers will require oxygen plants to

achieve a satisfactory energy content. Combustor

design for medium-Btu gas (250 to 500 Btu/SCF)

is well developed and use of this gas with gas turbines presents no efficiency problems (47,48).

Although fuel quality must be high in order to

prevent damage to turbine blades in open-cycle

combustion turbine operation, the use of solid

fuels is not necessarily precluded. It is unlikely

that coal will be able to be used in this way but

recent developments indicate that pulverized

wood can be made acceptable. The Aerospace

Research Corp. in Roanoke, Va., is designing and

building a 3-MW combined-cycle system using

an open-cycle gas turbine fueled by pulverized

wood (62). The wood is dried to a 25-percent

moisture content, and the combustion gases are

cleaned using hot gas cleanup technology developed in the British pressurized fluidized bed combustion program. Using these steps, it appears

that unacceptable damage to the turbine blades

can be avoided. A 17-MW system (also designed

by Aerospace Research Corp.) operates at an inlet temperature of 980° C and an exhaust temperature of 510“ C.

While this system shows promise, its acceptance will depend on demonstrated reliability over

an extended period. If it is necessary to remove

the blades and repair or replace them more often

than currently anticipated, the O&M costs could

negate the potential economic benefits of using

wood directly. Reliability also will depend on

durable operation of the hot gas cleanup technology and the burner assembly, which requires a

screen to filter out the larger wood particles.

These issues should be resolved by the demonstration unit under construction in Virginia.

Reciprocating Internal Combustion Engines

Reciprocating internal combustion engines suffer from some of the same problems regarding

fuel gas quality as combustion turbines, but

metallic contamination and particulate are more

a pollution problem than a technical problem in

operating these engines. As mentioned above,

hydrogen chloride from MSW plastics can pose

a corrosion problem if it is not removed from the

fuel gas.

For proper operation of an internal combustion engine, the fuel gas must be cooled to avoid

detonation of the fuel. This reduces the energy

content 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 from

coal and higher for low-energy gas from coal. !f

the waste heat from cooling the gas can be used

onsite, this reduction in energy content does not

reduce the engine’s overall fuel efficiency, but

will reduce the electric generating efficiency.

Fuel gas that contains heavy organic compounds can produce gums that increase the

maintenance requirements for reciprocating internal combustion engines. The formation of such

gums is the most common operating problem

with using fuel gas from relatively primitive wood

gasifiers in these engines, and the second most
146 ● Industrial and Commercial Cogeneration

common problem with MSW gas (after hydrogen burn gas from moderate- to high-temperature

chloride formation). With wood gas, internal coal gasifiers are more likely to have maintenance

combustion engines that operate continuously requirements similar to those of engines that burn

may 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 cogeneration technologies just described are interconnected with the centralized electric grid, so

that the cogenerator may supply power to the

grid and use backup power from the grid. However, interconnection with the grid may create

problems for the utility system’s operations or for

the cogeneration equipment itself. As discussed

in chapter 3, many State public utility commissions already have jurisdiction over utility connections with customers. In most States, this includes

regulation of voltage levels and safety standards.

However, in the past the utilities and State commissions have had to be concerned only with regulating power flow in one direction—from utility

equipment to the customer. Because interconnected cogeneration will involve power flows in

both directions, utilities’ and regulatory commissions’ tasks in these areas will be more complicated.

If cogenerated power is of a different quality

from that distributed on the grid, it may affect the

utility’s ability to regulate power supply and may

result in damage to both the utility’s and its customers’ equipment. Moreover, large numbers of

utility-dispatched dispersed generators could

make central load dispatching more difficult. Utilities also are concerned about properly metering

the power consumption and production characteristics of grid-connected cogeneration systems,

and about the effects of such systems on the safety of utility workers. Finally, all of the above concerns raise questions about liability for employee

accidents or equipment damage that may result

from improper interconnection.

The Public Utility Regulatory Policies Act of

1978 (PURPA) authorizes the Federal Energy Regulatory Commission (FERC) to issue orders under

the Federal Power Act requiring the physical connection of a qualifying cogenerator (or other small

power producer) with electric utility transmission

facilities and any action necessary to make that

connection effective (e.g., increasing the existing

transmission capacity or improving maintenance

and reliability) (see ch. 3). Under the FERC rules

implementing PURPA, utility rates for purchases

of power from and sales of power to cogenerators

must take into account the net increased costs

of interconnection (i.e., compared to those costs

the electric utility would have incurred had it

generated the power itself or purchased it from

the grid), including the reasonable costs of connection, switching, metering, transmission, distribution, and safety provisions, as well as administrative costs incurred by the utility. Each qualifying cogenerator must reimburse the utility for

these interconnection costs. The State regulatory

commissions are responsible for ensuring that interconnection costs and requirements are reasonable and nondiscriminatory, and for approving

reimbursement plans (e.g., amortizing the costs

over several years versus requiring one lump-sum

payment).

This section discusses the nature of potential

interconnection problems for cogeneration, describes some of the technologies that can be used

to resolve them, and reviews estimates of the cost

of meeting interconnection requirements. Where

data specific to cogeneration are not available,

analogies are drawn from the relevant literature

on wind or photovoltaic systems.

Power Quality

Utility customers expect electric power to meet

certain tolerances so that appliances, lights, and

motors will function efficiently and not be damaged under normal operating conditions. Power

supplied to the grid by an interconnected cogenerator also is expected to be within certain toler-
Ch. 4—Characterization of the Technologies for Cogeneration ● 147

ances, so that the overall power quality of the

utility system remains satisfactory. Electric utilities

are concerned about three types of power quality: correcting the power factor to keep the voltage and current in phase, maintaining strict voltage 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 wave

forms coincide in time. The capacitive and inductive properties of electrical circuits can cause the

voltage and current to be out of phase at particular places and particular times. Phase shifts are

expressed as the cosine of the fraction (in degrees)

of the full 360° cycle of the difference between

the voltage and current maximums, called power

factor. A power factor of 1.00 means that the current and voltage signals are in phase. A power

factor different from 1.00 means that the voltage

and current are out of phase, and can be either

“leading” if the voltage maximum occurs before

the current maximum, or “lagging” if it occurs

after. Because the most useful power is delivered

when voltage and current are in phase, it is important that the power factor be as close to 1.00

as possible.

Phase shifts are one consideration in setting the

demand component of rate structures (see ch.

3). Thus, utilities typically will have one rate for

power with a power factor of 1.00 sold to other

utilities, another rate for power sold to industrial

customers which may have power factors much

less than 1.00 and that require the utility to install special monitoring devices, and another rate

for power sold to residential customers, where

power factor is not measured individually (l).

Utilities (and cogenerators) supply power with

two basic types of alternating current (AC) generators—induction generators and synchronous

generators (64). An AC generator produces electric power by the action of a rotating magnetic

field that induces a voltage in the windings of the

stationary part of the generator. The rotation is

caused by mechanical means (steam or combustion turbine, diesel engine, etc.) and the magnetic

field is created by a current flowing in windings

on the rotor. For an induction generator, this current is supplied by an external AC source, such

as the electric power grid. For a synchronous generator the rotor current comes from a separate

direct current source on the generator itself. As

a result, a synchronous generator can operate independently of the electric grid or any other AC

power source whereas induction generators cannot. When a cogenerator feeds into a power grid,

induction generators can be advantageous because they are less expensive than synchronous

generators (22). There are other characteristics

of the two types of generators, however, which

can negate this cost advantage.

First, synchronous generators have power factors of approximately 1.00 but can be adjusted

to slightly leading or slightly lagging, while induction generators always have lagging power factors because they have more inductive than capacitive elements (15,35,64). Second, synchronous generators are more efficient than induction generators. These two points can cause synchronous generators to be preferred for units

above a certain power level (about 500 kW), although the precise value depends on the situation (22). Third, care must be taken if there are

several cogeneration units on a circuit, as would

almost certainly be the case for a utility buying

cogenerated power. When a synchronous generator is connected to other generators (either synchronous or induction), separate equipment is

needed to synchronize each additional generator

with the others. Such equipment is standard but

does add to the total system cost.

Most cogenerators that have been installed to

date have been larger synchronous machines because they can be used if the grid is disconnected

and they offer redundant capacity for those (usually higher demand) customers who need secure

power sources, such as hospitals and computer

centers (15). However, PURPA provides incentives for all sizes of cogenerators, and thus those

customers that can use smaller generators and

do not need redundant capacity will have an economic incentive to use an induction generator.

As the penetration of these induction cogenerators increases, more inductive elements are

added to a particular distribution substation’s circuits, resulting in a more lagging power factor.

Unless the utility has a leading power factor, this

creates three potential problems for the utility:
148 ● Industrial and Commercial Cogeneration

the capacity of both transformers and switching

equipment in the transmission and distribution

system may have to be increased to handle the

out-of-phase signals; the efficiency of the transmission network may decrease;* and equipment

and appliances may overheat and need more frequent overhaul (20).

Utilities normally improve lagging power factors by using capacitors, which may be sited

either at the distribution substation or near the

customer’s load or generator, depending on the

cause of the poor power factor and its magnitude

(22). If the poor power factors are caused by

smaller customers’ equipment, utilities usually

pay for the correcting capacitors, while larger customers often are required to pay for their own

power factor correction. Most utilities have guidelines that state the minimum power factor allowed, usually 0.85 lagging (46). If a customer

fails to maintain this minimum, utilities may ask

the customer to install and pay for the necessary

corrective capacitors. * * Traditionally, few utilities

have leading power factors, because most utility circuits (and most appliances and motors) have

more inductive elements than capacitive elements.

Similar policies will apply to cogenerators.

Thus, many utilities are supplying capacitors (out

of the overall transmission and distribution system) for smaller cogenerators, while requiring

larger ones to pay for their own capacitors under

the theory that there will be fewer substations

with a significant cogeneration penetration. Thus,

the avoided substation capacity becomes part of

the utilities’ avoided cost under PURPA and is

credited to the cogenerator (see ch. 3).

*Other sources have indicated that the increase in utility transmission and distribution efficiency compensates for the decrease in

power factor from induction generators (40). Efficiency is increased

because more power is produced onsite and therefore less power

is transmitted and less power is lost due to inefficiencies in the transmission and distribution system.

**Salt River Project has monitored an interconnected photovoltaic

array for an entire year and calculates that its average lagging power

factor is about 0.50 (10). However, the array produces direct current (DC) power and uses an inverter to convert the DC power into

AC. Since cogenerators produce AC power, no inverter is necessary.

Inverters have a poorer power factor than most induction generators.

Southern California Edison’s guidelines are typical of those utilities that have set guidelines:

Installations over 200 [kW] capacity will likely

require capacitors to be installed to limit the adverse effects of reactive power flow on Edison’s

system voltage regulation. Such capacitors will

be at the expense of the [co]generating facility

(49).

This expense can be important for smaller cogeneration systems: for example, the cost of capacitors to increase the power factor of a 300-kW

generator from 0.70 to 1.00 can range from 1 to

4 percent of the capital cost of the cogenerator. *

However, just the installation of capacitors may

not be sufficient. If the capacitors are located near

induction generators, the generators may “self

excite; “ in other words, they may continue to

operate even when they are disconnected from

the utility power source. This could be a problem for utility lineworkers because the cogenerator could start supplying power and endanger the

workers. This is discussed in more detail in the

section on safety, below.

Voltage Regulation

In addition to potential problems with maintaining appropriate power factors, utilities also are

concerned with regulating voltage. Utilities have

many concerns about variations in voltage cycle

from the standard cycle, both over long and short

time intervals. While some customers can tolerate

voltage levels outside of a specified range for very

brief intervals (less than a second), any longer

term variation will cause motors to overheat and

will increase maintenance costs. * * Voltage cycle

*This range assumes that capacitors may cost anywhere from $9

to $40/kVAR (kilovolt-am peres-reactive, a measure of current and

voltage handling capability), with the low end of the range representing the cost for capacitors used in the large bulk transmission systems, such as those maintained by American Electric Power; and

the high end of the range representing the cost for capacitors used

in smaller distribution system applications, such as single-family residence interconnections (29,43). The amount of capacitance needed

to 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 the

capital cost.

**The American Public Power Association’s guidelines cite a table

from the Estimator’s Guide that give recommended voltage ranges

over a given day, hour, minute, and second (l).
Ch. 4—Characterization of the Technologies for Cogeneration ● 149

variations are minimized through the proper design and operation of generators. However, generators do not always function perfectly, and protective “over/under voltage” relays generally are

necessary to disconnect the generator if its voltage falls outside of a certain range. These relays

usually cost under $1,000, including installation

(15,22).

The State regulatory commissions normally require a steady supply of 120 (or 240) volts (+/-5

percent) for residential customers (1). Large commercial and industrial customers often receive

their voltage directly from substations or distribution lines, with much higher voltages and different

tolerances (see the discussion of transmission and

distribution in ch. 3).

Two major analyses are available of potential

voltage regulation problems caused by improperly interconnected dispersed generators. One

study considers a sample utility with sO percent

of its customers generating power with wind machines (14). This study might be considered a

“worst case” analogy for cogeneration because

the output from the wind machines will change

more often than the output of typical (either induction or synchronous) cogenerators. Even with

this 50 percent penetration, the study indicates

that substation voltage levels would remain within

5 percent of standard levels because:

. . . [the] addition of small wind systems to a [distribution] feeder will not occur suddenly; rather

wind-turbine generators will be installed in small

capacities throughout the utility’s system and if,

by chance, many are added to a particular feeder, the voltage profile will change gradually.

[Also] utilities adjust voltage regulation equipment for normal load growth and wind-turbine

generators added to a feeder will influence this

normal adjustment procedure only slightly (13).

In the second study, the Salt River Project (SRP)

installed a transformer on its 37.5-kVA distribution circuits and connected it to two residences

(both unoccupied), one of which uses a photovoltaic array, in order to test the effect of the

photovoltaic system on other residences connected to the same distribution transformer (12).

That study also concluded that voltages would

remain within 5 percent of standard (10).

Both of these studies indicate that cogeneration should not present any longer term (i.e., lasting longer than 1 minute) voltage regulation problems for utilities. However, sudden and more

brief changes in power system voltages can also

occur in utility systems—especially when large

power consuming equipment is turned on and

off (such as the cycling of air-conditioner compressors and refrigerators). These changes are

caused by the large amount of current that is

needed to startup these motors, thereby removing some power normally used for the remaining load on the circuit. Because these large surges

of power can temporarily dim lights, these

changes are called “voltage flicker. ”

Utilities usually confine voltage flicker problems

to the customer’s own system by requiring some

large commercial and industrial customers to use

a “dedicated” distribution transformer that connects the customer’s load directly to a higher voltage distribution line, substation, or, in some

cases, the higher voltage transmission network. *

Because of this policy, voltage flicker and regulation effects of cogenerators are extremely siteand circuit-specific and it is difficult to make any

general statements except that most of the commercial and industrial facilities that are potential

cogenerators probably already have a dedicated

transformer (15). Therefore there would be no

additional cost for voltage regulation if these

customers were to install cogenerators. One way

for cogenerators to get around this problem is to

install synchronous generators, which already include voltage regulators.

However, if a potential cogeneration facility

does not have a dedicated transformer and uses

an induction generator (e.g., smaller commercial

and residential customers), the cost involved in

installing a transformer could be equal to all other

interconnection equipment costs combined, and

therefore could be a major disincentive to cogeneration. In general, however:

dedicated transformers are not a valid issue

for 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 connection), the density of the surrounding area (transformers would be

needed in rural areas with spotty concentrations of loads, and in

very high density urban areas), and on other site- and distributioncircuit-specific conditions.
150 . Industrial and Commercial Cogeneration

power producers (less than about 20 kw) and,

of those, only the ones installed in high density

areas where non-dedicated transformers are the

usual method of service. where a dedicated

transformer is needed, the issue usually is] settled through negotiations between the utility and

the customer with the requirement for a dedicated transformer being waived if it would be impractical (15).

Even though dedicated transformers may not

bean issue for many cogenerators, most utilities

protect themselves by including a clause in their

interconnection agreement that says:

[f high or low voltage complaints or flicker

complaints result from operation of the customer’s [co]generation, such generating equipment

shall be disconnected until the problem is resolved (49).

The interim guidelines published by the Rural

Electrification Administration state that “no induction generators larger than 10 kW should be

permitted on single phase secondary services . . .

due to possible phase unbalances and voltage

flicker” without the electric cooperative first

studying the situation to ensure that adequate and

reliable service to all members will be maintained

(52).

Harmonic Distortion

A third utility concern related to power quality

is harmonic distortion. Occasionally, other frequencies besides the standard 60 cycles per second are transmitted over the power system, usually due to the use of an inverter that converts

DC power into AC power. The distortions are

called harmonics because they have frequencies

that are multiples of 60. These distortions may

be made up of several harmonic frequencies or

a single strong frequency. A 60 cycle-per-second

power signal accompanied with many other harmonic signals may cause several problems for the

utility:

Excessive harmonic voltages [and currents]

may cause increased heating in motors, transformer relays, switchgear*/fuses, and circuit

breaker ratings, with an accompanying reduction

*Switchgear (used in this citation and throughout this report) refers

to all of the necessary relays, wiring, and switches that are used

in interconnection equipment.

in service life, or distortion and jitter in TV pictures, or telephone interferences. Also, excess

harmonics may produce malfunction in systems

using digital and communications equipment

(20).

Other possible problems caused by excessive harmonics are the overloading of capacitors, malfunctioning of computers, and errors in measuring power at the customer’s kilowatthour meter

(12,25).

What constitutes “excessive” harmonics is not

well defined. There is no agreement on the exact ratio of distorted signals to the standard signal,

and a great deal of research is underway to determine this ratio precisely. SRP has collected data

on the operation of an interconnected photovoltaic array for over a year:

But, SRP feels further study is needed on the

level of harmonics that occurs naturally on a utilty system, the limits that must be placed on harmonics required to prevent adverse effects on

equipment and appliances, and on whether certain harmonic frequencies are more harmful [to

the utility system] than others (4 I).

While further research is underway, both the

Electric Power Research Institute (EPRI) and the

American Public Power Association (APPA) have

recommended maximum percentage limits for

total systemwide harmonic distortions for both

current and voltage signals (as well as limits for

any one single source and single voltage or current frequency). EPRI (20) suggests 5 percent for

current harmonics, and 2 percent for voltage,

while APPA (1) suggests 10 percent for current

and 2 percent for voltage. *

In the past, most of the major problems of harmonics have occurred with the normal operation

of inverters, rather than any malfunctioning of

conventional induction or synchronous generators (15). Since inverters have a high capital cost,

they rarely are used and their present impact on

utility systems is small in most cases. Because

cogenerators produce AC power at the standard

power system frequencies and, therefore, do not

use inverters, and because these generators are

not normally a significant harmonic source, most

*Several municipal utilities already have adopted APPA’s recommendations for harmonics, such as the Salt River Project in Phoenix.
Ch. 4—Characterization of the Technologies for Cogeneration . 151

utility engineers feel that harmonic distortions will

not increase when cogenerators are interconnected to utility systems (43).

Summary of Power Regulation Problems

Smaller cogenerators (under 20 kW) may not

be able to afford the necessary power regulation

equipment in connecting to the centralized grid,

including capacitors to correct power factor (if

required) and dedicated transformers to regulate

voltage (if not already in use). However, these

smaller units may have little or no adverse effect

on overall system power quality, according to one

study looking at wind machine penetration. Thus,

a utility, when considering each particular case

of a smaller cogenerator, may be able to exempt

the cogenerator from the requirements for expensive interconnection equipment. Larger gridconnected cogenerators might need to install

capacitors to correct for power factor—if they use

induction generators— but probably will have a

dedicated transformer already.

Even though all of the power quality effects of

interconnected cogeneration are very site-specific, most of the evidence gathered so far indicates

that neither excessive harmonic distortion nor objectionable voltage flicker will be caused by adding any size of cogenerator to the centralized

system.

Metering

Three types of metering configurations can be

used to measure the amount of energy consumed

and produced by dispersed generators. The first

uses the simple watthour meter that is commonly

found outside of most homes today and that costs

approximately $30* (1,29). When a cogenerator

is producing power that is sold back to the utility, the watthour meter simply runs backward

(even though the meter running backwards can

be off as much as 2 percent in measuring power)

(l). As a result, the meter will measure only net

power use, thus assuming that there is no differ-

*More complicated (and more expensive) three-phase watthour

meters may be used where three-phase power, which consists of

three (current and voltage) single-phase signals, each out of phase

with the others by 120°, is supplied to larger commercial and industrial customers.

ence between the utility’s rates for purchasing

cogenerated power and its retail rates. If these

rates are different (as they are likely to be with

most utility systems) then two watthour meters

can be used, one that runs in the reverse direction of the other, with the first meter to measure

power produced by the cogenerator and the second (equipped with a simple detente or rachet

that prevents the reverse rotation of its induction

disk) to measure the customer’s power consumption. This configuration is recommended by the

National Rural Electric Cooperative Association

interim guidelines, unless the individual electric

cooperative prefers a different metering system

(52).

The third configuration uses more advanced

meters to measure a combination of parameters,

including power factor correction, energy, and

time-of-use. * Some utilities are asking customers

to install these advanced meters in order to understand the relationship between the cogenerator and the central power system better, and to

collect the best data possible to help determine

future interconnection requirements (such as information on power factor requirements and

peak demands) and to decide how to price buyback and backup power. These more sophisticated meters can cost $300 or more each (29).

In some cases, such as with Georgia Power, the

utility is supplying the advanced meters and paying for the collection and analysis of data (30).

In others, such as with SRP (46) and Southern

California Edison, ** the customer may be asked

to pay for the meters (either as a one-time charge

or in several types of monthly installment plans).

Controlling Utility System Operations

Most utility systems have a control center to

coordinate the supply of power with changes in

demands. Such coordination involves both day-

*Theordore Barry & Associates (52) provides many examples of

these more advanced configurations, and includes the cost (excluding instrument transformers) for different combinations of singlephase meters.

* *southern California Edison already bi Ils its larger customers

(either those installations with greater than 200 kW of generation

or those with less than 200 kW generation with greater than 500

kW of load) using time-of-day meters. Customers that become

cogenerators who do not have time-of-day meters already will not

be required to install them by Edison (15).
152 ● lndustrial and Commercial Cogeneration

to-day operations, including dispatching generators and monitoring load frequency and power

flows over the transmission and distribution network, and longer term tasks needed to schedule

unit commitments and maintenance (25). If load

changes are not anticipated correctly by system

controllers, transformers may become overloaded and circuit breakers may open the line,

possibly causing power reductions or interruptions for customers that are connected to that

transformer. Cogenerators have the potential to

affect two types of system operations: generation

dispatch and system stability.

Generation Dispatch

Many utilities are concerned that large numbers

of cogenerators will overload system dispatch capabilities, including the ability to anticipate

transformer overload conditions (43). If the utility feels the cogenerated electricity needs to be

dispatched centrally, it could require a connection via telemetry equipment between the cogenerator and the control center, so that the system

controllers can turn cogenerators on and off according to the overall needs of the utility system

(36). This telemetry equipment is costly, and

probably would be used only with very large

cogenerators.

One study has looked at potential dispatch and

control problems for a large penetration of wind

generators and has concluded that with approximately half of the load using grid-connected wind

turbines, the dispatch and control errors of the

system controllers would not increase significantly (14). Because wind machines would have

greater fluctuations of power output than cogenerators, large numbers of cogenerators should

pose even fewer control problems.

For smaller cogenerators, it is unlikely that the

utility would require any dispatch control. Rather,

these smaller units can be treated as “negative

loads,” in which case the controller would subtract the power produced by the dispersed

sources from his overall demand and dispatch the

utility’s central station generation to meet the reduced demand. Negative load treatment probably will be more advantageous to the utility system than dispatch telemetry because the overall

impact of smaller cogenerators on system loading

and voltage conditions may be quite limited (44).

Negative load scheduling works well for those

utilities that already have a few cogenerators online, and some utility transmission planners believe that even much larger numbers would not

cause problems for the utility. That is, as more

cogenerators are added to a particular distribution substation, the utility would continue to use

negative load scheduling. (The utility would need

to increase the capacity of the transmission and

distribution lines–equivalent to upgrading the

capacity of its lines as a developer adds more

homes to a subdivision.) Because conditions are

so site-specific, it is difficult to generalize and put

forth guidelines, and each utility’s situation must

be considered individually to determine the appropriate requirements (44).

System Stability

Stability refers to the ability of all generators

supplying power to stay synchronized after any

disturbance (such as after a fault on part of the

power system) (25). At its most extreme, a disturbance may cause a loss of synchronization for the

entire power system (resulting in a possible systemwide blackout), or may alter the flow of

power within the system and cause selected

blackouts.

Not much is known about the effects of a significant number of cogenerators on a system’s

stability. Utilities are concerned that large penetrations of small, dispersed sources of power

could contribute to unstable conditions. Some

analysts (25) cite a 5 to 10 percent penetration

of the service area (with photovoltaic systems) as

the definition of “large penetration,” while others

cite much higher figures. One study by Michigan

State University (cited in 25) shows that wind turbines cause fewer stability problems for the overall utility system than variations in weather (such

as the movement of storm fronts). Further research on the effects of cogenerators on system

stability is needed before any conclusions can be

made, however.
Ch. 4—Characterization of the Technologies for Cogeneration ● 153

Safety

A major concern with interconnection of dispersed generators is the safety of utility employees

working on transmission and distribution lines.

During routine maintenance or repairs to faulty

lines, lineworkers must disconnect the generation source from the service area, and establish

a visibly open circuit. Also, before starting any

repairs, they must ground the line and test it to

ensure that there is no power flowing in the line.

The Occupational Safety and Health Administration publishes a series of guidelines for utilities

on these procedures (OSHA subpt. V, sees.

1926.50 through 1926.60),

Disconnecting and grounding the lines is relatively simple when the generation system is centralized and there are few sources of supply.

However, with numerous sources of power supply (as with grid-connected cogenerators) the disconnect procedure becomes more complicated

and extra precautions may be needed: the utility must keep careful accounts of what dispersed

equipment is connected to the system, where that

equipment is located, what transmission lines and

distribution substations it uses, and where the

disconnecting switches are located. To simplify

these procedures, many utilities have asked cogenerators to locate their disconnect switches in

a certain place, such as at the top of the pole for

the distribution line going into the customer’s

building (30).

Disconnecting and reconnecting a cogenerator

is not so simple as just turning the switch off and

on, because the cogenerator must be synchronized and brought up to the standard frequency

before coming back on-line with the centralized

system. Without this synchronization, both the

cogenerator and the customers’ appliances could

be damaged.

However, the normal operation of circuit

breakers that have disconnected a line to clear

a fault is to reclose automatically after a fraction

of 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 onequarter to one second, and then recloses to restore service In the event

the fault was temporary. This operation may be repeated up to three

ent, a cogenerator also will need to be concerned

about this reconnection. Most utilities require

protective equipment that can disconnect the cogenerator from the line before any reclosing can

occur (49).

Another problem with disconnecting cogeneration equipment is self-excitation of the generators.

When an induction generator is isolated from the

rest of the grid (because of a downed line or a

breaker opening the line), the absence of the gridproduced power signal usually will shut down the

generators. However, if there is sufficient capacitance in the nearby circuits to which the generator is connected (e.g., power factor correcting

capacitors), the induction generator may continue to operate independently of any power supplied to the grid. * The power signal produced

by the isolated self-excited induction generator

will not be regulated by the grid’s power signal

and the customer’s electricity-using equipment

may be damaged. More importantly, an isolated

induction or synchronous cogenerator that reenergize on the customer’s side of a downed

transmission or distribution line, could endanger

utility workers. Self-excitation is less of a problem with synchronous generators (which will continue to operate independently of the grid).

There are two ways to prevent self-excitation

problems. First, the utility can put the corrective

capacitors in a central location, in which case

disconnecting a cogenerator also will disconnect

the capacitors and reduce the possibility of selfexcitation. Southern California Edison recommends this method for smaller (less than 200 kW)

cogenerators (49). Alternatively, voltage and frequency relays and automatic disconnect circuit

breakers can be used to protect both the customer’s equipment and utility workers.

In summary, while extra precautions must be

taken to ensure the safety of utility crews, none

of these precautions is difficult to implement and,

times, depending on the recloser setting, before the OCR [leaves] the

line deenergized (52).

Such alternate connecting and disconnecting can damage the

cogenerator.

*One consultant calculated that this self-excitation is possible with

wind turbines (1 4). A 100-kW machine capable of supplying half

of the customer’s load, connected to the capacitors needed to correct a 0.75 power factor to 1.00, will self-excite and supply 30 volts

to that load—25 percent of the standard 120 volts.
154 ● Industrial and Commercial Cogeneration

when properly carried out, will minimize the potential for danger to utility personnel.

Liability

Despite the protective relays and automatic disconnect switchgear that may be installed, this

equipment may not always function properly and

the cogenerator could damage the utility’s equipment or other customers’ appliances. Under

PURPA, the net increased interconnection costs

may include the cost of insurance against liability for such damage, or liability may be assigned

to the cogenerator in the purchase power contract. Liability issues also have been raised regarding wheeling, but in that case no special insurance policy is needed, and all the ratepayers

share any liability for damage due to wheeled

power (6).

At the present time, few guidelines exist for utilities concerning the liability of the cogenerator.

A set of guidelines being prepared by EPRI recommends that the cogenerator be responsible for

damages caused by the cogeneration system, up

to and including the connection to the customer’s

side of the meter (20). A second approach has

been adopted by Southern California Edison,

whose interconnection contract provides that:

Customer is solely responsible for providing

protection for customer’s facilities operating in

parallel with Edison’s system and shall release

Edison from any liability for damages or injury

to customer’s facilities arising out of such parallel

operation, unless caused solely by Edison’s negligence . . . Customers shall be required to maintain an in-force liability insurance in an amount

sufficient to satisfy reasonably forseeable indemnity obligations and shall name Edison as an additional insured under said insurance policy (49).

A precise definition of “reasonably foreseeable

indemnity obligations” is not yet clear. Few utilities will put an exact figure in writing and leave

each case to be determined on an individual basis. Many have argued against some of these liability requirements that place an excessive cost

burden on owners of cogenerators and small

power producers. A staff report to the California

Public Utilities Commission (CPUC) recommended that utilities be allowed to include only

standard “boilerplate” liability and indemnity

provisions, and not to require a cogenerator “to

assume a greater responsibility for losses resulting

from its acts or equipment failure than it would

have under common law principles” (8). The staff

also has tried to eliminate the dual cost burden

of insurance and dedicated transformers, and has

recommended that cogenerators and small power producers with capacity under 20 kW that

have installed dedicated transformers be excused

from providing proof of liability insurance. In another case, the New York Public Service Commission ruled that the utility could not require a

cogenerator to assume the utility’s broadly

sweeping liability clauses, but rather the utility

could require a cogenerator to be responsible

only for negligent installation and operation of

his equipment (3).

Summary of Requirements

Cogenerators may need several types of equipment for proper interconnection with centralized

utility grids: corrective capacitors to meet power

factor requirements, relays and filters to protect

the circuits of other customers, special meters to

measure cogeneration energy profiles, and dedicated transformers and increased transmission

and distribution line capacity to ensure reliable

service. Moreover, cogenerators may be required

to carry special liability insurance to limit the

responsibility of the utility or its noncogenerating

customers. These requirements are displayed

graphically in figure 41.

While utilities and cogenerators agree that

interconnection may pose all of the problems discussed above, there is still much to be decided

about the frequency and severity of these problems for particular cogeneration systems. Even

when utilities and cogenerators agree about the

nature of potential interconnection problems,

they may disagree about the type or quality of

equipment necessary to resolve them.

Quality of Interconnection Equipment

One of the critical questions concerns the quality of the equipment used in the interconnection.

There are two basic levels of quality: “industrial”
Ch. 4—Characterization of the Technologies for Cogeneration ● 155

Figure 41 .—Possible Power System Additional Equipment Requirements to Serve Qualifying Facilities

I

I

I

I

SOURCE: Blair A. Ross, “Cogeneration and Small Power Production Facility Effects on the Electric Power System,” paper presented at Federal Energy Regulatory

Commission conference on Cogeneration and SmalL Power Production RuLes, June 1980.

and “utility” grades. Utility grade equipment generally is more reliable and responsive, but it also

costs more than industrial grade (40). Although

requirements have varied in the past, a general

consensus is emerging that industrial grade equipment is adequate for smaller (under 300 kW) cogenerators while larger cogenerators should use

the more costly utility grade. This distinction is

based not only on the safety implications of a

system failure but also on the cost of replacing

damaged equipment. For smaller cogeneration

systems, the maintenance or replacement cost of

utility grade equipment could be several times

higher than the cogenerator’s monthly electricity

bill.

However, utility grade equipment may be necessary under certain circumstances. For example,

Southern California Edison requires “utility quality” protective relays if a cogenerator is large

enough (more than 1 -MW installed capacity) that

the opening and closing of utility relays must be

synchronized (49). While many utility engineers

agree with this distinction, they also may disagree

about the size of equipment that requires industrial or utility grade. One source suggests that industrial grade equipment should be used by cogenerators smaller than 200 kW, while others suggest 1 MW as the cutoff point (34).

Guidelines for Interconnection

Utilities differ widely in their general specification of interconnection requirements. Some utilities have adopted guidelines, while others review

each interconnection design to ensure that it

meets their standards. Although case-by-case review can result in costly delays for a cogenerator,

utilities and interconnection experts agree that

separate reviews are necessary until industrywide

standards have been developed for the interconnection of onsite generating equipment (4). At

this time, each cogenerator has virtually customdesigned configurations of interconnection

equipment because the circumstances under

which connections are made vary widely, and

so few cogenerators have been installed by each

engineer that it is difficult to generalize and use

rules-of-thumb (57).

Research is underway to provide the needed

information for future guidelines, and several sub-
156 . Industrial and Commercial Cogeneration

committees of the Institute of Electrical and Electronics Engineers’ (IEEE) Power System Relaying

Committee* are working together on a manual

of accepted interconnection standards, with specific engineering guidelines for a wide range of

equipment types and conditions. EPRI also is assembling its own guidelines, although for a more

general audience, and researchers at the Jet Propulsion Laboratory (JPL) have made many recommendations on guidelines to the Department of

Energy’s (DOE) Electrical Energy Systems Division

(25). Several staff members at IEEE, EPRI, DOE,

and JPL are delegates to a committee that will

recommend changes in the National Electrical

Code related to interconnection equipment by

late 1983 (24). Finally, several utilities are installing instruments on their own initiative to measure

power factor, voltage variation, frequency, and

other aspects of cogenerated power, with the

hope that this better instrumentation will lead to

a better understanding of interconnection performance, costs, and benefits (37).

This research points out the need for performance-based guidelines—allowing cogenerators to

meet general functional criteria—rather than technology-specific guidelines that might require particular technologies that could become outmoded or more costly in the future. The CPUC

staff (8) recommended that utilities should use

performance-based guidelines (that specify such

functions as reacting properly to utility system

outages, assisting the utility in maintaining system

integrity and reliability, protecting the safety of

the public and of utility personnel), rather than

specifying a list of equipment that could restrict

cogeneration unnecessarily (8).

Southern California Edison complied with the

CPUC staff recommendation by issuing a complete set of equipment performance specifications

as its guidelines. The guidelines provide all requirements for design, installation, and operation

of interconnecting equipment in clear, easy-toread language, and include examples of wiring

diagrams and metering configurations that meet

its performance specifications for three types of

cogenerators: those over 200 kW with the inter-

*Hassan and Klein (25) give a good list of the various groups within

IEEE, as well as other organizations, that are working on these issues.

connection equipment owned by the customer,

those over 200 kW with the equipment owned

by the utility, and those under 200 kW (49). Other

consultants have also suggested that different policies be used with different sizes of generators,

with one policy covering units under 5 kW, another for units between 5 and 40 kW, and a third

for units over 40 kW (40).

Southern California Edison requires all interconnection equipment (that eventually will be owned

by the utility) for cogenerators larger than 200 kW

to have four functions:

(i) A set of utility-owned circuit breakers in addition to any circuit breakers that the customer

may have installed,

(ii) synchronizing relays,

(iii) meters for kW and kWh produced and demanded, kVARh demanded, and (for cogenerators larger than 1 MW) telemetry and telephone communication lines, and

(iv) protective relays for short circuits, isolation (to

separate the cogenerator from other customers on its line), over/under frequency and voltage, and circuit-breaker closing/reclosing (to

prevent the re-energizing of an open line) (49).

For installations over 200 kw with customerowned interconnections, the Southern California

Edison requirements state: “The customer shall

provide adequate protective devices to detect

and clear . . . short circuits, . . . detect voltage

and frequency changes, . . . and prevent reparalIeling the customer[’s] generation.” There are

similar, although less stringent, requirements for

under 200 kW equipment (49).

Southern California Edison also gives the cogenerators three different options for paying for all

required interconnection equipment: (i) the utility

supplies and owns the interconnection equipment and the cogenerator pays a standard

monthly charge, currently 1.7 percent of the total

costs of the facilities; (ii) the cogenerator installs

the equipment to utility specifications and transfers ownership to the utility at which time the utility assesses a one-time engineering charge for approving the design, and the utility charges monthly operation and maintenance fees for the equipment (currently 0.75 percent of the total costs of

the facilities), or (iii) the utility builds the equipment, with an advance payment from the cogen-
Ch. 4—Characterization of the Technologies for Cogeneration ● 157

erator, and the cogenerator pays the monthly

operation and maintenance charge once construction is completed (49). Most utilities just offer the last option, with monthly charges greater

than $1,000 for large installations of several megawatts capacity, and much less for smaller facilities

(46).

Costs for Interconnection

Interconnection costs can vary widely depending on the size of the cogeneration system and

on the requirements of the utility or State regulatory commission. Two published studies on cogeneration allow for a detailed comparison of

costs for a variety of assumptions. One set of sample costs includes schemes for a variety of generators and is shown in table 26. These schemes

have used similar assumptions in assembling the

interconnection costs, and so are useful for comparison purposes and relating the economies of

scale of interconnection.

As can be seen in table 26, the interconnection requirements for the larger units cost less per

kilowatt to construct and maintain; and as the size

of the cogenerator decreases, the cost per kilowatt increases rapidly, from $35/kW for the 20-

MW generator up to $1,328/kW for the 2-kw

generator. Because cogenerators in this range

typically cost about $1 ,000/kW, the total costs

for interconnection of these smaller generators

can exceed the capital costs of the generators.

Some utility personnel feel these costs are higher than their experience would indicate (35,43).

Some of these costs may be unnecessary or else

might be paid by the utility instead of by the

cogenerator (6,8). For instance, dedicated transformers may be installed already, thereby reducing the total interconnection cost substantially—in

some cases by more than 30 percent.

These costs also depend heavily on whether

existing switchgear is adequate or whether

modifications will be necessary to accommodate

the cogeneration equipment. For example, two

different 900-kW installations might vary in cost

between $150,000 (or $167/kW) and $250,000

(or $278/kW)–with the difference resulting from

the number of modifications needed in existing

distribution cables and switchgear (57).

Based on the published information, OTA has

assembled cost information for three different

sized systems, using two series of assumptions for

interconnection requirements for two of the

smaller generators and one set of assumptions for

the larger generator (22).

Table 26.—Cogeneration Interconnection Sample Costsa

Costs (dollars)

Equipment (kW) Engineering Total cost

Scheme

b Generator size Transformer size Switchgear Transformer Relay labor Total ($/kW)

Larger generators:

A 20,000

B 5,000

c 4,200

D 1,000

E 200

Smaller generators:

F 100

G’ 50

H 50

I 20

J

d e 5

K

d 2

20,000

10,000

10,000

2,500

750

111

112

112

30

25

10

$296,000

150,000

129,000

56,000

27,000

$4,700

4,340

1,570

2,590

496

1,035

$314,000

160,000

160,000

31,000

16,000

$2,250

1,530

1,530

640

130

350

$51,000

43,000

18,000

11,000

7,000

$2,065

2,125

1,325

360

360

320

$30,000

30,000

26,000

12,000

10,000

$1,900

1,550

1,500

1,450

950

950

$691,000

339,000

319,000

104,000

60,000

$10,915

9,545

5,925

5,040

1,935

2,655

$35

68

76

104

300

$109

191

119

252

387

1,328

aAll costs include new (either shared or dedicated) transformers, but do not include: watthour meters, annual maintenance requirements for all interconnection equipment, 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).
158 ● Industrial and Commercial Cogeneration

Because the range of conditions and the use

and cost of interconnection equipment may vary

widely with smaller cogenerators, two sets of assumptions were used; a “best case” that assumes

that power factor correcting capacitors, a dedicated transformer, and protective relays would

not be needed; and a “worst case” that assumes

that this equipment (along with more expensive

meters and equipment transformers for these meters and relays) would be needed. Both 50-kW

systems use induction generators, while both

5oo-kW and 5-MW systems use synchronous generators.

All of the equipment meets industrial grade

specifications and operates at 480 volts on a

three-phase circuit (these are common conditions

for medium-sized equipment). All of the costs

cited include installation, except for the protective relays which cost $250 to install (22). Table

27 displays the various cost components of the

interconnection for the three generators.

The cost to interconnect the smallest generator

(50 kW) varies between $52 and $260/kW, or a

range of 5 to 26 percent of the capital cost of the

generator (assuming $1 ,000/kW capital cost). The

cost for the 500-kW generator varies between $22

and $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 observed: First, most of the variations in cost result

from the addition of a dedicated transformer to

the interconnection requirements, as well as the

use of more expensive relays and other protective devices. Second, the cost per kilowatt of

capacity decreases quickly as the size of the generator increases, primarily due to the economies

of scale for circuit breakers, transformers, and installation costs, and because most of the cost of

the relays is independent of the size of the generator they protect. For example, even though the

capacity of the !@O-kW generator is ten times that

of the 50 kw, the circuit breaker costs only eight

times as much and the dedicated transformer

only three times as much.

From these studies, it is concluded that there

is a great deal of variation in the cost of interconnection equipment per kilowatt of cogeneration

capacity. The costs will depend on the size of the

cogenerator and the amount of transmission and

distribution equipment already in place. Costs per

kilowatt will increase as the size of the generator

decreases and as the amount of new transmission and distribution equipment increases.

Summary

Interconnecting cogeneration could create

problems for utilities, especially with respect to

providing satisfactory power quality, controlling

system operation, and minimizing utility liability

and safety problems. While many of these problems may require special dedicated facilities or

Table 27.—interconnection Costs for Three Typical Systems

50 kW 500 kW 5 M W

Equipment Best Worst Best Worst Average

Capacitors for power factor . . . . . . . . . . . . — $1,000 $5,000 – “

Voltage/frequency relays . . . . . . . . . . . . . . . $1,000 1,000 $1,000 1,000 $1,000

Dedicated transformer. . . . . . . . . . . . . . . . . — 3,900 – 12,500 40,000

Meter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 80 1,000 80 1,000 1,000

Ground fault overvoltage relay . . . . . . . . . . 600 600 600 600 600

Manual disconnect switch . . . . . . . . . . . . . 300 300 1,400 1,400 3,000

Circuit breakers . . . . . . . . . . . . . . . . . . . . . . 620 620 4,200 4,200 5,000

Automatic synchronizers. . . . . . . . . . . . . . . — — 2,600 2,600 2,600

Equipment transformers . . . . . . . . . . . . . . . 600 1,100 600 1,100 1,100

Other protective relays . . . . . . . . . . . . . . . . — 3,500 – 3,500 3,500

Total costs ($) . . . . . . . . . . . . . . . . . . . . . . $2,600 $13,020 $11,080 $32,900 $57,800

Total costs ($/kW). . . . . . . . . . . . . . . . . . . 52 260 22 66 12

NOTE: “-” means an optional piece of Interconnection equipment that was not Included in the requirements and cost

calculations.

SOURCE: Off Ice of Technology Assessment calculations based on data derived from Howard S. Geller, The Interconnection

of Cogenerators arrd Small Power Producers to a Utility System (Washington, D. C.: Office of the People’s Counsel,

February 1982),
Ch. 4—Characterization of the Technologies for Cogeneration ● 159

operating and administrative techniques, none

are insurmountable and most have been resolved

in the past (44). One executive remarks that the

utility industry has not yet identified any problems with distributed generation which cannot

be solved technically (43). The real problem is

whether the cost involved will be prohibitive.

However, in order to determine costs, more

analysis and better data are needed. Results obtained to date through simulation and analysis

must be verified in the field (25). In addition, State

commissions need to encourage those utilities

that have not yet done so to prepare guidelines

for interconnection requirements, and to update

those guidelines as the results of new research

being conducted by EPRI, DOE, APPA, IEEE, and

individual utilities are made available, and as experience is gained.

THERMAL AND ELECTRIC STORAGE

The analysis in chapter 5 shows that the greatest

opportunity for cogeneration occurs when onsite thermal demands closely match regional electric demands. To some extent, a cogenerator or

a utility could mitigate a mismatch between these

two demand curves through the use of devices

that store either the thermal or electrical energy

for release when it is needed. Thermal and electric storage techniques are described briefly

below. *

Thermal Storage

The thermal demand of an industry or building

is rarely constant; rather, it varies with the day

(e.g., weekday v. weekend day) and time of day

as well as with the season. As a result, an industrial or commercial cogenerator may produce

more thermal energy than can be used immediately onsite. Similarly, if a cogenerator is supplying electricity to the utility grid, a mismatch between the timing and/or magnitude of the onsite

thermal needs and the utility’s electric demands

could result in temporary excess thermal energy

production. In such circumstances, it maybe advantageous to store this excess thermal energy

for subsequent use during periods when the cogenerator is producing less than is needed onsite. Thermal energy storage also can be used to

reduce peakloads on utility powerplants, to improve the efficiency of heating or cooling devices

by reducing cyclic losses, and to make it practical 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 day

can be stored for heating during the night).

There are three basic approaches for storing

thermal energy. In sensible-heat storage, engine

or exhaust heat is used to elevate the temperature

of a liquid or solid that does not melt or otherwise change state for the temperature range in

question. Water is the most widely used material

for sensible-heat storage. It is relatively easy and

inexpensive to store at temperatures below its

boiling point, but can be stored at temperatures

up to 300° to 400° F if pressurized tanks are used.

At higher temperatures, the pressure required to

maintain water in its liquid form would greatly

increase the cost and danger of operating the

system. Even at lower temperatures, it can be difficult to maintain constant output temperatures

when the stored energy is tapped. Rocks also can

be used in sensible-heat storage by heating them

and keeping them in insulated containers. However, the heat storage capabilities of rocks are

poorer than those of water,

Latent-heat storage occurs when a material

undergoes a phase change (e.g., melting, vaporizing) when heated. This approach supplies energy

at a relatively constant temperature and usually

allows for greater amounts of energy to be stored

in a given volume or weight of material, as compared to the sensible heat approach. More than

500 phase change materials have been reported

as potential thermal energy storage candidates,

but three basic categories are used in low-temperature applications: 1 ) inorganic salt compounds, 2) complex organic chemicals such as

paraffins, and 3) solutions of salts and acids. The
160 . Industrial and Commercial Cogeneration

disadvantages of latent-heat storage include the

high cost of the phase change materials and the

difficulty involved with transmitting thermal

energy in and out of the storage medium.

Chemical storage techniques use heat to produce a chemical reaction, and then release the

heat when the reaction reverses. The most promising materials for the chemical storage of thermal energy are metal hydrides (compounds of the

metal and hydrogen) because their reactions can

be reversed easily. Moreover, hydrides have relatively high heats of formation, while the reaction products can be stored at ambient temperatures and the heat recovered as needed and

stored indefinitely with no need for insulation.

Chemical storage techniques may be applied at

a wide variety of temperatures, and transporting

the chemical energy is convenient. However,

chemical storage is likely to be less attractive than

other methods because the catalysts required to

facilitate the chemical reaction are expensive, as

is the storage of gaseous chemicals in pressurized

tanks, and the metal hydrides may be highly toxic

and pose a dangerous fire risk.

The size of a thermal storage unit will depend

on the onsite energy needs (e.g., a single residence, a large building or industrial plant, a utility

powerplant). However, most of the experience

to date is in the design, construction, and operation of smaller thermal energy storage systems

capable of storing heat from electric generating

plants with less than 500-kW capacity. Table 28

indicates possible required storage capacity as a

function of typical industrial plant sizes.

Reliable data on costs, maintenance, and performance for thermal energy storage systems are

not yet available. Most systems are still in R&D

stages. Thermal energy storage using water in

above 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 60

100 200 to 300

SOURCE: Roger L. Cole, et al,, Oesign and Installation Manual for Thermal Energy

Storage (Argonne, Ill.: Argonne National Laboratory, AN L-79-15, 2d cd.,

January 1960)

studied the most and is closest to being ready for

commercial use, although even these systems require more research and design work.

The component costs of a thermal energy storage system will include the cost of the storage

medium itself, the containment facility that

houses the medium, and the maintenance required to keep the storage system in working

order. Other costs that accrue to sensible-heat

systems using water include the cost of additives

to inhibit corrosion or prevent freezing, which

can be significant. Although costs are uncertain,

developers have estimated storage costs as a function of storage capacity for several low- and hightemperature thermal storage systems (see figs. 42

and 43).

Figure 42.— Low-Temperature Thermal Storage

Cost per KWht v. Storage Capacity

50

20

10

NOTE: The storage units would lose only about 5 percent of the energy stored

in the interval indicated. This cost is based on precast concrete and

coated steel, and excludes 25 percent O&P.

SOURCE: Application of Solar Technology to Today’s Energy Needs, Volumes I

and II (Washington, DC.: U.S. Congress, Office of Technology

Assessment, 1976).
Ch. 4—Characterization of the Technologies for Cogeneration ● 161

Figure 43.—High.Temperature Thermal Storage

Cost per kWht v. Storage Capacity

200

100

50

1.00

Storage capacity (kWht)

NOTE The storage units would lose only about 5 percent of the energy stored

in the interval indicated

SOURCE. App//cat/on of Solar Techrrology to Today’s Energy Needs, Volumes 1

and // (Washington, D C.: U.S Congress, Office of Technology

Assessment, 1978)

Some general factors affecting efficiency, or

the percentage of thermal energy recovered from

storage, are the supply temperature range (the

ratio of the input temperature to the storage

material temperature), the specific heat of the

storage medium, and the insulating properties of

the storage container. In general, the overall efficiency (energy in/energy out) declines as the input temperature increases.

Little special maintenance should be required

for thermal storage tanks because they contain

no moving parts. However, it is necessary to

check the tanks periodically for corrosion, and

the effects of normal weathering may necessitate

repainting or repair of the tank,

Electric Storage

Storage of electricity is an alternative means of

matching generating capacity output with user

demand. It may be particularly advantageous in

conjunction with intermittent sources of electricity, including wind and solar generators as well

as some cogenerators.

The primary methods of storing electric energy

are:

●

●

●

●

●

pumped storage, in which electricity is used

to pump water to a higher elevation during

periods of low electricity demand, and then

the water is released to the lower elevation

to drive a turbine during times of peak

demand;

compressed air storage, in which electricity

is used to compress air during low demand

periods, and then the air is heated and expanded through a combustion turbine to

generate electricity at peak demand;

electrochemical storage, which (as with

chemical thermal energy storage) uses reversible electrochemical reactions to store

electric energy (e.g., in batteries);

mechanical energy storage, which uses flywheels brought up to speed by electric

motors to store kinetic energy for subsequent

controlled release to generate electricity; and

thermal storage, in which electricity is converted to heat and stored in hot solid, liquid,

or gaseous materials (as described above) for

subsequent controlled release to generate

elect ricity.

The most common form of electric energy storage for dispersed energy systems (such as cogenerators) would be battery storage. * However, the

electric energy must be introduced and withdrawn from batteries as direct current, and thus

inverters must be included in any battery system

that receives and produces alternating current.

Within large bounds, the cost of batteries per unit

of storage capacity is independent of the size of

the system because most batteries consist of a

*Battery storage of electricity IS discussed in detail In increased

Automobile Fuel Efficiency and Synthetic Fuels: Alternatives for

Reducing Oil Imports (OTA-E-185, September 1982).
162 ● Industrial and Commercial Cogeneration

large number of individual reacting cells. Larger

systems may benefit from some economies of

scale because of savings due to more efficient

packing, lower building costs, and possibly lower

costs of power conditioning (see discussion of interconnection), but a separate analysis on this

point must be performed for each type of battery. It is likely that there will bean optimum size

for each device.

Lead-acid batteries are the only devices currently mass produced for storing large amounts of

electric energy using electrochemical reactions.

Systems as large as 5,000 kWh currently are used

in diesel submarines. However, contemporary

lead-acid battery designs have a relatively low

storage capacity per unit weight (due largely to

the amount of lead used), and batteries now on

the market that can be discharged deeply often

enough for onsite or utility storage applications

are too expensive for economic use in electricity generation. Extensive work is being done to

determine whether it is possible to develop batteries suitable for use in utility systems, including

work on advanced lead-acid battery designs and

on several types of advanced batteries that may

be less expensive than lead-acid batteries in the

long term.

Advanced battery types include nickel-iron,

nickel-zinc, zinc-chlorine, sodium-sulfur, and

lithium-metal sulfides. Operating and cost characteristics as well as expected availability data are

given in table 29 for several battery types. A comparison of technical and cost characteristics for

several electric storage systems, including thermally based electric storage is given in table 30.

Table 29.-Cost and Performance Characteristics of Advanced Batteries

Estimated availability

Operating Energy density Power density Estimated cost (year) (prototypes

temperature (watthours (watts per Estimated (dollars per or early

Battery type (degrees Celsius) per kilogram) kilogram) cycle life kilowatthour) commercial models)

Lead-acid

Utility design . . . . . . Ambient — — 2,000 80 1984

Vehicle design

(improved). . . . . . . Ambient 40 70 > 1 ,000” 70 1982

Nickel-iron . . . . . . . . . . Ambient 55 100 >2,000 (?) 100 1983

Nickel-zinc . . . . . . . . . . Ambient 75 120 800 (?) 100 1982

Zinc-chlorine

Utility design . . . . . . 30-50 — 2,000 (?) 50 1984

Vehicle design . . . . . 30-50 90 90 > 1,000 (?) 75 1985

Sodium-suifur

Utility design . . . . . . 300-350 — — > 2,000 50 1986

Vehicle design . . . . . 300-350 90 100 > 1,000 1985

Lithium-iron sulfide. . . 400-450 100 >100 1,000 (?) 80 1985

NOTE: 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 electricpower 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 chief

criteria 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.) Both

the 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.
Ch. 4—Characterization of the Technologies for Cogeneration ● 163

Table 30.—Expected Technical and Cost Characteristics of Selected Electrical Energy Storage Systems

Hydro pumped Thermal Lead-acid

Characteristics storage Compressed air Steam Oil batteries Advanced batteries

Commercial availability . . . Present Present Before 1985 Before 1985 Before 1985 1985-2000

Economic plant size

(MWh or MW) . . . . . . . . . . 200-2,000 200-2,000 50-200 50-200 20-50 20-50

M W M W M W Mw MWh MWh

Power related costsa ($/kW) 90-160 100-210 150-250 152-250 70-80 60-70

Storage related costsa

($/kWh) . . . . . . . . . . . . . . . 2-12 4-30 30-70 10-15 65-110 20-60

Expected life (years) . . . . . . 50 20-25 25-30 25-30 5-10 10-20

Efficiency b (percent) . . . . . . 70-75 —c 65-75 65-75 60-75 70-80

Construction Ieadtime

(years) . . . . . . . . . . . . . . . . 8-12 3-12 5-12 d

5-12 d2-3 2-3

aConstant 1975 dollars, does not include cost of money during construction.

bElectric energy out to electric energy in, In percent

cHeat 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 HEATING

District heating is the use of one or more centralized sources of heat to supply thermal energy

to a group of buildings through a piping network.

A district heating system could provide space

heating and domestic water heating, and in some

cases space cooling, to residential and commercial customers, or it could provide thermal energy

for industrial processes. A district heating system

is not limited to any particular type of heat source,

but could use conventional boilers, cogenerators,

industrial or utility waste heat, or municipal incinerators with heat recovery equipment. District

heating systems generally are thought of as large

citywide systems—and thus, in a sense, centralized power production—but they also can be

smaller systems suitable for industrial or commercial parks, college campuses, and military bases.

This section will summarize the advantages and

disadvantages of district heating based on cogenerators; a more complete discussion of district

heating can be found in the OTA assessment, The

Envgy Efficiency of Buildings in Cities.

A district heating system comprises three major

components, as shown in figure 44: the thermal

production plants that provide heat to the system;

the underground transmission/distribution system, which conveys thermal energy (in the form

of hot water or steam) from the thermal production plants to customers; and the in-building

equipment—typically a heat exchanger that forms

the connection between the system distribution

network and the remainder of each in-building

heating and cooling system.

Proponents of district heating systems for the

United States cite several potential advantages of

such systems, including the improved fuel utilization efficiency of cogeneration compared to conventional steam-electric generating stations (as

described above); reduced heating costs (through

the use of currently discarded heat and increased

equipment efficiency) relative to conventional

heating systems; increased certainty of fuel supply, through reduced consumption of oil and
164 ● Industrial and Commercial Cogeneration

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 to

coal or waste fuels; reduced fire hazards in buildings, through the substitution of a heat exchanger

for a furnace, a boiler, or electric resistance

heaters; reduced land requirements for sanitary

landfills if resource recovery facilities, such as heat

recovery incinerators, are used in district heating

systems; and increased employment and revitalization of urban areas.

However, district heating also may have a

number of disadvantages. These include a very

high capital cost, due mainly to the transmission/

distribution piping. Financing is crucial to the economic viability of district heating systems. If the

district heating system burns a high-grade fossil

fuel (natural gas or oil), the increase in fuel use

efficiency and the cost advantage to the consumer (compared to individual heating units) are

diminished by the high capital costs and thermal

losses in piping. Thus, a district heating system

will have a clear benefit only if it can utilize lower

price, relatively abundant fuels such as coal and

municipal solid waste that cannot be burned directly in individual heating units. In addition, the

installation and maintenance of district heating

systems, including the time required for the piping, can be drawn out and disruptive. During

construction, commercial establishments may

lose business and traffic may have to be rerouted.

Furthermore, system maintenance sometimes will

require reexcavation of the pipes, but cannot

always be performed during periods of low heat

demand (summer), since a break in the system

during the winter could prevent heat from reaching customers who do not have backup heating

systems. Finally, district heating systems have

limited applicability, and some very specific conditions must be met for viability, including a high

connection rate and careful design and siting.

These latter points are discussed more completely

in The Energy Efficiency of Buildings in Cities.

District heating is not a new idea, but a technically proven concept with no breakthroughs or

discoveries needed for implementation. Over 40

utility-run steam district heating systems in the

United States go back as many as 80 years, while

many smaller steam systems serve university campuses, shopping centers, industrial parks, military

bases, or industrial plants located adjacent to

power stations. A high proportion of the heat in
Ch. 4—Characterization of the Technologies for Cogeneration ● 765

Northern Europe is supplied by hot water district

heating. However, U.S. city-scale district heating

systems owned by utilities have, up until now,

enjoyed little success when compared to European systems, primarily because European systems use hot water instead of steam. Steam

district heating systems are only justified for small

areas with very high thermal load densities, preferably with connections to industrial users. Hot

water systems are preferred for commercial/residential space and water heating because thermal

extraction from steam turbine cogenerators (the

most common type used in district heating systems) should be done at relatively low temperatures to reduce losses in electric generating

capacity (see discussion of steam turbine efficiency, above) and heat losses during transmission

and distribution.

The potential contribution of cogeneration district heating could be significant, but its actual

CHAPTER 4

1. American Public Power Association, Cogeneration

and Small Power Production, Guidelines (Washington, 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/PE

03871-01, November 1979).

3. Bawn, William E., Jr., and Guerrero, J. V., Utility

Concerns About Interconnected Small Energy Systems, Technical Memorandum (Golden, Colo.:

Rocky Flats Wind Systems Program, Rockwell international Corp., November 1980).

4. Blenkle, Gerard L., Consolidated Edison Co. of

New York, testimony before New York State Public Service Commission, case No. 27574.

5. Bos, Peter G., and Williams, James H. “Cogeneration’s Future in the Chemical Process Industries

(CPI),” Chemical Engineering, Feb. 26, 1979, pp.

104-110.

6. Bullard, Clark, University of Illinois, private communication to OTA, October and November

1981.

7. California Energy Commission, Commercial

Status: Electrical Generation and Nongeneration

use will be strongly influenced by a variety of

technical, institutional, and economic factors. Its

feasibility is extremely site- and region-specific.

Such factors as climate, energy density, fuel type,

fuel availability, present and future fuel cost, age

and type of heating equipment in existing buildings, and type of existing electric generating

capacity can influence the viability of district

heating. In addition, analyses of district heating

systems are extremely sensitive to interest rates,

tax provisions, utility rate structures, environmental regulations, local building and electrical codes,

and labor regulations. Promotion of district heating may require streamlining of permit procedures, additional tax credits, low cost loans, resolution of conflicts with environmental regulations,

and favorable treatment with respect to fuel allocations and curtailments.

8.

9.

10.

11.

12.

Technologies (Sacramento, Calif.: California

Energy Commission, P102-8O-OO4, April 1980).

California Public Utilities Commission, “Standards

for Operating Reliability,” ch. 14 in Final Staff

Report on Cogeneration and Small Power Production Pricing Standards, Order Instituting Rulemaking No. 2 (San Francisco: California Public Utilities

Commission, January 1981).

Cantus, H. Hollister, United Technologies Corp.,

personal communication to OTA, Dec. 2, 1980.

Chalmers, Steve, “Solar Rankine Cooling and

Cogeneration Installations and Solar Photovoltaic

Cogeneration System,” paper presented at American Public Power Association Engineering and

Operations Workshop in New Orleans, La., Mar.

19, 1981,

Cole, Roger L., et al., Design and Installation

Manual for Thermal Energy Storage (Argonne, Ill.:

Argonne National Laboratory, ANL-79-15, 2d cd.,

January 1980).

Cummings, A. B., and Morris, J. A., Technical Supplement to the American Public Power Association Report on Cogeneration and Small Power Production (Phoenix, Ariz.: Salt River Project, March

1981 ).
166 ● Industrial and Commercial Cogeneration

13. Curtice, David, et al., Study of Dispersed Small

Wind Systems /interconnected With a Utility Distribution System, Interim Report (Palo Alto, Calif.:

Systems Control, Inc., RFP-3093/94445/3533/80/7

UC-60, March 1980).

14. Curtice, David, and Patton, James, Operation of

Small 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 Load

Shapes and Energy Storage (Palo Alto, Cal if.: Electric Power Research Institute, EPRI EA-970, March

1979).

17. DOW Chemical Co., et al., Energy Industrial Center Study (Washington, D. C.: National Science

Foundation, June, 1975).

18. Edison Electric Institute, Cogeneration—Concepts

and Systems (Washington, D. C.: Edison Electric

Institute, 07-80-06, 1980).

19. “Electric Power Generation,” McGraw-Hi// Yearbook of Science and Technology (New York:

McGraw-Hill Book Co., 1980).

20. Electric Power Research Institute and Jet Propulsion Laboratory, Interim Working Guidelines and

21.

22.

23.

24.

25.

26.

27.

Discussion Concerning the Interface of Small Dispersed Photovoltaic Power Producers With Electric Utility Systems (Palo Alto, Calif.: Electric Power

Research Institute and Jet Propulsion Laboratory,

draft, August 1981).

Fagenbaum, Joel, “Cogeneration: An Energy

Saver,” IEEE Spectrum, August 1980, pp. 30-34.

Geller, Howard S., The /interconnection of Cogenerators and Small Power Producers to a Utility System (Washington, D. C.: Office of the People’s

Counsel, February 1982).

General Electric Co., Cogeneration Technology

Alternatives 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/0031-80/l-6, May 1980).

Griffin, Clayton, Georgia Power Corp., private

communication to OTA, September 1981.

Hassan, M., and Klein, J., Distributed Photovoltaic

Systems: Utility Interface Issues and Their Present

Status (Washington, D. C.: U.S. Department of

Energy, DOE/ET-20356-3, September 1981).

ICF, Inc., A Technical and Economic Evaluation

of Dispersed Electric Generation Technologies,

contractor report to OTA, October 1980.

Institute of Gas Technology, “Phosphoric Acid

Fuel Cells,” ch. 3 in Handbook of Fuel Cc// Per28.

29,

30.

31.

32.

33.

34.

35.

36.

37.

38.

39.

40.

41.

42.

43.

44.
45

46

47

48

Production Facility Effects on the Electric Power

System,” paper presented at Federal Energy Regulatory Commission conference on Cogeneration

and Small Power Production Rules, June 1980.

Ross, Marc H., and Williams, Robert H., “Industrial Cogeneration: Making Electricity With Half the

Fuel,” ch. 10 in Our Energy: Regaining Control

(New York: McGraw-Hill Book Co., 1981).

Salt River Project, Management Proposal Regarding Small Power Production and Cogeneration

Facilities (Phoenix, Ariz.: Salt River Project, December 1980).

Solar Turbines, International., Alternate Fuels for

Gas Turbines (San Diego: Solar Turbines International, 79 177A, 1979).

Solar Turbines International, Turbomachinery

Systems for Low Heating Value Gas Fuels (San

Diego: Solar Turbines International, 80197, 1980).

49. Southern California Edison Co., Guidelines for

50

51

Operating, Metering, Protective Relaying for Cogenerators and Small Power Producers (Rosemead, Cal if.: Southern California Edison Co., June

1981 ).

Stambler, Irwin, “New Breed of Combined Cycle

Plants—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 Requirements of Sections 201 and210 of PURPA for Cogeneration and Small Power Production (Washington, D. C.: National Rural Electric Cooperative

Association, March 1981).

Thermo Electron Corp., Analysis of Cogeneration

Systems 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.

62.

63.

64.

Thermo Electron Corp., Venture Analysis case

Study–Steam Rankine Recovery Cycle Producing

Electric Power From Waste Heat (Waltham, Mass.:

Thermo Electron Corp., TE4231 -117-78, December 1978).

United Technologies Corp., Cogeneration

Technology Alternative Study (CTAS)– Volumes

/-V/ (Cleveland, Ohio: National Aeronautics and

Space Administration, Lewis Research Center, and

Washington, D. C.: U.S. Department of Energy,

DOE/NASA/0030-80/l-6, January 1980),

U.S. Bureau of the Census, Statistic/ Abstract of

the United States 1981 (Washington, D. C.: U.S.

Government Printing Office, 1981).

Whittaker, George, Russell Electric, private communication 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, private

communication to OTA, October 1981.

Williams, Robert H., Princeton University, “Biomass Cogeneration as a Major Option in the

Swedish Context,” draft report, October 1982.

Wilraker, V. F., et al., Photovoltaic Utility/Customer Interface Study (Albuquerque, N. Mex.:

Sandia National Laboratory, SAND-80-7061, December 1980),

Zastrow, Orville, Report on Study of Problems

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Association, 1980).
Chapter 5

Industrial, Commercial, and

Rural Cogeneration Opportunities
Page

Industrial Cogeneration . . . . . . . . . . . . . . . . . . . 171

Industrial Cogeneration Technologies and

Applications . . . . . . . . . . . . . . . . . . . . . . . . 171

Potential for Industrial Cogeneration . . . . . . 178

Market Penetration Estimates . . . . . . . . . . . . 184

Commercial Cogeneration . . . . . . . . . . . . . . . . 189

Previous Studies of Commercial

Cogeneration. . . . . . . . . . . . . . . . . . . . . . . . 189

Critical Assumptions and Limits of the

DELTA Model . . . . . . . . . . . . . . . . . . . . . . . 191

Commercial Cogeneration Opportunities . . . 198

Rural Cogeneration . . . . . . . . . . . . . . . . . . . . . . 210

Potential Applications . . . . . . . . . . . . . . . . . . 211

Fuel Savings . . . . . . . . . . . . . . . . . . . . . . . . . . 213

Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 215

Chapter 5 References . . . . . . . . . . . . . . . . . . . . 216

Tables

Table No. Page

31.Fuel Utilization Characteristics of

32

33

34

35

Cogeneration Systems . . . . . . . . . . . . . . . . . 172

Cogeneration Projects by Region . . . . . . . . 179

Existing Industrial Cogeneration by

SIC Code . . . . . . . . . . . . . . . . . . . . . . . . . . . 179

Sample Industrial Electric Rates by State.. 182

Early Estimates of the Potential for

industrial Cogeneration. . . . . . . . . . . . . . . . 185

36. Range of Utility Buyback Rates Analyzed

by RPA. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 187

37. Typical Days Used in the DELTA Model . . 192

38. Fuel Prices . . . . . . . . . . . . . . . . . . . . . . . . . . 196

39. Technology Characteristics . . . . . . . . . . . . . 197

40. Sample Utility Configurations . . . . . . . . . . . 198

41. Description of Scenarios Used . . . . . . . . . . 199

42. New Capacity installed for Coal-Limited

Scenarios . . . . . . . . . . . . . . . . . . . . . . . . . . . 201

43. Capacity Factors for Baseload and

Cogeneration Plants . . . . . . . . . . . . . . . . . . 202

44,

45.

46.

47.

Page

Base-Case Standard Scenario Fuel Use,

by Generation Type and Year . . . . . . . . . . 206

Comparison of Fuel Use for Coal-Limited

Scenarios . . . . . . . . . . . . . . . . . . . . . . . . . . . 209

Distribution of Waste Heat From a

Supercharged Diesel Engine . . . . . . . . . . . . 210

Model Community Gasification/Diesel

Electric Generation Energy Cost

Estimate . . . . . . . . . . . . . . . . . . . . . . . . . . . . 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 the

Cogeneration System . . . . . . . . . . . . . . . . . 173

Celanese Chemical Co./Southwestern

Public Service Co.—Schematic of the

Cogeneration System . . . . . . . . . . . . . . . . . 173

Gulf States Utility Co.-Schematic of the

Cogeneration System . . . . . . . . . . . . . . . . . 174

Union Carbide Corp.—Schematic of the

Cogeneration System . . . . . . . . . . . . . . . . . 174

Holly Sugar Corp. –Schematic of the

Cogeneration System . . . . . . . . . . . . . . . . . 175

Riverside Cement Co.–Schematic of the

Cogeneration System . . . . . . . . . . . . . . . . . 175

Cogeneration Potential at California

State Facilities . . . . . . . . . . . . . . . . . . . . . . . 191

Comparison of EIectric Demand for

Three Types of Days.... . . . . . . . . . . . . . . 193

1990 Heating Demands for Scenario 1 .. 194

1990 Cooling Demands . . . . . . . . . . . . . . . 195

Electrical Capacity Additions 1990-2000 . . 200

Thermal Supply and Demand for Winter

Peak Day . . . . . . . . . . . . . . . . . . . . . . . . . . . 203

Electricity Supply for Winter Peak Day . . . 203

Fuel Used in 1990 and 2000 for

Coal-Limited Scenarios . . . . . . . . . . . . . . . . 208

EthanoI Cogeneration With Diesel Engine

Waste Heat Recovery . . . . . . . . . . . . . . . . . 212

Anaerobic Digester Svstem. . . . . . . . . . . . . 215 “ ,
Chapter 5

Industrial, Commercial, and

Rural Cogeneration Opportunities

INDUSTRIAL COGENERATION

Large amounts of fuel are used to produce thermal energy for U.S. industries and this energy

represents a potential for fuel savings through

cogeneration. Industrial cogeneration is firmly

established as an energy supply option in the

United States, with a total installed capacity of

about 9,000 to 15,000 megawatts (MW), or about

3 percent of the total U.S. electricity generating

capacity (1 2). Industrial cogeneration currently

saves at least 0.5 Quad of fuel each year.

The onsite production of electricity in industry

(not necessarily cogeneration) has declined

steadily throughout the 20th century. This decline

was the result of a number of economic and institutional considerations that made it more advantageous for industries to buy electricity from

utilities than to generate it themselves. At the

same time, however, the technical potential for

cogeneration (the number of industrial sites

where the demand for thermal energy is sufficient

to justify a cogeneration system) has been growing, and today may be as high as 200 gigawatts

(GW) of capacity (equal to about 33 percent of

total U.S. electricity generating capacity; see

below). But, just as economic and institutional

issues were responsible for the decline of onsite

generation during the 20th century, these issues,

rather than technical constraints, mean that the

market potential (the number of sites at which

investment in cogeneration will be sufficiently attractive) is much lower than the technical potential–perhaps 40 to 100 GW by 2000.

Industrial cogeneration systems may use any

of the possible technology and fuel combinations

described in chapter 4. These systems generally

are smaller than baseload utility powerplants, but

still vary considerably in size. Examples of proposed cogeneration units now under consideration illustrate this range: A 125-kW wood-fired

unit being built in Pennsylvania to burn the scraps

from a furniture company plant; a 5.8-MW combustion turbine system being built to serve a boxboard company on the west coast; a 60-MW biomass- and coal-fired system proposed for a puIp

and paper mill in northern Mississippi; and a

140-MW coal-burning unit proposed by a major

oil company to serve a complex of refineries and

chemical plants on the gulf coast of Louisiana.

This section will describe the industrial cogeneration technologies and applications, discuss the

criteria for implementing an industrial cogeneration system, and review estimates of the market

potential for industrial cogeneration.

Industrial Cogeneration Technologies

and Applications

The cogeneration systems in place today primarily use steam turbine technology in a topping

cycle. Steam is raised in a high-pressure boiler

and then piped through a turbine to generate

electricity before heat is extracted for the industrial process (see ch. 4). The thermal output

of the turbine generally ranges from less than 50

to over 1,000 psig, which is appropriate for many

types of industrial steam processes. The steam turbine topping cycle is extremely versatile, in that

it can use any fuel that can be burned in a boiler;

oil, gas, coal, and biomass are routinely used. But

when the steam turbine technology is used for

cogeneration, only 5 to 15 percent of the fuel is

turned into electricity. Thus, these cogenerators

usually are sized to fit an industry’s steam load,

and they produce less electricity than other cogeneration technologies.

The measure of the ability of cogeneration technologies to produce electricity is the ratio of electrical output (measured in kWh) to steam output

(measured in million Btu), or the electricity-tosteam (E/S) ratio. A steam turbine cogenerator will

produce 30 to 75 kWh/MMBtu, For some industries, this is only enough electricity to satisfy onsite needs, but, in others a modest amount may

be available for export offsite as well. Higher E/S

171
172 . Industrial and Commercial Cogeneration

ratio technologies that have been proven in industrial uses are combustion turbines, diesels,

and combined cycles. The combustion turbine

can generate two to seven times as much electricity with a given quantity of fuel as the steam

turbine, and the diesel five to twenty times as

much. Combined-cycle systems perform in a

range between combustion turbines and diesels.

Typical E/S ratios for these technologies are given

in table 31 (see also ch. 4). Shifts in future cogeneration projects to these higher E/S systems

would increase the amount of electricity that

could be provided to the grid, and would save

more fuel than with the use of lower E/S technologies.

Fuel savings is one important advantage of

cogeneration. All of the proven cogeneration

technologies use about 50 to 60 percent as much

fuel to generate a kilowatt-hour of electricity

(beyond the fuel otherwise needed to produce

process steam) as is required by a conventional

steam generating station. Whereas a central station powerplant requires 10,000 to 11,000 Btu/

kwh, the proven cogeneration systems require

only about 4,500 to 7,500 Btu/kWh (see table 31).

There is no particular fuel savings in the steam

production part of the cogeneration process; raising steam by cogeneration usually is allocated the

same amount of fuel as required by a conventional boiler. Therefore, overall fuel savings are

roughly proportional to the total electricity production achievable with each technology.

However, while the higher E/S technologies

produce more electricity and save more fuel than

the standard steam turbines, their fuel versatility is more limited. Higher E/S systems can only

Table 31.—Fuel Utilization Characteristics of

Cogeneration Systems

Heat ratea

Second law E/S ratio

(Btu/kWh) efflciencyb (kWh/MhfBtu)

Steam turbine . . . . . . . . . 4,500-6,0(N) 0.40 (0.32) 30-75

Combustion turbine . . . . 5,500-6,5fxl 0.47 (0.34) 140-225

Combined cycle . . . . . . . 5,000-6,000 0.49 (0.35) 175-320

Diesel . . . . . . . . . . . . . . . . 6,000-7,500 0.46 (0.35) 350-700

The fuel required to generate elactrklty, In excess of that required for process

steam production alone, assuming a boiler efficiency of 88 percent for process

steam production.

%he second law efficiency for separate process steam and central station electricity generation Is shown In parentheses (see ch. 4).

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

use liquid or gaseous fuels of uniform composition and high purity, or turbine parts or engine

parts may be corroded or eroded. Although there

is some experimental work with coal and coalderived fuels for use in high E/S cogeneration

technologies, the only proven cogeneration technology using coal today is the steam turbine.

Some of the technologies under development

that could use coal in industrial applications are

discussed below.

Systems Design

The characteristics of presently employed systems vary enormously. Rather than try to generalize the system configurations that might be used

in different industries, six examples of successfully

operating cogeneration plants are described briefly below.

A pulp and paper industry cogeneration

system at the Potlatch Corp. plant in Lewiston,

Idaho, burns various woodwastes and the “black

liquor” from the first stage of the pulping operation, plus natural gas. This plant began to cogenerate in 1951, when the company installed a

10-MW steam turbine, which was supplemented

by another 10 MW of capacity in 1971. The cogeneration system produces steam at both 170

and 70 psig, plus 23 percent of the plant’s electrical needs. The system generates less than’ the

electric load needed onsite because of the extremely low retail electricity rates and purchase

power rates in the region (see tables 19 and 34),

but will be upgraded in the 1980’s with an additional 30 MW of capacity, at a cost of $89 million

(1980 dollars), to supply almost all the onsite demand. The system is extremely reliable, operating

24 hours per day 360 days per year, giving a system availability of over 90 percent. Electrical efficiency (fraction of fuel Btu converted to electricity) is 64 percent, and the maintenance cost

is 3 to 4 milIs/kWh (29). A schematic of the cogeneration system is shown in figure 45.

An example of a chemicai industry cogeneration system, that is sized to export electricity to

the grid, is the system installed by the Celanese

Chemical Co. at its Pampa, Tex., plant in 1979.

The system burns pulverized low-sulfur Wyoming

coal in two large high-pressure boilers, each
Ch. 5—industrial, Commercial, and Rural Cogeneration Opportunities ● 173

Figure 46.—Celanese Chemical Co./Southwestern

Public 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 that

produces ethyl lead for increasing gasoline octane. The system (Louisiana Station #l at Baton

Rouge, La.) was built by the Gulf States Utility

Co. in 193o and upgraded several times over the

decades to a present capacity of 129 MW of electricity and 3.6 million lb/hr of steam. It has now

been- cogenerating successfully for almost half a

century with only one unscheduled outage (during an electrical storm in 1960) (29).

This cogeneration plant uses natural gas and

refinery waste gas as fuel for its boilers, which

produce both 600 and 135 psig steam for sale by

the company to its industrial customers. The overall efficiency of the system is 73 percent, and the

industrial customers consider the system extremely reliable. Exxon, the refinery owner, has a 7-year

contract for steam supply. The utility sells both

the electricity and steam from the station (sale

of the steam is unregulated), and the industrial

users provide most of the fuel and pay the operating costs (29). Figure 47 presents a diagram of

the Gulf States system.

Due to natural gas price increases, Louisiana

Station #1 may be phased out soon. Until 1979,

Gulf States had long-term gas contracts for $0.30/

MMBtu, and when these contracts expired the

price rose to $2.60/MMBtu. At the same time that

their fuel prices were increasing, energy conservation by their industrial customers substantially reduced the demand for steam, which now
174 ● Industrial and Commercial Cogeneration

Figure 47.—Gulf States Utility Co.—Schematic of

the 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 that

prevailed 2 to 3 years ago, according to Gulf

States (29).

Gulf States reports that it is not in a position

to raise the capital for a new system easily (the

most recently added increment of capacity is now

27 years old), so the present system may be

retired and a new one built by Exxon. Exxon is

planning a 150- to 180-MW coal-fired cogenerator nearby. The proposed new cogeneration

plant would produce 6 million to 8 million lb/hr

of process steam and potentially could supply

more industrial customers than the existing

system.

Another cogeneration system associated with

a chemical company in the southern part of the

country is the Texas City, Tex., plant of the Union

Carbide Corp. The Texas City cogeneration system is owned by the chemical company, which

produces a wide variety of products from alcohols

to plastics, and uses natural gas for fuel. The

system is a complex network of both steam and

combustion turbines that was started in 1941. It

produces up to 70 MW of electricity, but historically has not sold any for use offsite due to

regulatory restrictions, The peak demand for the

plant is 40 MW. Union Carbide reports that it is

satisfied with its return on investment, but that

rising natural gas prices make future cogeneration questionable, especially with combustion

turbines, Union Carbide is now concentrating on

conservation through heat recovery applications

and waste heat utilization, rather than cogeneration (29). This system is sketched in figure 48.

The operating patterns of food plants are considerably different from those of chemical or pulp

plants. An example of a food plant that only operates 4 months per year is the Holly Sugar Corp.

plant at Brawley, Cal if. The plant’s 7.5-MW steam

turbine system provides all the steam and electricity needed onsite. The company reports that

it installed the cogeneration system for economics

and reliability—there had been interruptions in

power when it drew electricity from the local

grid. Now the system is isolated from the grid and

operates to provide the electrical load required

for the plant. Holly Sugar reports that reliability

is very high (99,9 percent) for the 120 days per

year that the plant operates. The reported annual

capacity factor is expectedly low for such a plant

schedule—25 percent. This may be too low for

economic cogeneration under most circumstances, but the alternative is charges for utilitygenerated power during the summer months,

which would be seasonably high—a factor that

improves cogeneration economics (29). A schematic for the system is shown in figure 49.

Figure 48.—Union Carbide Corp.—Schematic

of the Cogeneration System

Natural gas

1 J

1,000 psig/600°F

o

I

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 the

Cogeneration System

Boilers

An example of a bottoming-cycle cogenerator

is the system at the Riverside Cement Co. plant

at Oro Grande, Calif. The plant has five waste

heat boilers to recover energy from its cement

kiln exhaust gases. These produce 100,000 lb/hr

of steam for cogeneration via steam turbines.

Because the production of steam in the waste

heat boilers varies with the production rate of the

cement kilns, the system also has two oil-fired

boilers for use when the output of the waste heat

boilers diminishes. At present, oil provides 21 percent of the energy for cogeneration. In order to

reduce its oil consumption (the cement kilns operate on coal and natural gas), the company plans

to add two additional waste heat boilers. The

company reports that the system (see fig. 50) normally operates 24 hours per day, 365 days per

year, and that there have been only two brief

unscheduled outages since 1954. Because 80 percent of the energy that is used for cogeneration

would otherwise be wasted, system efficiency calculations are not significant in this situation (see

discussion of bottoming cycles in ch. 4). The cogeneration capacity available to the local utility

is 15 MW (29).

Advanced Systems

Most of the existing cogeneration systems described above are limited to the use of clean

premium fuels such as natural gas and distillate

fuel oil, which are much more expensive than

alternative solid fuels, and which may be in short

Figure 50.— Riverside Cement Co.—Schematic

of the Cogeneration System

supply in the coming decades. The only proven

technology appropriate for a wide range of industrial sites that can use solid fuels (e.g., coal,

biomass, urban refuse) is the steam turbine topping cycle, which has limited electrical production for a given amount of steam. However, a

number of technologies now under development

offer more fuel flexibility for cogeneration than

the steam topping turbine with a conventional

boiler.

The primary problem with these emerging technologies is the difficulty in handling and storing

the solid fuel and disposing of its ash. Compared

with the ease of handling traditional liquid and

gaseous fuels, solid fuels—particularly coal—are

cost intensive and complex to use. Small, medium-sized, and perhaps even large industrial

plants would prefer to avoid the investment and

operating costs associated with burning coal.

These factors are likely to limit conventional coal

cogeneration systems to units 30 to 40 MW or

larger, according to sources surveyed by OTA.

CENTRAL GASIFIER, REMOTE

GENERATION SYSTEMS

An alternate system now under intensive

development would eliminate the need for industrial firms to handle coal on their plant sites.

Utilizing a central gasifier to serve a region, it
176 ● Industrial and Commercial Cogeneration

would be possible to provide medium-Btu gas- premium synthetic natural gas. Onsite, the ineous fuel to 50 to 100 industrial plants. Medium- dustrial plants associated with such central

Btu gas has an energy content between that of gasifiers would only have relatively compact

low-Btu power gas and synthetic natural gas (see cogeneration systems that would entail no more

ch. 4). It can be transported economically over accessory buildings and equipment than present

a 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
Ch. 5—industrial, Commercial, and Rural Cogeneration Opportunities 177

gasifier that produced medium-Btu gas (about 300

Btu per standard cubic foot) could serve a region

up to about 100 miles in radius—the distance over

which medium-Btu gas can be transported economically.

An example of the central gasifier/remote generation concept is the system proposed for central and southern Arkansas to serve as many as

35 industrial sites from a central coal gasification

facility located at the Arkansas Power& Light Co.

(AP&L) White Bluff coal-fired generating station.

The initial central gasifier module would burn

petroleum coke or Illinois #6 coal to produce approximately 120 billion Btu of gas per day. The

as-spent cost of this module, for a design and construction time of 76 months, and with commercial operation beginning in mid-1988, is estimated

at $1.8 billion. This initial module could supply

fuel for combined-cycle cogenerators that would

produce 400 to 475 MW of electricity and 1.6

million to 2 million lb/hr of steam, depending on

the conditions at each industrial site. Four central

gasifier modules of this size–producing 460

billion to 480 billion Btu per day of medium-Btu

gas–would be required to supply the 35 industrial steam users identified by AP&L as the primary

cogeneration candidates in its service area. With

the central gasifier concept, these 35 cogenerators would use 6 million lb/hr of process steam

and produce up to 1,700 MW of cogenerated

electricity. The synthetic gas would be piped as

far as 100 miles to user sites with combined-cycle

cogeneration systems (14).

The medium-Btu gas for the system would be

produced in a gasifier fed by streams of air or

oxygen and coal/water slurry, both pumped into

the system at controlled rates under pressure.

Both streams enter a reactor vessel where partial oxidation of the fuel occurs, The product gas

leaves the vessel at very high temperature, then

passes through a series of heat exchangers that

cool the gas to 400° F. Ash from the burning fuel

is separated at the exit of the gasifier and directed

into a water-quench that produces a glassy waste

product that can be used as an asphalt filler.

Because the gasifier operates above the melting

temperature of the ash, the quenched ash is inert

and the plant does not require scrubbers.

A 150-ton-per-day Texaco entrained-process

gasifier (similar to that proposed by AP&L) has

been operating for more than 2 years, producing synthesis gas for the Ruhr Chimie chemical

plant near Oberhausen, Germany. In addition,

the Tennessee Valley Authority is building a

200-ton-per-day Texaco gasifier at Muscle Shoals,

Ala., and the Electric Power Research Institute–in

conjunction with Southern California Edison

Co.–is in the final stages of planning a 1,OOO-tonper-day gasifier (the Coolwater project) that will

be used to produce 100 MW of power. None of

these projects is intended to cogenerate, but the

technology could be used to do so (4).

FLUIDIZED BED SYSTEMS

Another advanced coal technology is the

fluidized bed combustor, which can be used to

burn coal or other solid fuels, including urban

refuse, in a more compact system than a conventional coal boiler. The fluidized bed combustor

can burn coal of any quality, including that with

a high ash content, and it can operate at a temperature (1 ,500° F) only about half as high as a

conventional pulverized coal boiler. At these

lower temperatures, the sulfur dioxide formed

during combustion can be removed easily by

adding limestone to the bed, and the combustion gases may be suitable for driving a combustion turbine with minimal erosion damage, because the coal ash is softer at lower temperatures.

Two types of fluidized beds currently are being

developed–those that work at atmospheric pressure and those that work at considerably higher

pressures (see ch. 4).

At present, fluidized bed systems are used to

fire boilers, and thus can be readily used for

cogeneration with conventional steam turbines.

Fluidized bed systems incorporating combustion

turbines, which have higher E/S ratios, are in an

earlier stage of development and are just approaching commercial status. But, combustion

turbines require a high-temperature gas at a

pressure considerably above atmospheric pressure, so the output of an atmospheric fluidized

bed combustor cannot be used as the input to

the turbine. Instead, the fluidized bed output can

be used in conjunction with air heater tubes for
178 ● Industrial and Commercial Cogeneration

heat recovery in the fluidized bed, and the air,

delivered from the turbine compressor to be

heated in these tubes, can be used to indirectly

fire a combustion turbine (either open or closed

cycle).

The Curtiss-Wright Corp. in Woodbridge,

N. J., is offering a prototype indirectly fired system

on a semicommercial basis, sized to produce 2

to 10 MW of electricity and 25,000 to 150,000

lb/hr of steam. A spokesman for the company

says that 20 MW is probably the maximum feasible size for such a system using an atmospheric

bed combustor, the bed size being the limiting

factor. Pressurized bed systems could be larger,

however. The crucial factor in this technology,

according to Curtiss-Wright, is the choice of alloy

for the heater tubes. These tubes pass through

the bed itself, operate at temperatures up to

2,000° F, and can be subject to corrosion, oxidation, and sulfurization. After “working the

bugs out” of the first few demonstration units,

Curtiss-Wright plans to offer the system on a commercial basis (4).

Pressurized fluidized bed combustors have output gases that exit at high enough pressures that

these gases may be used directly to drive a turbine. These systems are also just approaching

commercial status. The German Babcock Co. is

planning a demonstration of a medium-sized

system of this type in Great Britain. The major

difficulty in the successful demonstration of such

systems is perfecting the technology for cleaning

the fluidized bed output gas so that it does not

erode the turbine blades and shorten the lifetime

of the system (4).

Shell Oil Co. recently decided to build a coalfired fluidized bed cogeneration system near Rotterdam, Netherlands, a relatively small unit that

will produce 110,000 lb/hr of steam. A considerably larger fluidized bed project is being

undertaken by the American Electric Power Co.

(AEP) at Brilliant, Ohio. The AEP system, being

built in conjunction with Babcock& Wilcox, Ltd.

of Great Britain and Stal-Laval Turbin AB of

Sweden, uses a pressurized fluidized bed to

operate a combustion turbine topping cycle in

conjunction with an existing steam turbine. The

capacity of the combined system (which will not

cogenerate in this instance but which would be

appropriate for cogeneration applications) will be

170 MW (4).

Other technologies also are receiving attention

for use with coal. The Thermo Electron Corp. has

tested the performance of a two-cycle marine

diesel engine fired with a coal/water slurry. The

engine, which is a low-speed tanker motor (see

ch. 4), could achieve in principle 40 percent efficiency in generating electricity. Coal also can

be used to fuel externally fired engines such as

the Stirling-cycle engine. N.V. Philips, of Einhoven, Netherlands, has initiated work in applying fluidized bed coal systems to use with Stirling engines.

Potential for Industrial Cogeneration

Cogeneration’s market potential depends on

a wide range of technical, economic, and institutional considerations, including a plant’s steam

demand and electric needs, the relative cost of

cogenerated power, the fuel used and its cost,

tax treatment, rates for utility purchases of cogenerated electricity, and perceived risks such as

regulatory uncertainty. The criteria for investment

in an industrial cogeneration system is discussed

below, including a description of the industrial

sectors where cogeneration is likely to be attractive, and a brief review of the industrial cogeneration projections in the literature.

Appropriate Industries

A summary of cogeneration projects by region

in the United States is given in table 32. The 371

projects in this table are those that are positively

identified as cogeneration systems in a recent Department of Energy (DOE) survey (12). A breakdown by industry type is given in table 33. An

additional 98 projects-representing at least 3,300

MW of capacity–have been proposed, are under

construction, or are being added to existing

cogeneration units.

The pulp and paper industry has, for some

time, been a leader in cogeneration due to the

large amounts of burnable process wastes that

can supply energy needed for plant requirements.

Integrated pulp and paper plants find cogenera-
Ch. 5—industrial, Commercial, and Rural Cogeneration Opportunities ● 179

Table 32—Cogeneration Projects by Region

Capacityb

Regiona Number of plants (MW)

New York , . . . . . . . . . . . . . . 27 913

New York/New Jersey . . . . 23 498

Mid-Atlantic . . . . . . . . . . . . . 39 1,512

South Atlantic . . . . . . . . . . . 62 2,200

Midwest . . . . . . . . . . . . . . . . 89 3,176

Southwest . . . . . . . . . . . . . . 57 4,812

Central . . . . . . . . . . . . . . . . . 14 259

North Central. . . . . . . . . . . . 14 413

West . . . . . . . . . . . . . . . . . . . 25 629

Northwest . . . . . . . . . . . . . . 21 445

Total . . . . . . . . . . . . . . . . . 371 14,858

aStandard EIA/DOE regions.

bTotal may not agree due to rounding.

SOURCE: General Energy Associates, Industrial Cogeneration Potential.’ Targeting of Opportunltles at the Plant Site (Washington, DC.: U.S. Department of Energy, 1982).

tion particularly attractive. These plants dispose

of woodwastes (e. g., bark, scraps, forestry residues unsuitable for pulp) and processing fluids

(“black liquor”), and recover process chemicals

in furnaces that can supply about half of a plant’s

energy needs. For at least two decades, the industry has considered power production an integral part of the manufacturing process, and new

pulp and paper plants are likely candidates for

cogeneration.

The chemical industry is another major steamusing industry that has great cogeneration potential. It uses about as much steam per year as the

pulp and paper industry (1.4 Quads in 1976) and

historically has ranked third in installed cogeneration capacity. The steel industry is also a major

cogenerator, because the off-gases from the

open-hearth steel making process provide a ready

source of fuel, which is burned in boilers to make

steam for blast furnace air compressors and for

miscellaneous uses in the rest of the plant. Although the steel industry has been a major cogenerator in the past, most analysts project that

it will not build more integrated stand-alone

plants. Instead it is expected to build minimills

that run with electric arcs and have little or no

potential for cogeneration unless a market can

be found for the thermal energy. Thus, new steel

mills probably have considerably less cogeneration potential than the chemical industry. However, on the gulf coast substantial cogeneration

capacity has been proposed for existing primary

metals facilities (34)0

petroleum refining also is an industry that is,

in many ways, ideal for cogeneration. Existing

refineries could be upgraded over the next

Table 33.—Existing Industrial Cogeneration by SIC Code

Percent Capacity Percent

SIC code Number of total (MW) of total

20—Food . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 42

21 —Tobacco products . . . . . . . . . . . . . . . . . . . . . . .

22—Textile mill products. . . . . . . . . . . . . . . . . . . . . 9

23—Apparel . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0

24—Lumber and wood products. . . . . . . . . . . . . . . 19

25—Furniture and fixtures. . . . . . . . . . . . . . . . . . . . 1

26—Paper . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 136

27—Printing and publishing . . . . . . . . . . . . . . . . . . 1

28—Chemicals. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 62

29—Petroleum and coal products . . . . . . . . . . . . . 24

30—Rubber, miscellaneous plastic products . . . . 3

31—Leather . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . —

32—Stone, clay, and glass products . . . . . . . . . . . 6

33—Primary metals. . . . . . . . . . . . . . . . . . . . . . . . . . 39

34-Fabricated metal products. . . . . . . . . . . . . . . . 10

35—Machinery, except electrical . . . . . . . . . . . . . . 11

36—Electric and electronic equipment . . . . . . . . . 3

37—Transportation equipment . . . . . . . . . . . . . . . . 1

38—instruments and related products . . . . . . . . . 3

39—Miscellaneous manufacturing . . . . . . . . . . . . . —

Total. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 371

11.3 %

<1. 0

2.4

5.1

<1.0

36.7

<1.0

16.7

6.5

<1.0

—

1.6

10.5

2.7

3.0

< 1.0

< 1.0

< 1 .0

100.0

398

33

224

479

2

4,246

3,438

1,244

76

115

3,589

304

134

83

345

137

14,858

2.7

<1.0

1.5

3.2

<1 .0

28.6

<1 .0

23.1

8.4

< 1 .0—

<1. 0

24.2

2.0

1.0

1.0

<2.3

< 1 .0

100.0

SOURCE: 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 output and decrease residual oil production. A

byproduct of this upgrading would be the production of low-Btu gas that might be used in

cogeneration systems. One report estimates that

such upgrading could produce 0.5 Quad/yr of

gas, to meet about 40 percent of the refineries’

1976 process steam demand and provide 9 GW

of electricity generating capacity (34). However,

new refineries are not likely to be built in the near

future except on the Pacific coast in conjunction

with enhanced oil recovery in the Kern County

heavy oilfields.

An industry in which cogeneration and conservation are in head-to-head competition is the

cement industry. It has been identified as a candidate for bottoming-cycle cogeneration, an application in which the heat of the kiln exhaust

gas is recovered and used to produce steam for

electricity generation. But because the industry

is highly energy intensive, it has improved its efficiency substantially in recent years, reducing the

temperature of its exhaust gases from 9000 to

1,000° F to 300° to 400° F. One plant has

reported exhaust temperatures as low as 180° F

(28). In plants where conservation measures are

that effective, it probably will not be economic

to cogenerate.

Criteria for Implementation

A wide range of considerations must be taken

into account in deciding whether to invest in an

industrial cogeneration system. These include

both internal and exogenous economic factors,

fuel cost and availability, ownership and financing, 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 cogenerated

power, and a variety of perceived risks in such

an investment.

ECONOMIC CONSIDERATIONS

For any potential cogenerator, the desirability

of cogenerating depends on the price of power

from the utility plus the cost of producing thermal energy, versus the cost of cogenerating. Historically, industrial and commercial users have

paid different amounts for utility-produced

power. Compared to the case for commercial cogeneration (see below), industrial facilities typically have lower electric rates, averaging up to about

1.5cents/kWh lower than commercial and residential users (see table 34) (9). Nevertheless, in some

regions of the country, rates for utility purchases

of cogenerated electricity have reached 8.3cents/

kWh (see table 19), higher than the national average for either commercial or industrial retail electricity rates. These areas are prime targets for expanded industrial cogeneration (see discussions

of purchase power rates and simultaneous purchase and sale, below).

The current costs of cogeneration for industrial

users often are below the rates for utility purchases from industrial customers. A study for the

Federal Energy Regulatory Commission (FERC)

(28) found that the price of cogenerated electricity

ranged from 4.4 to 5.6cents/kWh (1979 dollars) for

various regions of the country, assuring the use

of steam topping and gas turbine technologies.

Diesel cogeneration was found to cost 7.2 to

7.6cents/kWh, assuming small, distillate-fired systems

operating at a relatively low capacity factor.

Larger systems using natural gas and operating

at higher capacity factors should be able to compete at the busbar with new coal plants in many

instances (34). While utility rates for purchases

of cogenerated power vary widely by region (see

table 19), the costs of cogeneration vary only 10

to 20 percent among the regions of the country,

This is a strong indication that the rates for sales

of cogenerated electricity will be important in

determining the economic viability of industrial

cogeneration over the next few years. More specifically, external economic factors, rather than

technical breakthroughs that would reduce the

intrinsic costs of cogeneration, are likely to be
182 ● Industrial and Commercial Cogeneration

Table 34.-Sample Industrial Electric Rates

by State (costs per kWh for industries using 1.5 milllon

kWh per year with a peak demand of 5 MW.

. - . . .— Alabama . . . . . . . .....3.60

Alaska . .............3.7

Arizona . ............4.4

Arkansas . ...........2.9

California . ..........5.0

Colorado . ...........3.4

Connecticut . ........5.2

Delaware . ...........5.8

District of Columbia ..3.9

Florida . .............3.1

Georgia . ............3.7

Hawaii . .............5.7

Idaho . ..............1.7

Illinois . .............4.0

Indiana. . ............3.6

Iowa . ...............3. 9

Kansas. . ............3.9

Kentucky . ...........3.0

Louisiana . ..........2.9

Maine. . .............3.6

Maryland . ...........2.7

Massachusetts. .. ....5.2

Michigan . ...........4.6

Minnesota. . .........3.0

Mississippi . .........3.9

Missouri . ...........3.8

Montana . . . . . . .....1.70

Nebraska. . . . . . .. ...2.7

Nevada . ...........4.7

New Hampshire .. ...4.8

New Jersey. . .......4.4

New Mexico . .......5.5

New York .. ........7.6

North Carolina .. ....2.9

North Dakota . ......3.5

Ohio . ..............4.1

Oklahoma . .........2.6

Oregon. . ...........1.7

Pennsylvania . ......5.1

Rhode Island . ......5.3

South Carolina .. ....3.6

South Dakota . ......3.3

Tennessee. . ........3.2

Texas . .............3.7

Utah . .............,3.1

Vermont. . ..........3.3

Virginia . ..........,5.2

Washington ., .. ...,1.1

West Virginia . .....,3.2

Wisconsin .. ........3.5

Wyoming . ..........1.5

aRates shown are calculated from typical bills for 455 cities with a totai population of 76.9 million as of Jan. 1, 1980. The State averages are population-based

averages. 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 cogeneration implementation in the 1980’s.

In most parts of the country, the rates for purchases of cogenerated electricity do not exceed

the 4.5 to 5.5cents/kWh cogeneration cost quoted

above. However, the avoided cost of many utilities 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 the

case. in regions with high avoided costs, it would

be advantageous for industrial firms to sell all their

cogenerated power to the utilities and buy back

as much power as they need at the industrial

wholesale price. The conditions for favorable

election of this option, known as simultaneous

purchase and sale (or arbitrage), are discussed

further below.

FUEL VERSATILITY

The fuel used for cogeneration varies with the

type 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 natural

gas are the most versatile fuels because they can

be used in all available cogeneration technologies

from the lowest E/S systems (steam topping turbines) to the highest (combined cycles and

diesels). However, due to the price and supply

uncertainties of oil and natural gas, over the long

term (10 years and beyond) the most attractive

cogeneration investments will use solid fuels. As

discussed previously, of the available technologies, only steam turbines presently can use such

fuels, but these systems also have relatively low

fuel savings for a given steam load, and a low E/S

ratio. With the advanced technologies described

previously, solid fuels could be used more widely

than now possible. Both the medium-Btu gasifier

and the fluidized bed systems could be used with

combustion turbines or combined cycles, producing electric power with a high E/S ratio from

coal or biomass.

OWNERSHIP AND FINANCING

ownership arrangements may be among the

principal determinants of the rate of development

of cogeneration. The issue is whether cogeneration systems will be owned by the industry that

uses the thermal energy, whether they will be

owned by the utilities that would distribute the

cogenerated electricity, or whether a third party

would invest in the cogeneration equipment.

Joint ventures and multiparty ventures mingling

these various players also are possible (see ch. 3).

Industrial ownership could be attractive if the

surplus electricity were purchased by a utility at

rates that reflect the utility’s full avoided costs.

Also ownership could assure the cogenerating industry of reliable power, which can be a strong

incentive for particular industries in some regions.

However, the capital requirements of a cogeneration system are large enough that many potential industrial cogenerators would like to have

long-term (i.e., 20-year) contracts for power sales

to the grid. Whether this can be reasonably expected under the presently applicable laws is an

important question, one that is addressed in

chapter 3 of this study.
Ch. 5—Industrial, Commercial, and Rural Cogeneration Opportunities . 183

Utility ownership has the advantage that utilities

consider power production their primary line of

business. Utility-owned cogeneration systems

could be included in the rate base, thus allowing the utility to earn a return on the systems.

Utility ownership also provides a straightforward

means by which utilities could maintain dispatching control over the electric power entering the

grid, providing them with assurance that this new

form of generating capacity would preserve system stability (see the discussion of interconnection in ch. 4). Furthermore, cogeneration’s relatively small unit size can decrease the cost of

capital for capacity additions and can reduce the

downside risk of unanticipated changes in demand growth (see ch. 6). However, as discussed

in chapter 7, unregulated utility ownership raises

concerns about possible anticompetitive effects.

Third-party ownership is most likely to occur

in cases where new steam-producing equipment

is badly needed to cut energy costs but the industry in question cannot raise capital for a new

system. Novel cogeneration financing arrangements are emerging slowly and it is risky to make

generalizations so early in the process. In some

cases, the third party may be a separate entity

set up by the utility. In other cases, it may be a

large institutional investor wooed by the industry.

There appear to be few instances on the industrial

scene where—as happened in the development

of hydro power under the Public Utility Regulatory Policies Act of 1978 (PURPA)—a small entrepreneur identified an attractive steam load,

proposed building a new plant, served as capital

matchmaker, and then ran the facility. Third parties will want to reduce the risks of ownership

by negotiating long-term purchase power contracts with the utilities.

TAX INCENTIVES

Significant Federal tax incentives are available

to cogeneration in recognition of its fuel saving

value. These include the investment and energy

tax credits, accelerated depreciation, and safe

harbor leasing (see ch. 3). In some cases, cogeneration may also qualify for tax-exempt financing. An informal survey by OTA indicates that

these tax incentives may promote some marginal

cogeneration projects from “unattractive” to “attractive,” but tax considerations are not, in most

cases, the overriding economic issue. Industrial

power cost and reliability, PURPA avoided cost

prices, and restrictions on capital from traditional

sources are still the dominant economic issues.

On the other hand, tax considerations can have

a very strong influence on ownership and financing decisions for a cogeneration project. A key

issue in cogeneration tax treatment is whether or

not facilities are categorized as “public utility

property.” Full utility ownership is generally the

least attractive tax alternative for a cogeneration

project under either the 1978 or 1980 tax bills.

FLEXIBILITY IN LOAD EXPANSION

One of the major reasons that cogeneration

would be attractive to utilities in the short term

is its suitability for adding new capacity in small

increments that are deployable in a relatively

short time. Cogeneration capacity sizes in industrial settings range from 100 kw, miniscule

by utility standards, to over 150 MW, about half

the size of the smallest unit of baseload capacity

a large utility would consider installing. Many

utilities favor 300-MW coal units as small incremental additions for central plant capacity.

Adding Ieadtime for planning, the total time to

put a cogeneration facility in place is 3 to 6

years–much less than the 5- to 12-year period

required for utility baseload plants. As a result,

cogeneration can represent an “insurance

policy” against unanticipated changes in demand

growth-a much less costly form of insurance

than overbuilding central station capacity.

The planned cogeneration strategy of AP&L (described above) illustrates the flexibility in capacity

growth that can be attained with cogeneration.

AP&L’s proposed 1,700-MW remote gasification

system (described above) would be based on

combined-cycle units at each plant site (up to 35

sites), which would allow the utility to decouple

steam and electricity production. Thus, the utility could build a system to supply the industrial

steam load of its customers, and then turn on

electrical capacity as needed. In this way, AP&L

could gradually augment its system capacity from

zero to 1,700 MW over several years in a smoothly increasing trend (14).
184 ● Industrial and Commercial Cogeneration

PURCHASE POWER RATES

The critical economic considerations in a decision whether to invest in an industrial cogeneration system include the rates and terms for utility purchases of cogenerated power. As discussed

below, the utility buyback rates are a primary

determinant not only of the number of cogeneration systems installed, but also of the amount of

electricity they will produce. However, Federal

and State policies on this issue are in great flux

just now, and the regional variability in purchase

rates is quite high (see ch. 3). As a result, many

potential cogenerators are caught in a “squeeze”

between the regulatory uncertainty surrounding

sales of electricity to the grid and the desire to

invest during 1982 before the energy tax credit

expires.

SIMULTANEOUS PURCHASE AND SALE

The regulations implementing PURPA section

210 allow industrial cogenerators to simultaneously buy all their needed power from the utilities

(at rates that do not discriminate against them

relative to other industrial customers), while selling all their cogenerated electricity at the utility’s purchase power rate. In effect, this provision

decouples a cogenerator’s thermal and electric

energy production (see ch. 3). Utilities, which are

seeing their load growth diminish drastically as

a result of price-induced conservation, may find

this option attractive because it does not reduce

their load base. Moreover, industries generally

are less willing to project their steam or heat loads

as far into the future as utilities. Systems that allow

some decoupling of steam and electric production thus have potentially greater appeal to industry, under industry ownership. industries may

also find simultaneous purchase and sale attractive because it does not require them to pay

standby charges for electricity they would use

when the cogeneration system was shut down

for maintenance or unplanned outages.

REGULATORY UNCERTAINTY AND

PERCEIVED RISKS

At present, probably the greatest deterrent to

investment in cogeneration systems is regulatory

uncertainty. Utility rates for purchases of cogenerated power under PURPA and the FERC regulations on interconnection of cogenerators with the

grid are uncertain pending a final court ruling on

the existing regulations (see ch. 3). Other regulatory or legislative items that may affect cogeneration implementation but are in a state of flux

include: the Fuel Use Act regulations on exemptions for cogenerators; natural gas prices, the

schedule for deregulation, and its effect on incremental pricing; and the expiration of the

energy tax credit at the end of 1982.

Industrial companies also are concerned about

limited capital resources and high interest rates,

and may favor investments in process improvements that would contribute to plant efficiency

over investments in new energy systems. Companies also are hesitant to invest until the payback

periods are more firmly established, given uncertainties in fuel prices. Some companies also have

expressed concern about a lack of technical expertise in the use of solid fuels, as well as about

the possibility of using up air pollution increments

that may be needed for future plant expansions.

Market Penetration Estimates

A number of recent studies have estimated the

technical and/or market potential for cogeneration based either on the Quads of energy that

might be saved by the substitution of cogenerators for separate conventional electric and

thermal energy systems, or on the Quads of steam

and megawatts of installed capacity that could

be supplied by industrial cogeneration. The range

of estimates given in these studies is large, extending from 6 to 10 Quads of energy saved annually by 1985, and from 20 to 200 GW of installed

generating capacity by 2000. Differing assumptions about energy prices, ownership, and return

on investment, whether the cogeneration facilities

would export electricity to the utility grid, and

the types of technologies employed account for

the large range. The early projections of the

potential for industrial cogeneration are summarized in table 35.

The general methodology in each of these studies was to estimate the industrial steam load and

then quantify what portion of that load would be

technically and economically exploitable for

cogeneration. 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 steam

Study 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 20-34a

4.1 % (1975-85)

Combustion turbine 85-128

Diesel 107-209

Utility Steam turbine 34-37a

Combustion turbine 131-137

Diesel 218-249

Williams Utility Steam turbine 28 (in 2000) 20/0 (1974-2000)

Combustion turbine or

combined cycle:

Oil-fired 28

Coal w/FBC 95

Diesel 57

Total 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, then

would determine the electrical capacity achievable with such a steam load. In general, those

studies that assumed the use of only steam turbine topping cycles (sized so there was no offsite export of electricity) arrived at much lower

estimates of cogeneration electric capacity.

A DOW Chemical Co. study (6) projected 61

GW of electrical cogeneration capacity in 1985

(including existing capacity), corresponding to

about 50 percent of the projected process steam

demand for that year. The DOW study assumed

industrial ownership (with a 20-percent rate of

return) of steam turbine topping cycles installed

in plants using over 400,000 lb/hr of steam. These

cogenerators would produce the minimum

amount of electricity for a given steam load

(about 40 kWh/MMBtu) and would not export

any electricity offsite. Even with this rather conservative choice of technologies, there were instances in which the study found that more electricity would be generated than could be used

onsite, and so the estimated market potential for

cogeneration was scaled down accordingly.

A 1977 study by Resource Planning Associates

(RPA) for DOE (24) examined the potential for

cogeneration development by 1985 in six major

steam-using industries (pulp and paper, chemicals, steel, petroleum refining, food, and textiles).

RPA only considered applications larger than

5-MW electrical capacity and assumed that all of

the cogenerated electricity would be consumed

onsite. Furthermore, approximately 70 percent

of the total estimated process steam available for

cogeneration development in 1985 was eliminated as unsuitable for cogeneration, due to

technical or economic constraints, or to conservation and process improvements. As a result,

RPA found the 1985 potential in the six industries

to be 1.7 Quads of process steam output (10-GW

capacity) without Government action, and 2 to

2.6 Quads of process steam (12- to 16-GW

capacity) with Government programs such as the

energy tax credits and the more rapid depreciation now in place, or PURPA-style regulatory and

economic incentives.

A study by Thermo Electron (30) was based on

three of the most steam-intensive industries—the

chemical, pulp and paper, and petroleum refining industries—which were assumed to account

for approximately 34 percent of the total estimated 1985 industrial steam loads. This study

assumed that either industry or utilities might invest in high E/S technologies such as combustion

turbines and diesels, and found that the maximum implementation for combustion turbines—

137 GW of cogeneration capacity–occurred with

utility ownership, an investment tax credit of 25

percent (rather than the 10 percent then available), and Government financing for half the

project.
186 Industrial and Commercial Cogeneration

A 1978 study by Williams (33) assumed utility

ownership, and a mix of technologies in which

steam turbine cogenerators met 42 percent of the

steam load and higher E/S technologies the remainder. Williams assumed that fuel use for

steam generation in existing industries would increase 2 percent annually through 2000, leading

to a process steam demand of 16.1 Quads in

those industries. Williams also assumed that

about half of the total steam demand would be

associated with cogeneration having an average

E/S ratio of 140 kWh/MMBtu and producing electricity 90 percent of the time that steam is produced. Based on these assumptions, Williams estimated the total cogeneration potential in 2000

to be 208 GW, saving over 2 million barrels of

oil per day.

As noted previously, each of these studies

began by estimating the present demand for industrial process steam. These estimates include

a 1974 steam load of 7.8 Quads (Williams, based

on an Exxon analysis); a 1976 industrial steam demand of 9.7 Quads (RPA); and a 1980 estimate

of about 14 Quads (DOW). In 1981, the Solar

Energy Research Institute (SERI) attempted to

reconcile the differences among these and other

estimates of industrial steam load, and found that

the data base (disaggregated by fuel use, boiler

capacity, average and peak steam loads per site,

steam quality, steam load by industry, steam load

by State) is so inadequate that none of these

published estimates could be considered accurate. However, SERI was able to reject the

higher steam demand estimates in the literature

because they did not account accurately for fuel

use in smaller boilers in less energy-intensive industries. By reconciling differences in approach

and accounting among the lower published numbers, SERI arrived at an estimate equivalent to approximately 5.5 Quads/yr during 1976-77 (27).

In addition to overestimating the base industrial

demand for steam, the early studies of industrial

cogeneration assumed robust steam growth-on

the order of 4 percent annually. The steady progress that has been made in industrial energy conservation through the 1970’s—amounting to a

decrease in energy use per unit of industrial

value-added of approximately 2 percent per

year—makes these earlier predictions for steam

load growth highly unlikely. More recent studies

of cogeneration have projected steam growth

rates that are either lower or constitute no

growth. For instance, in 1980 SRI International

projected 1.18 percent per year (28), while

Williams now estimates zero growth in steam demand through 2000 (34), and SERI projected zero

or negative growth (27).

More recent estimates of the potential for industrial cogeneration either have assumed a

much smaller present steam base and lower thermal demand growth rates, or have devised a

methodology that does not begin with an estimate of the current steam load. However, due

to changes in the context for cogeneration since

the earlier studies were completed, these recent

studies have not necessarily projected a lower

market potential for industrial cogeneration.

These contextual changes include the PURPA

economic and regulatory incentives for gridconnected cogeneration, substantial increases in

oil and electricity prices, special energy tax

credits, and shorter depreciation periods. As a

result of these and other considerations, cogeneration is considered likely to be economically

attractive at more industrial sites than in earlier

studies (despite the lower thermal demand projections), and more likely to use technologies with

higher E/S ratios that produce more electricity.

A 1981 study by RPA (23) examined the 1990

potential for cogeneration in five industries (those

analyzed previously except for textiles), began

with a 1990 steam demand of 682 million lb/hr

(approximately 6 Quads/yr, assuming 1,000

Btu/lb and 24-hr operation). Of this base, RPA

found an expected investment in the five industries of 155 million lb/hr (1 .36 Quads) steam

production, or 20.8 GW of electric capacity,

assuming “base case” utility buyback rates (see

table 36). This would increase to 28.7 MW of installed cogeneration capacity if, as a result of utility ownership, 30 percent of the steam turbines

were replaced by combustion turbines and combined cycles. The “high buyback rates” case

would lead to an expected investment potential

of as much as 37 GW of instaIled capacity, while

the “low” case shows 14.2 GW (1.2 Quads

steam). The amount of electric capacity declines

more 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 buyback

DOE region fuel rate rate rate

1. New England . . . . . . . . Oil 4.0 5.5 7.0

2. New York/New Jersey. Oil 4.0 5.5 7.0

3. Mid-Atlantic . . . . . . . . . Oil 4.0 5.5 7.0

4. South Atlantic . . . . . . . Oil/coal 2.0 3.5 5.0

5. Midwest. . . . . . . . . . . . . Coal 2.0 3.0 4.0

6. Southwest. . . . . . . . . . . Natural gas 2.5 4.0 5.5

7. Central. . . . . . . . . . . . . . Coal 1.0 2.0 3.0

8. North Central . . . . . . . . Coal 1.0 1.5 2.5

9. West. . . . . . . . . . . . . . . . Oil 4.5 6.0 7.5

10. Northwest . . . . . . . . . . . Coal 3.5 4.5 5.5

SOURCE: 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/S

ratio to these rates (23).

In an informal update of his earlier work,

Williams (34) begun with a much lower steam

demand–4.l Quads in six industries in 1977–

but assumed that cogeneration would achieve a

higher degree of penetration of the steam base

than he had assumed earlier. Of these 4.1 Quads,

Williams assumed 1.25 Quads would be unsuitable for cogeneration (due to load fluctuations,

low steam demand, low-pressure waste heat

streams, declining demand, etc.), resulting in a

six industry market potential of 93 to 142 GW

in 2000, depending on the technology mix.

Williams estimated an additional potential of up

to 32 to 49 GW in other industrial sectors, if their

steam loads are proportional to those in the six

industries, but less if their steam loads are smaller

or more variable. Finally, Williams estimates that

new industries (e.g., thermally enhanced oil recovery) have a potential of 11 to 20 GW of installed capacity. Together, these sources have an

“economic potential” of 136 to 211 GW of cogeneration capacity in 2000. Williams considers

this economic potential to be the amount available for insuring against underdevelopment of

central station generating capacity. The actual

amount to be designated as a “prudent planning

base” for such insurance could not be determined without better disaggregated data on the

steam base, but Williams found 100 to 150 GW

to be a “conservative estimate” (34).

Williams’ approach to cogeneration as insurance against the uncertainty in future electricity

demand growth was included in the 1981 SERI

report on solar/conservation. SERI did not

estimate the total potential for industrial cogeneration because the report’s emphasis on conservation meant that projected electricity demand

growth was so low (0.13 percent annually) that

no cogeneration electrical capacity would be

needed unless the conservation targets were not

met. The study concluded that 93 GW of cogeneration in the six industries would be an adequate

insurance measure, but made no attempt to ascertain how much capacity would be economically attractive (27).

A different methodology was adopted in a 1982

analysis for DOE (12). Rather than using a gross

estimate of steam demand as the primary measure of potential, this study began by individually

analyzing the 10,000 largest U.S. industrial sites

for their cogeneration potential based on buyback rates, accelerated depreciation, heat match,

and other considerations. This analysis identified

3,131 plants in the 19 manufacturing sectors that

would have a return on investment greater than

7 percent and represent the maximum potential

of 42.8 GW of cogeneration capacity (producing 3.3 Quads of steam). Ninety-two percent of

the electric capacity and 95 percent of the steam

generated are in the five top steam-using industries. The “best” mix of technologies for these

sites was found to be 70 percent combustion turbines and 30 percent steam turbines, resulting

in the offsite export of 49 percent of the electricity

generated. If the return on investment increased

to 20 percent, the maximum potential decreases

to 20 GW. The study also estimated that an additional 48.5 GW of capacity could be installed
188 . Industrial and Commercial Cogenerafion

at new industrial sites based on U.S. Department

of Commerce industrial growth figures and

assuming that plant expansions and new plants

would have characteristics similar to those in existing plants (12).

The studies reviewed above illustrate two main

points:

1.

2.

The technical potential for cogeneration is

very large; even the lowest of these estimates

corresponds to the equivalent of 20 new

baseload central generating plants, while the

highest estimate corresponds to a generating

capacity capable of producing more than

one-sixth of the electrical power presently

used in the country.

Economic and institutional considerations

are paramount in determining how much

cogeneration will actually be installed, as illustrated by the wide sensitivity of these estimates to variations in utility purchase rates,

tax incentives, ownership, fuel prices, etc.

The underlying consensus among these studies on all matters except the likely steam load

is in fact remarkable.

While the market for cogeneration is potentially

large, the actual rate of cogeneration equipment

installation is much lower than expected a few

years ago. This trend is occurring in spite of higher

electricity prices because of the weakened financial posture of utilities, industries’ difficulty in raising capital for expansion due to unprecedentedly

high interest rates, and the unexpectedly rapid

rate of energy use reductions in industry. Longterm fuel supply uncertainties also may work

against cogeneration, or against the more attractive cogeneration options.

The effect of energy conservation in industry

is one of the key influences on future cogeneration. Whereas substantial steam load growth was

assumed in most cases, the rate of energy use per

unit of production has in fact dropped substantially in major industries. The industry that has

traditionally been most committed to cogeneration as an integral part of its business, the pulp

and paper industry, has reduced its energy consumption per ton of production by 26 percent

between 1972 and 1980. The chemical industry

has reduced its energy use by 22 percent over

the same period, and the petroleum refining industry, 15 percent. Steam production at the

largest operating industrial cogeneration system–the Gulf States 130-MW complex supplying steam to oil refineries and related industries

near Baton Rouge, La.—has decreased by 30 to

50 percent over the past several years, according

to a spokesman for the utility.

The weakened financial position of some industries is also likely to be a factor in cogeneration. Whereas the steel industry is a very heavy

energy user, it has been a declining industry over

the past decade and one unlikely to have the capital for new cogeneration facilities. In most industries, cogeneration faces competition for

capital with expansion of production capacity,

and in such a face-off cogeneration investments

are likely to have a low priority. However, this

situation would be averted under utility ownership, or under the leasing provisions of the

Economic Recovery Tax Act of 1981. Although

utilities face more financial problems than at any

time in decades, smaller investments in cogeneration systems can be financed more easily than

1,000-MW central powerplants.

If cogeneration is implemented, the amount of

electrical capacity resulting from a system sized

to fit a given heat or steam load could vary by

as much as a factor of 4 depending on the type

of cogeneration equipment that is used. For example, a large industrial installation that uses 0.5

million lb/hr of steam would cogenerate 30 to 40

MW of electricity with steam turbines, and 120

to 150 MW with gas or oil burning combustion

turbines. A major question for industrial usage,

therefore, is the extent to which alternate fuels

such as coal or biomass can be adapted to turbine technology, because the traditional fuels (oil

and gas) are now the most expensive available

on the U.S. market.
Ch. 5—industrial, Commercial, and Rural Cogeneration Opportunities ● 189

COMMERCIAL COGENERATION

Although the opportunities for cogeneration in

industry are numerous and diverse, cogeneration

in commercial buildings is likely to have a smaller

market potential. Commercial enterprises typically use thermal energy only for space conditioning and water heating, and have thermal load factors that are usually much lower than those of

industrial concerns. As a result, the economics

of cogeneration systems for commercial buildings

traditionally have been much less favorable than

those of industrial systems. Recently, however,

market incentives resulting from PURPA and/or

from high electricity and fuel prices have changed

the economics of commercial cogeneration. Several technical and economic factors in particular

determine the relative attractiveness of commercial building cogeneration and purchasing utilitygenerated electricity, such as the suitability of

electrical and thermal load profiles, the potential for fuel savings, and the change in relative

fuel prices.

This section discusses the results of OTA analyses of cogeneration in commercial buildings v.

centralized electric utility systems. The section

begins with a review of the literature on commercial cogeneration, followed by a general introduction to OTA’s analytical methods, a discussion

of the major assumptions used in the analyses,

and a summary of the results.

Previous Studies of

Commercial Cogeneration

Several existing studies have examined the

potential for commercial cogeneration in particular areas or under certain conditions. These

include a FERC study that estimated the amount

of cogeneration that would be stimulated by

PURPA (28); a study by the American Gas Association (AGA) that compared gas-fired cogeneration with two conventional heating systems in a

hospital in different climate regions (l); and

regional studies by Consolidated Edison (Con Ed)

for their service area (1 3,25) and by the State of

California for State-owned buildings (s).

The FERC study calculates the national and regional penetration of cogeneration and small

power production induced by PURPA through

1995, and concludes that only in the Mid-Atlantic

region (New York, New Jersey, and Pennsylvania)

is commercial building cogeneration likely to be

economically attractive. FERC projects that 2,500

MW of commercial sector capacity could or

might be installed in this region by 1995, producing 10,000 GWh/yr of electricity. In these calculations FERC assumed: first, that the PURPA regulations would be the sole incentive for cogeneration; second, that cogeneration would only occur

in large new buildings (e.g., new apartment buildings with more than sO units, new hospitals having more than SO beds); third, that all commercial investment would earn a fixed rate of return

of 20 percent; and fourth, that all equipment

would have a fixed capacity factor of 45 percent

and a fixed size of 500 kw. Some of these assumptions may be both too kind and too cruel

to commercial cogeneration. That is, FERC’S analysis ignores incentives other than PURPA (e.g.,

tax benefits, high electricity rates), the possibility of retrofits or eventual use in smaller buildings,

and the achievement of higher capacity factors,

and thus may understate cogeneration’s potential. At the same time, the analysis uses a very

favorable rate of return and thus may overstate

the market potential for cogeneration under current high interest rates.

The AGA study is based on a prototype design

for a 300,000 square foot hospital located in four

different climate regions. AGA assumed two different rates for utility purchases of cogenerated

power to compare the annualized capital, fuel,

O&M, and net electricity costs for three different

types of heating and cooling systems for the hospital: 1) a conventional combination system,

using a gas boiler to provide steam for space

heating plus an electric air-conditioner for space

cooling, and relying on the grid for electricity;

2) an all-electric system, using baseboard resistance heaters and air-conditioners run with utilitygenerated electricity; and 3) an all-gas system,

using a gas-fired cogenerator to provide electricity

and space heating and a waste heat recovery system to run an absorptive air-conditioner. AGA

assumed the cogenerator was sized to match the
190 . Industrial and Commercial Cogeneration

thermal load, with any excess electricity being

sold to the electric utility.

The AGA study concluded that the “economic

attractiveness (of cogeneration) is heavily dependent on the buyback rate for cogenerated electricity.” The study found that, for all four climate

regions, the cogeneration system had a lower annual cost than the other options when the buyback rates were set at 8cents/kWh. However, when

the rate was lowered to 2cents/kWh, cogeneration

was found to be economical only in the MidAtlantic region. This is because the higher

buyback rates offset cogeneration’s high capital

cost compared to the capital costs of the combination and all-electric systems. But when the

buyback rates were lowered, cogeneration’s capital cost became prohibitive in all but the MidAtlantic region, where high fuel costs and electric utilities’ dependence on foreign oil give fuelefficient cogenerators an economic advantage.

Although the AGA study analyzes the sensitivity

of cogeneration economics to factors such as buyback rate and climate, it is limited to hospitals,

a type of commercial building with a relatively

constant energy demand.

ConEd developed a model of the costs and

benefits of investment in cogeneration based on

the internal rate of return from such investment,

and applied the model to load data for their 4,500

largest customers, assuming that the investment

would be made if the rate of return would be at

least 15 percent over 10 years. Depending on

customers’ loads and other variables, ConEd

found an “expected” cogeneration penetration

of 395 customers with a combined peakload of

1,086 MW, with a high range of up to 750 cogenerators totaling 1,483 MW peakload. The

analysis was then repeated using a slightly higher

cost cogenerator (and thus a lower rate of return),

and the market potential dropped substantially—

to 27 customers with a combined peakload of 130

MW.

These market penetration estimates for cogeneration depend heavily on how the cogenerators

will operate. Con Ed assumed that cogenerators

would only operate when there is sufficient electrical demand on the system. Thus, the assumed

thermal efficiency is low (52 percent for commercial building systems and 62 percent for residential systems), and the cogenerators are unable to

provide either substantial fuel or cost savings.

However, if cogenerators are undersized (relative

to the electrical demand) so that they operate as

“baseload” heaters and only supply some of the

electrical needs, they may have lower total costs,

and thus, higher penetration rates than the ones

calculated by ConEd (3). Therefore, even in the

Mid-Atlantic region, cogeneration’s market penetration may be very sensitive to operating and

cost assumptions.

In the fourth study of cogeneration in commercial buildings three State agencies in California

calculated the cogeneration potential in Stateowned buildings, including hospitals, universities,

and State offices. The State identified 188 Stateowned facilities that have significant potential for

cogeneration, and initiated engineering studies

for the cost effectiveness of cogeneration. “The

evaluation showed that 150 MW at 24 sites could

be designed, under construction, or in operation

in fiscal year 1981. An additional 97 MW at 31

sites could be developed in fiscal year 1982, totaling 247 MW at 55 sites. It should be clearly understood that these are preliminary estimates of

cost-effective cogeneration capacity. Further

engineering analyses may result in increased or

decreased capacity.” The study concludes that

the total potential for cogeneration in Stateowned buildings is over 400 MW. The distribution of this capacity among State facilities is

shown in figure 51.

Because the literature on commercial cogeneration is sparse, OTA undertook its own analysis

of cogeneration opportunities in the commercial

sector. This analysis is concerned with illustrating

those parameters that significantly affect the use

of cogeneration in commercial buildings. To do

this, in part, we make use of a computer-based

model—the Dispersed Electricity Technology

Assessment (DELTA) model–that simulates decisionmaking by electric utilities in choosing new

capacity. The model can accommodate ranges

of values for the technical, operating, and financial characteristics of utilities and cogenerators.

There are limitations to its use, however, due to

the number of assumptions that have to be made

and 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 facility

SOURCE: 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 accurately project levels of cogeneration use in commercial buildings over the next several years. in particular, we have not used the model to analyze

the case where natural gas and distillate oil prices

are significantly different from one another, nor

the case where retrofits of existing buildings are

included in the demand for thermal energy. A

qualitative discussion of these cases is presented,

however. The model does give us, though, insight into how cogeneration might compete with

new central station capacity to supply commercial electricity demand, and the effect of such factors as thermal load profiles on that competition.

Therefore, despite its limitations it is believed that

the DELTA model–properly clarified–will substantially assist in understanding the conditions

that affect cogeneration’s future in the commercial sector.

Critical Assumptions and Limits

of the DELTA Model

The DELTA model uses a linear program (similar to those used by utility planners) that

minimizes the total cost of producing electricity

and thermal power during the years 1981 to 2000

(see app. A for model description). The model

simulates the addition of grid-connected cogeneration in three kinds of large new commercial

buildings, with different types of daily load cycles,

to supply electricity, space heating, and space

cooling demands. Several scenarios were constructed to explore the sensitivity of cogeneration in these buildings to regional utility and

climate characteristics, future fuel price changes,

and different technological specifications. The

structure of the model, the assumptions about

thermal and electricity supply and demand, and
192 . Industrial and Commercial Cogeneration

the features of the scenarios constructed are described below.

Model Structure

Electric and Thermal Cost Minimization.—The

DELTA model differs from many existing utility

planning models in that its objective is the minimization of total annualized fixed plus operating

costs for both utilities and their commercial

building customers (e.g., for heating and cooling). Thus, DELTA goes beyond traditional utility planning, which usually analyzes only those

costs borne by the power system. The strategy

selected through this hybrid cost minimization

may not exactly match either the strategy chosen

by the utility or by the customer acting alone, but

will tend to produce an “average” between both

parties.

Demand Assumptions

Grid-Connected Cogeneration.–The DELTA

model only examines grid-connected cogeneration because the PURPA provisions on purchases

of cogenerated power are intended to benefit

cogeneration systems that provide energy and/or

capacity as well as diversity to utilities. Therefore,

OTA did not analyze the effects of stand-alone

systems on utility operations.

Three Types of Energy Demands.–The DELTA

model specifies hourly demands for three types

of energy: space heating, space cooling, and electricity. The analysis begins in 1980 with a specified

thermal baseline of zero load and zero capacity, and an electrical baseline of 1,000-MW load

and the existing generating capacity mix (normalized to the 1,000-MW load) in each sample

region. The model then determines what capacity

additions will minimize utility and customer costs

for all three types of energy, assuming a range

of growth rates for energy and peak demands in

each sample region (see table 40, below, for a

description of existing electrical capacity and

growth rates). New capacity is added at the end

of each decade—in 1989 and 1999—and then system costs are evaluated in 1990 and 2000.

The 1980 electric generating capacity in each

sample region was normalized to 1,000 MW to

facilitate comparisons of capacity additions and

future utility operations among the different

regions. However, in order to compare thermal

demands among the building types and regions

a different approach was necessary. A large

amount of data would be needed for a precise

specification of existing thermal capacity and

demands–unlike electrical demands, there is no

accurate and centralized source of information

on thermal demand and capacity. Thus, in order

to ensure consistent and accurate treatment of

thermal demands, OTA would have had to collect individual commercial customer profiles–a

time-consuming and expensive process. Therefore, OTA chose another method for the DELTA

model: to set existing thermal demands and

capacity equal to zero. In effect, this is equivalent

to only allowing cogeneration in new buildings,

and then comparing the cost of installing cogeneration with the costs for new centralized capacity and new steam boilers, but not considering the

replacement of any existing steam boilers with

new cogeneration equipment. As was stated,

without inclusion of such boiler retrofits, the

model cannot be used to project the cogeneration potential in the entire commercial sector.

Although we have not attempted to project the

retrofit potential in any other way, the factors that

will influence this potential will be discussed later

in this section.

Eight Typical Days. –OTA chose to specify

each type of energy demand with a yearly pattern of eight different “typical days” in order to

observe more clearly the range and frequency

of utility operating characteristics (see table 37).

Table 37.—Typical Days Used in the DELTA Model

Day type Frequency Per Year

Winter:

Peaka

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

Weekday . . . . . . . . . . . . . . . . . . . . . . . .

Weekend. . . . . . . . . . . . . . . . . . . . . . . .

Summer:

Peaka.. . . . . . . . . . . . . . . . . . . . . . . . . .

Weekday . . . . . . . . . . . . . . . . . . . . . . . .

Weekend. . . . . . . . . . . . . . . . . . . . . . . .

Fall/spring:

Weekday a . . . . . . . . . . . . . . . . . . . . . . .

Weekend . . . ... , . . . . . . . . . . . . . . . . .

6

59

26

108

44

Total . . . . . . . . . . . . . . . . . . . . . . . . . 365

aThe 1990 electrlc bad patterns for region 1 for these 3 days are shown in fig. 52.

SOURCE: Off Ice of Technology Assessment.
Ch. 5—lndustrial, Commercial, and Rural Cogeneration Opportunities 193

Each typical day has a specific load cycle pattern

for each region and year. For example, the load

cycle patterns during 1990 for three different

typical days and for one region (New England)

are shown in figure 52. The differences among

these cycles are caused by the different assumptions for energy use and demand growth used

in each region.

Three Commercial subsectors.-ln addition to

specifying the annual load patterns for electricity, OTA chose to disaggregate the commercial

sector’s thermal heating and cooling demands

into three parts: hospitals and hotels, multifamily buildings, and 9-to-5 office buildings. This was

done to explore the effects of load diversity on

cogeneration operation, and thus to provide

more precise information on the opportunities

for commercial cogeneration. Other commercial

sector building types (such as universities and

retail stores) have energy demand profiles that

are combinations of these basic three categories.

(The electric demands were not disaggregated in

the DELTA model because the load profiles for

the entire commercial sector were sufficient to

capture the interaction of the cogenerators with

the centralized utility system.)

The three subsectors were chosen for their different thermal load patterns; examples of these

patterns for two typical day types are given in

figures 53 and 54 for 1990 New England heating

and cooling demands respectively. For heating

demands, hospitals and hotels have the lowest

energy demands of all the subsectors, with small

peaks at 8 a.m. and 9 p.m. Multifamily buildings

use somewhat more energy and have similarly

occurring peaks, while 9-to-5 offices use the most

energy and have the most pronounced peak during the winter days at 6 a.m. The cooling demands of hospitals and hotels and multifamily

buildings are small when compared to office

buildings, the latter having a peak during summer days at 2 p.m.

Supply Assumptions

The energy supply assumptions in the DELTA

model 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 Winter

weekday peak day peak day

-. .-. . . . . . . . .

MW electrical demand

1,100

1,000

900

800

700

600

500

400

12 midnight 4 a.m. 8 a.m. 12 noon 4 p.m. 8 p.m. 12 midnight

Time of day

SOURCE: Office of Technology Assessment.
194 . Industrial and Commercial Cogeneration

Figure 53.—1990 Heating Demands for Scenario 1s (for Region 1 during 1990)

Winter peak day

1 0 0

90

12 midnight 4 a.m. 8 a.m. 12 noon 4 p.m. 8 p.m. 12 midnight

Time of day

Summer peak day

7

Multifamily 9-to-5 office I

12 midnight 4 a.m. 8 a.m. 12 noon 4 p.m. 8 p.m. 12 midnight

Time of day aScale on two graphs Is different.

SOURCE: Off Ice of Technology Assessment.

technological and operational characteristics in coal (and electricity) and 1.7 percent per year for

order to describe the three different sample utility fuel oil and natural gas for the low price trajecregions. tory, and 4.7 percent annually for coal (and elecFuel Prices.–OTA specified two different fuel tricity) and 4.8 percent per year for fuel oil and

price trajectories, based on the 1980 average

natural gas for the high price trajectory. * For this

prices in the commercial sector (31) and the range analysis of commercial cogeneration, these asof 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, ApplicaThese growth rates are: 1.0 percent annually for

tion of Solar Technology to Today’s Energy Needs, vol. 11, September

1978.
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 day

a Scale on two graphs Is different.

SOURCE: Office of Technology Assessment.

sumptions were modified slightly by setting the Therefore, only the lower price path results were

price 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 reIowed us to test the sensitivity of our results. quires elaboration. Currently, most natural gas

However, the results varied by less than 2 per- is used for purposes that require a higher quality

cent between the two different price paths. fuel than coal or residual fuel oil. About 25 to
—.

196 . Industrial and Commercial Cogeneration

Table 38.-Fuel Prices

(all prices In 1980 dollars per MMBtu)

1980 1990 2000

Coal . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.34 1.95 2.38

Residual . . . . . . . . . . . . . . . . . . . . ., . . . 4.05 5.86 7.13

Distillate . . . . . . . . . . . . . . . . . . . . . . . . 5.67 8.20 9.98

Natural gas . . . . . . . . . . . . . . . . . . . . . . 2.09 8.20 9.98

SOURCE: Office of Technology Assessment.

30 percent of current natural gas use is for raising steam, while the remainder goes for space

heating in buildings, industrial process heat,

peakload electricity generation (primarily combustion turbines), and chemical feedstocks (7).

The future price of natural gas will be determined

by the relative strengths of these demands combined with the availability and cost of new domestic natural gas.

The conversion of all natural gas-fired boilers

to coal would free about 4 trillion to 5 trillion

cubic feet (TCF) of natural gas per year at current consumption rates. If there were no other

change in natural gas supply and demand, this

new “supply” would be more than enough to

replace all current distillate fuel oil used for stationary purposes (1.9 MMB/D) (8). If price increases resulting from decontrol bring about

more conservation, additional natural gas would

be freed, which, when combined with the displaced boiler fuel, would result in a substantial

surplus of natural gas. The most logical use for

this surplus gas would be to displace residual fuel

oil used to fire boilers. (Of course, in reality, the

gas would only leave the boiler market until it

just displaced all stationary fuel oil). This competition with residual fuel oil would keep the marginal cost of natural gas about the same as that of

residual oil.

This scenario, however, assumes that domestic

natural gas supplies do not decline significantly

over the same period, and that the marginal cost

of the new supplies that offset the decline in production from existing reserves will be below the

price of distillate fuel oil. It is quite possible–

indeed both Exxon and the Energy Information

Administration have projected as much–that

there will be a net decline in domestic natural

gas 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 fraction

of new domestic supplies in these projections is

made up of high cost supplemental supplies—

unconventional gas, Alaskan gas, and synthetic

gas from coal. In fact, the three organizations project about the same amount of conventional domestic natural gas production—about 14 TCF in

1990 and 12 TCF in 2000. This is close to the

quantity now being consumed by the so-called

high priority uses for which only distillate fuel oil

or electricity are feasible substitutes (19). Therefore, if the cost of new marginal natural gas supplies were equivalent to distillate fuel oil, the price

of all natural gas would approach that of distillate

or electricity (whichever is cheaper) as decontrol

takes effect and the quantity of old, flowing natural gas under contract vanishes. It is partly the

somewhat optimistic supply assumptions about

new, “lower cost” gas that has caused most recent price projections to show natural gas prices

below those for distillate fuel oil for the remainder

of the century (8).

Our price scenarios rest on the assumption that

“lower cost” gas supplies will decline as fast or

faster than the rate at which coal displaces natural

gas in boilers. Even in this case, however, natural

gas prices could be lower than distillate oil if electricity prices stay below distillate (on an energyservice basis)—as they currently are in many regions of the country. in this case, natural gas

prices will likely approach those of electricity

(again on an energy service basis). Similar speculation has been offered by others (26). Because

OTA did not run the model with natural gas

prices below distillate, the model results presented are confined to what would happen under

the plausible situation that the prices of the two

fuels are the same. To partially expand the analysis, some calculations of target gas prices are presented for the condition that cogeneration produces power at the cost of electricity determined

by the model. There is evidence, as will be seen,

that some cogenerators are proceeding based on

the assumption that natural gas prices will remain

below distillate prices for the economic life of

their projects.

Technology Characteristics.–The major

technologies used in the DELTA model include
Ch. 5—industrial, Commercial, and Rural Cogeneration Opportunities ● 197

three types of central electricity generating plants,

several space heating and cooling technologies,

and the cogenerators. Table 39 summarizes the

characteristics for each type.

OTA specified three different types of generic

utility generating plants to serve base, intermediate, and peak loads. The baseload type is represented by coal-fired steam powerplants, the intermediate-load type by either residual oil-fired or

distillate or gas-fired steam turbines, and the peaking technologies by distillate or gas-fired combustion turbines.

Space heating and cooling technologies in the

model include ordinary steam boilers used for

heating, electric air-conditioners, absorptive airconditioners using distillate or gas fuel, and thermal storage equipment with a capacity of up to

24 hours storage. Because of the linear programing formulation, the model cannot change the

type of fuel used in either electric generating or

thermal equipment from their original specification in table 39.

Two sets of capital costs for cogeneration capacity were included in the analysis. The higher

cost 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 capital

costs are typical of the range of cogeneration

costs described in chapter 4 (see table 23). We

did not include, explicitly, cogeneration technologies that could use coal by means of synthetic

fuel production or advanced combustion technologies (e.g., fluidized beds). If the capital costs

of these technologies are similar to those used

in the model, the results would remain unchanged. The only exception would be a reported increase in coal use if these technologies

are employed, because the model allowed cogeneration technologies to use only oil or natural

gas.

Operational Assumptions.–OTA made three

operational assumptions that would allow the

DELTA model to follow more closely the way actual grid-connected cogeneration systems would

operate. First, OTA specified the utility planned

reserve margin to be 20 percent of annual peak

demand. This includes scheduled maintenance

for 10 percent of the year for the base and intermediate types of plants, and is typical of

reserve margins used in power systems planning,

although actual reserve margins may be much

higher than 20 percent. For the sample utility

regions used in this analysis (see below), all 1980

reserve margins were above 20 percent. In addition, the actual 1981 national average reserve

capacity was around 33 percent (16).

Second, the model assumes that all cogeneration 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 10,300

Intermediate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 200 0,0015 88 10,500

Peak . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 200 0.3 0.003 93 14,000

Cogeneration—high . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 750 0.0 0.008 95 9,751

Cogeneration—low . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 575 0.0 0.008 95 9,751

Thermal boiler . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 100 0.0 0.0 95 4,266

Thermal storage. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2’ 0.0 0.0 — —

Electric air-conditioners . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 700 0.0 0.0 95 1,138

Absorption air-conditioners . . . . . . . . . . . . . . . . . . . . . . . . . . . 110 0.0 0.0 95 5,251

aAvailability 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&M

costs, heat rates, and availabilities for coal steam plants with flue-gas desulfurization, for distillate oil-fired steam plants, and for oil- and gas-fired combustion 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 Gross

National Product inflator to bring 1978 dollars to 1980 dollars. Characteristics for the thermal technologies were obtained by averaging the data collected

in 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 the

conventional space heating and cooling technologies, because these costs are very small when compared to the 8 mills/kWh variable O&M costs of the

cogenerators.
198 . Industrial and Commercial Cogeneration

MMBtu, with 35 percent of the output used for

electricity, 45 percent to satisfy the thermal load, *

and 20 percent exhausted to the outside environment—an overall efficiency of 80 percent. Third,

thermal storage is assumed to have an efficiency of 90 percent (i.e., 1.0 MWh (thermal) into

storage can supply 0.9 MWh (thermal) out of

storage). No electrical storage is considered.

These values are within the range of actual values

described in chapter 4 for E/S ratios and efficiencies for gas turbine or combined-cycle cogeneration systems, which are or will be applicable in

the commercial sector (see table 23).

Sample Regions. –OTA chose three sample

utility regions based on the technological and

operational assumptions mentioned above and

on data from the regional electric reliability councils. Region 1 is typical of areas with utilities that

have a large percentage of oil-fired steam generation, high reserve margins (over 40 percent), and

a relatively moderate annual growth in electricity demand of 1 percent (such as the Northeast

Power Coordinating Council). The summer and

winter peaks for Region 1 are about equal. Region

2 is typical of summer-peaking regions with mostly nuclear or coal baseload capacity, a higher annual load growth than in Region 1 (2 percent),

but lower reserve margins (26 percent) (e.g., the

Mid-America Interpool Network). Region 3 is

typical of areas with large reserve margins (over

40 percent), relatively high load growth (3 percent), and large amounts of gas-fired steam generation (such as the Electric Reliability Council

of Texas). Region 3 is also summer-peaking. (See

fig. 8 for the location of each of these regions of

the North American Electric Reliability Council.)

● Measured in megawatts, i.e., 1 MW (thermal) = 3.412

MMBtu/hr.

Table 40 summarizes the electrical demand and

supply characteristics of each region, normalized

to 1,000 MW.

Scenario Description

Based on the above demand and supply assumptions, OTA used nine “standard scenarios”

to investigate the effects of cogeneration on the

sample utility regions for different cogeneration

costs (see table 41). These standard scenarios

were grouped into three sets to represent the

three utility regions. Each set has three different

scenarios: a base case in which no cogeneration

is allowed and only utility powerplants are used,

and two cogeneration cases using higher and

lower capital costs of the cogenerators. As mentioned previously, the scenarios also originally included two sets of fuel prices. However, the results of the analysis varied by less than 2 percent

between the higher and lower prices, and only

the results for the lower prices are reported here.

In addition, five special scenarios were formulated to investigate the effects of limiting the

addition of baseload capacity and of using a zero

capital cost cogenerator. Not all possible combinations of regions and cogeneration capital costs

were made for these five special scenarios because OTA was primarily interested in observing

the sensitivity of the standard set of scenario assumptions to particular situations, rather than

making complete inter-regional comparisons.

Table 41 identifies these special scenarios and

their distinguishing assumptions.

Commercial Cogeneration Opportunities

The DELTA model described above chooses

among the varying technological, financial, and

other assumptions to find the minimum total cost

Table 40.-Sample Utility Configurations

Annual 1960

1960 capacity installed (MW) Electrical peak reserve

Region Base Intermediate Peak Total demand growtha

in margin

740 150 1,390 1% Summer, winter 39%

2

500 

1,020 o 237 1,257 2 % Summer 26°A

3 265 1,107 50 1,44 2 3%0 Summer 4 4 %

aAnnual growth in both electrical peak demand and total energy demand.

SOURCE: Office of Technology Assessment.
Ch. 5—industrial, Commercial, and Rural Cogeneration Opportunities 199

Table 41.—Description of Scenarios Used

Standard scenarios:

l-NO COGEN

1-HIGH COST COGEN

l-LOW COST COG EN

2-NO COGEN

2-HIGH COST COGEN

2-LOW COST COG EN

3-NO COGEN

3-HIGH COST COGEN

3-LOW COST COG EN

Special scenarios

l-NO COGEN/COAL-LIMITED

l-LOW COST COGEN/COAL-LIMITED

2-ZERO COST COGEN

3-NO COGENI/OAL-LIMITED

3-LOW COST COGEN/COAL-LIMITED

Region 1, base case/no cogeneratlon allowed

Region 1, high capital cost cogeneration

Region 1, low capital cost cogeneration

Region 2, base case/no cogeneration allowed

Region 2, high capital cost cogeneration

Region 2, low capital cost cogeneration

Region 3, base case/no cogeneration allowed

Region 3, high capital cost cogeneration

Region 3, low capital cost cogeneration

Region 1, coal-fired baseload capacity limit, no cogeneration

Region 1, coal-fired baseload capacity limit, low capital cost cogeneration

Region 2, zero capital cost cogeneration

Region 3, coal-fired baseload capacity limit, no cogeneration

Region 3, coal-fired baseload capacity limit, low capital cost cogeneration

SOURCE: Office of Technology Assessment.

of providing electric and thermal energy in each

scenario. The model results are not predictions

about future utility behavior—rather, they represent what might happen under the conditions and

assumptions used to specify the scenario. By

answering these “what-if” types of questions, the

model can provide valuable insights about the

interaction of cogeneration with the existing centralized utility systems.

Capacity Additions and

Operating Characteristics

In order to analyze the addition of cogeneration capacity and its effects on utility system

operations, OTA determined, first, whether a

minimum-cost capacity expansion plan would include significant amounts of cogeneration, and

second, how the cogeneration equipment that

is added is used to supply electric and thermal

energy.

COGENERATION CAPACITY

To see if cogeneration capacity would be economically attractive compared to central station

generation for our set of assumptions, OTA compared the electric generating capacity additions

for the base-case scenarios–in which no cogeneration is allowed—with the scenarios in which

cogeneration can be added. Figure 55 summarizes these capacity addition comparisons for the

nine standard scenarios.

The results show that the greatest opportunity

for cogeneration occurs when the match between thermal space heating and electrical

demands is the closest. Thus, the largest proportion of cogeneration capacity is added in Region

2, which has the highest thermal demand of the

three regions. Region 3, on the other hand, adds

more total capacity (cogeneration and central station) because it has the largest growth in electricity demand, and because it has a large proportion of existing gas-fired capacity that can be

replaced by less expensive coal-fired units. With

our assumptions, therefore, commercial cogeneration in new buildings is competitive with central station technologies only when there is a

significant need for space heating and at least a

moderate growth in electricity demand. Coalfired capacity is cheaper than new cogeneration

capacity when electricity is needed but very little or no heating is required. Coal is cheaper because of the difference in fuel prices, and that

difference dominates any other cost of installing

or operating the technology under our assumptions.

One way to test this result is to vary the capital

cost of the cogenerator. By going to the extreme

case of zero capital cost, the limit of cogeneration penetration can be shown under our fuel

cost assumptions. * We ran this case for Region

*This analysis also provides a rough approximation of what might

happen by keeping the capital cost unchanged but lowering natural

gas fuel prices.
200 . Industrial and Commercial Cogeneration

Figure 55.–Elactrical Capacity Additions 1990-200@

Baseload Peak Cogeneration

I Low

aFor 1990, scenario l–LOW-COST COGEN/COAL-LIMITED.

SOURCE: Office of Technology Assessment.

2 (abbreviated as 2-ZERO COST COGEN), and

found that the cogeneration technology was

more competitive with the coal baseload capacity

and more cogeneration was installed than in the

other cogeneration scenarios for Region 2. However, the amount of electricity produced from the

cogeneration did not increase significantly (see

the discussion on costs below).

In another set of special cases, the amount of

coal that could be used for central station capacity was restricted. This constraint had two purposes. First, it simulated conditions where coal

burning may be prohibited or severely restricted

for environmental, availability, or other reasons.

(This assumption also simulates the case where

nuclear would serve as the baseload and it, too,

would be restricted.) The second purpose was

to examine the effect of much higher coal prices

relative to natural gas and oil. This method

(restricting coal use) is not as satisfactory as carrying out model runs with different fuel price trajectories and ratios, but will serve qualitatively

to show how higher coal prices would benefit oilor natural gas-fired cogeneration.

In Region 1, no baseload plants were allowed

to be added through 2000, while in Region 3,

baseload capacity additions through 1990 were

limited to a small percentage of the total existing

baseload capacity, while no limits were placed

on additions from 1990 to 2000. Two scenarios

were run for each region: a new base-case in

which only central station equipment was added

(abbreviated l-NO COGEN/COAL-LIMITED and

3-NO COGEN/COAL-LIMITED, for Regions 1 and

3 respectively) and a cogeneration case (abbreviated l-LOW COST COGEN/COAL-LIMITED

and 3-LOW COST COGEN/COAL-LIMITED).

Table 42 summarizes the capacity additions for

these four scenarios.

Table 42 shows that the limits on baseload

capacity additions increase the economic attractiveness 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 electrical

capacity 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 100

3-NO COGEN/COAL-LIMITED 1,192 100 0

3-LOW COST COGEN/COAL-LIMITED 1,363 63 0 17

NOTE: “-” means assumed zero input for this scenario.

SOURCE: Office of Technology Assessment.

ample, 3-LOW COST COGEN/COAL-LIMITED installs 77 percent of its total capacity as cogeneration while the standard Region 3 scenarios

(3-HIGH COST COGEN, and 3-LOW COST

COGEN) install at most 4 percent.

These results demonstrate the competition between cogeneration and central station coal-fired

capacity to meet new electricity demand. Both

capital and operating costs of the system and the

thermal demand determine this choice. If new

coal-fired capacity is sufficiently inexpensive,

even in the face of the efficiency advantage of

cogeneration, coal will provide electricity and

conventional oil- or gas-fired space heaters will

provide thermal energy for these new buildings.

Further, if excess electric generating capacity exists, the ability of cogeneration to penetrate the

commercial market may also be limited, even if

cogeneration is less costly than new, coal-fired

central station generation. Electricity from the existing capacity, because of its sunk capital cost,

is usually cheaper than that produced by new,

more efficient cogeneration if the latter is confined to premium fuels. In some cases, however,

economics may still favor cogeneration, particularly if the existing central station capacity is oil

fired and near retirement. In some markets where

retirement would be desirable in the next few

years, cogeneration from natural gas-fired units

could 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 are

explained by the details of how the electrical and

thermal loads are met. OTA calculated the electrical capacity factor (the ratio of time a generator

actually supplies power to the time the plant is

available for service) for both the cogeneration

and the baseload capacity in each of the scenarios. Table 43 shows the electrical capacity factors calculated by the model for both the standard and coal-limited scenarios. Most of the baseIoad capacity operates 66 to 70 percent of the

time, while the cogenerators operate less than

30 percent of the time. * The low load factor for

cogeneration results from its inability to generate

electricity that is competitive with central station

electricity even though cogeneration is more

energy efficient. This is a result of our assumed

fuel prices. As we shall see, the DELTA model

only operates cogenerators when the electricity

is needed to meet intermediate or peaking demands that otherwise would be supplied by oilfired utility units. The higher fuel prices of these

utility units, combined with the high overall efficiency of the cogenerator, allows the latter to

compete economically in the market for intermediate and peaking power. When coal is prohibited, the thermal and electrical capacity factor of the cogenerators increases from 30 percent

or less to over 50 percent. In this case, the cogenerators are also supplying a small amount of baseIoad electricity. This is because the cogenerators

can supply power less expensively than other

types of central station generation when coal-fired

additions are limited.

However, these capacity factors only indicate

the most general performance of each type of

equipment. in order to provide a more complete

description, we need to observe, for each scenario, the hour-by-hour dispatching schedule (for

*For the cogenerator, this is also the thermal capacity factor since

the unit is producing both electricity and thermal energy while it

operates.
202 ● Industrial and Commercial Cogeneration

Table 43.-Capacity Factors for Baseload and Cogeneration Plants

Baseload plants Cogeneration plants

1990 2000 1990 200 0

Standard scenarios

l-NO COGEN . . . . . . . . . . . . . . . . . . . . . . . . . . . 69 68

1-HIGH COST COGEN . . . . . . . . . . . . . . . . . . . . 69 68

—

— 27

1-LOW COST COGEN . . . . . . . . . . . . . . . . . . . . 70 69 31 29

2-NO COGEN . . . . . . . . . . . . . . . . . . . . . . . . . . . 66 67 —

2-HIGH COST COGEN . . . . . . . . . . . . . . . . . . . .

—

70 10

2-LOW COST COGEN . . . . . . . . . . . . . . . . . . . . 66 68 7 13

3-NO COGEN . . . . . . . . . . . . . . . . . . . . . . . . . . . 69 68

3-HIGH COST COGEN . . . . . . . . . . . . . . . . . . . . 70 68 21 20

3-LOW COST COGEN . . . . . . . . . . . . . . . . . . . . 70 69 21 21

Baseload-limlted-scenarlos

l-NO COGEN/COAL LIMITED . . . . . . . . . . . . . . 80 80 —

l-LOW COST COGEN/COAL-LIMITED . . . . . . . 80 80 58 53

3-NO COGEN/COAL-LlMlTED. . . . . . . . . . . . . . 80 67

3-L0W C0ST COGEN/COAL-LlMlTED . . . . . . . 80 69 95 7

Note:”—” 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

SOURCE: Off Ice of Technology Assessment.

both cogenerators and central station generators)

for each of the eight different types of “typical”

days used in the analysis. Figures 56 and 57 present the space heating and electric demands, respectively, and show how each technology is

dispatched to meet these demands for 1 day

(winter peak which occurs six times a year) in

1990 for scenario 1-LOW COST COG EN/COALLIMITED.

Figure 56 shows that, during the 1990 peak

winter day, the cogenerators provide about 37

MW of heat to meet thermal demands that vary

between 30 and 78 MW. During this peak day,

the cogenerators operate 95 percent of the time.

Thus, seen from the perspective of a commercial building owner, cogenerators operate as a

“baseload” heating system during winter peak

days.

Figure 57 shows the electrical demands for the

same 1990 winter peak day. Note that the cogenerators only contribute to the peak and intermediate load. The small numerical value of these

contributions is partly due to our assumptions of

zero thermal demand and 1,000 MW of electrical

demand for 1980. If a larger thermal demand had

been assumed and retrofits considered, the electricity contribution of the cogenerators would

have increased substantially, although it would

still be confined to the peak and intermediate

load. What is important here, however, is not the

absolute value of the electrical contribution by

cogeneration, but rather what portion of the electrical demand it can supply economically compared with other options.

RETROFIT OPPORTUNITIES

As discussed above, existing buildings (hence

existing thermal demands) were not included in

this analysis. This rules out cogeneration retrofits

and thus the analysis understates cogeneration’s

contribution to the total electric load. It is therefore important to discuss the factors that will

influence the choice of whether to install a cogeneration system in an existing building. In addition to the considerations about economic competition with new central station electric generating capacity, the major constraints to retrofitting

are excess central station capacity, the uncertainty about natural gas prices and availability, and

the difficult financial conditions brought about

by high interest rates and short loan terms.

The first constraint, excess capacity, has the effect of keeping the price of electricity well below

its marginal cost in most regions of the country
Ch. 5—industrial, Commercial, and Rural Cogeneration Opportunities ● 203

Figure 56.—Thermal Supply and Demand for Winter Peak Daya

12 midnight 4 a.m. 8 a.m. 12 noon 4 p.m. 8 p.m. 12 midnight

Time of day

aFor 1990, scenario 1- LOW-COST COGEN/COAL-LIMITED.

SOURCE: Office of Technology Assessment.

Figure 57.–Electricity Supply for Winter Peak Day

12 midnight 4 a.m. 8 a.m. 12 noon 4 p.m. 8 p.m. 12 midnight

Time of day

 aFor 1990, scenario 1 - LOW-COST COGEN/COAL-LIMITED.

SOURCE: Off Ice of Technology Assessment.
204 ● Industrial and Commercial Cogeneration

and thus to force payments for cogenerated

power under PURPA to be determined by fuel

savings alone (i.e., no capacity credit). Both act

as an incentive for building owners to continue

purchasing all their electricity from the utility.

New buildings have a similar incentive–as the

model results have demonstrated. In the case of

existing buildings the incentive is even greater,

however, because of the sunk costs of existing

heating equipment and interconnection with the

utility. Where current prices exceed marginal

cost, as would likely be the case if oil is the dominant fuel used to generate electricity and the future capacity would be coal-fired, shortrun

PURPA payments based solely on fuel savings

could be high, stimulating cogeneration investment. More will be discussed on this below.

The second constraint, uncertainty about fuel

prices and availability, is important because natural gas is the most likely fuel for commercial

cogeneration retrofits for the next several years.

As discussed earlier, the price of natural gas will

increase, but it could still be low enough to make

cogenerated electricity and thermal energy (using

a combustion turbine, diesel, or combined-cycle

system) cost less than a combination of electricity

produced from central station generators and an

individual heating plant. Gas prices also could

be much higher, perhaps as high as distillate fuel

oil, which would make potential retrofits too costly in most cases. In the latter case, the results

would be similar to those obtained for new construction as given by the model. The price at

which natural gas-fired cogeneration is competitive with electricity depends primarily on the size

of the facility, the credit obtained for displacing

natural gas or oil used for space heating, the financial conditions available to the prospective

owner, and the thermal load factor of the building. Capital and O&M costs per unit output increase as the facility size decreases, lowering the

natural gas prices required for breakeven with

electricity. The displacement credit depends on

the amount of fuel saved from the displaced

space heating unit, and the cost of hooking up

the cogeneration unit. The thermal load factor

will determine the amount of electricity that can

be produced assuming the cogeneration unit operates to supply baseload thermal demand. The

Photo credit: OTA staff

Some older commercial buildings could be retrofitted for

cogeneration, but the economics of such retrofit will depend

on the price of electricity and the price and availability of

cogeneration fuels—primarily natural gas

analysis of this point is similar to that described

above for the new buildings.

As an example of these considerations, we examine a combined-cycle cogeneration unit of

about 10 MW (a size typical for a very large

building), operating to supply 50 percent of a

building’s heat load. Further, if this unit can

operate at a high electric load factor of 85 percent or more, this unit could produce electricity

that would compete with central station electricity 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 order

to determine a breakeven natural gas price. In actual operation it

is the other way around. Under the conditions that the building

owner’s goal is minimum cost and that the cogeneration unit is sized
Ch. 5—industrial, Commercial, and Rural Cogeneration Opportunities ● 205

tional average price of natural gas in the commercial sector commercial sector for the third-quarter

of 1981 was about $3.50/MMBtu. Therefore the

combined-cycle system described above appears

to have a definite economic advantage for regions

where electricity is selling for 5cents/kWh or greater.

There is another set of conditions that would

allow natural gas-fired cogeneration to be economically competitive even if the price relationships just calculated do not hold. If the price that

utilities must pay to cogenerators for power is set

high enough by the State public utility commission, then cogeneration would be installed even

if its electricity production costs were greater than

the retail price for electricity. Further, depending

on the purchase power price under PURPA, cogenerated electricity from a natural gas unit could

cost more than new, central station coal-fired

generation and still be economically preferable

to the latter. In California, for example, the purchase price is based on the cost of oil-fired generation. Many industrial and commercial establishments see this as a very attractive opportunity

because their natural gas prices are below the fuel

oil prices paid by the utility. Therefore, these

cogenerators are willing to enter into agreements

with utilities in California to sell them electricity

for the next 5 to 10 years.

Even though natural gas prices will increase and

probably surpass those of residual oil during that

period, the cogenerators will still receive a high

return because of their higher overall efficiencies.

Further, the utilities will be able to replace current oil-fired capacity more quickly than by more

conventional means—i.e., coal or nuclear central station. For the period beyond 1990, however, coal-fired, central station capacity is planned

and probably will be cheaper than natural gasto supply baseload thermal energy, cogeneration would be operated

whenever it can produce electricity at a cost less than or equal to

the combined cost of central station electricity and separate thermal energy production (e.g., a conventional building heating system). The former cost depends on the price of the fuel for cogeneration (natural gas in this case), various financial parameters (interest,

taxes, debt/equity ratio, etc.), and O&M costs. The cogeneration

unit must be sized to provide baseload thermal energy because

the cost of electricity alone from the cogenerator will nearly always

be greater than the cost of electricity from a central station plant

due to economic and efficiency reasons. It is therefore necessary

for the cogenerator to be able to displace building heating fuel and

obtain a cost credit in order to meet the minimum cost criteria.

fired cogenerated electricity as the ultimate replacement for the existing oil-fired capacity. However, successful coal gasification with combinedcycle generation could alter the economics back

to favoring cogeneration. More is discussed about

this last point below.

The California case is not typical of fuel oil dependent utilities, primarily because such utilities

located in other States usually can purchase power from neighboring utilities with an excess of coal

or nuclear power. In California, power purchases

generally are not an option because of limited

transmission interties with other systems. The

California case does, however, point out the potential for natural gas-fired cogeneration in the

next 10 years. We have also not calculated that

potential for new buildings since that analysis

determines longrun generation needs only (hence

longrun avoided costs).

The final point about cogeneration’s potential

in existing buildings concerns the financing conditions currently available to prospective cogeneration owners. Financial factors will help determine the cost of electricity and thermal energy

from a cogenerator. The current high interest

rates and short loan terms available to non utility

investors for investments in building energy systems are acting to severely limit cost effective investments of any type—conservation or cogeneration.

In a study released by OTA, Energy Efficiency

of Buildings in Cities (18), these current financial

conditions are partially responsible for keeping

about 60 percent of the otherwise cost-effective

conservation retrofits identified in that study from

being installed. Although OTA did not examine

cogeneration in this same way, it is likely that

cogeneration retrofits will be affected similarly,

perhaps even more so because of the much higher initial investment levels per building needed

for cogeneration than conservation. This is one

place where utility or third-party ownership

would be potentially very helpful. In the former

case, utilities would be able to secure longer term

loans at lower interest rates than commercial investors. In addition, utilities possess the engineering 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 and

still qualifying for PURPA benefits.

Aside from this legal barrier, however, a potentially more important one exists as a result of the

low thermal load factors in individual buildings.

Because of this, cogeneration that supplies baseIoad thermal demand to these buildings may not

produce excess electricity for sale to the grid.

Unless such electricity is produced, utilities cannot be expected to invest in commercial cogeneration. Raising the load factor, for example, by

supplying clusters of buildings (each with different

load patterns), would be one way to eliminate

this problem. Finally, third-party ownership with

lease arrangements may also be promising because of the provisions of the new tax laws.

Although we have not attempted to project the

retrofit potential for cogeneration, it is probable

that movement in that direction will be tentative

for the next few years, primarily due to unfavorable financial conditions. Even should interest

rates and loan terms ease in the near future, however, there still will be competition with conservation investments, which will reduce the technical potential for cogeneration in a given building.

Further the uncertainty over natural gas is likely

to remain until resolution of pricing policy and

elimination of end-use restrictions (the Fuel Use

Act, see ch. 3). Once these conditions are

cleared, however, and if natural gas prices are

low enough, or purchase power rates are high

enough, there could be considerable interest and

activity in cogeneration retrofits in the last half

of the 1980’s. If new technologies that can use

solid fuels—through gasification-are successfully

developed by then, further stimulus would exist.

Fuel Use

In addition to investigating the changes in utility

capacity additions and operating characteristics

that might result from cogeneration, OTA also

analyzed the change in proportion of fuels used

in the sample utility regions to determine if

cogeneration would displace any oil or gas. As

mentioned earlier, the analysis assumes that all

cogeneration equipment uses distillate fuels in

Regions 1 and 2 and natural gas in Region 3. The

results of the calculations of fuel consumption in

1990 and 2000 for the “no-cogeneration” standard scenarios are shown in table 44.

Not all scenarios are shown in table 44 because

the total fuel used and the proportion used by

each fuel type are similar between the base-case

(“NO COG EN”) and the cogeneration scenarios

for each region. Cogeneration accounts for less

than 1 percent of the total fuel used in all cogeneration scenarios, and the total fuel and proportionate fuel use change less than 1 percent between the two types of scenarios. As expected

for our fuel price and use assumptions, because

cogeneration cannot compete with baseload

coal-fired electricity, cogenerators operate only

a small fraction of the time (when they can supply

intermediate and peak demand electricity) and

therefore use only a small fraction of the total fuel.

A further caveat is the exclusion of existing

buildings’ thermal demand, as explained earlier.

Because the model was restricted to the case

where natural gas and distillate prices were equal,

no results were obtained for the case when natural gas prices fall low enough so that cogenerated power could compete with central station

electricity. 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 fuel

Scenario Base Intermediate Peak Cogeneration Steam boiler use (10’2 Btu)

1990

l-NO COGEN 98 1 0 64.2

2-NO COGEN 97 0 0 2 62.5

3-NO COGEN 95 2 0 o 3 74.0

l-NO COGEN 97 0 0 2 69.3

2-NO COGEN 95 0 o 4 74.4

3-NO COGEN 94 1 0 o 5 95.1

SOURCE: Office of Technology Assessment.
Ch. 5—industrial, Commercial, and Rural Cogeneration Opportunities . 207

the set of costs and technical assumptions as well

as the average price of electricity determined

in our analysis (ranging from 3.3cents/kWh to 7.0cents/

kwh). Using our assumptions of $575/kW capital

cost for the cogenerator, 0.8cents/kWh O&M cost,

and an overall heat rate of 9,750 Btu/kWh with

an 80-percent combined heat and electric power

efficiency, we can calculate the breakeven price

range of natural gas. For a cogenerator capacity

factor of 0.85 this price ranges between $2.55/

MMBtu to $8.40/MMBtu, which brackets the current commercial natural gas price of $3.50/

MMBtu (in 1980 dollars). Again, the capacity factor will be determined by the cost of electricity

produced by the cogenerator and, therefore, the

cost of natural gas. This is a complex interaction

because lower capacity factors reduce the fuel

displacement credit, thus increasing the net cost

of cogenerated electricity.

Similar arguments can be applied for the new

technologies not considered in the model. The

ability of these newer technologies to enter the

market depends ultimately on the cost of steam

and power they produce. Currently a few systems

are being developed that will allow these costs

to be estimated. One such system is the Coolwater combined-cycle, coal gasification system

recently announced (1 1). Although that system

is being designed to supply electric power to the

Southern California Edison system, successful

demonstration of the technology could lead the

way to cogeneration applications. An unpublished analysis of the economics of the Coolwater

facility as a cogeneration plant estimates an electricity cost of about 3.6cents/kWh, including a credit

for heat recovery (fuel displaced by byproduct

steam from the cogenerator) of about 4.6cents/kWh

(34). This price for electricity is lower than the

marginal cost of electricity from a new central station coal plant, although higher than the average

cost calculated in some of the cases of our analysis. The calculation, however, assumes a return

on equity that may be less than will be required

of new plants such as the Coolwater facility. * In

● In the particular example cited, the return on equity assumed

was 10 percent along with a 50/50 debt-equity ratio and a real interest rate on debt of 3 percent. If we repeat the calculation with

a 15 percent return on equity and a 5 percent real interest rate on

debt, values which we have found to be operative in favor of synfuels projects (21), the cost of electricity increases to 5.9cents/kWh.

addition, using such facilities for commercial

buildings entails the development of coal handing, delivery, and storage facilities plus the need

for air quality control equipment. All will add expenses to these systems (which were not included

in the calculation cited above), and the question

of the economic attractiveness of these advanced

cogeneration systems is still open. Biomass and

urban solid waste have been proposed as fuels

for gasification-cogeneration systems, and, in

some cases, are under development. The economic analysis of these systems is similar to that

given for the Coolwater facility. One exception

is that for proposed solid waste units, a credit is

available in the form of the tipping fees usually

charged to dispose of these wastes.

A recent development concerning biomass

cogeneration is a combined-cycle system using

a direct-fired combustion turbine fueled by pulverized wood. Using hot gas cleanup technology

developed in the British pressurized fluidized bed

combustion program, turbine blade damage is

reduced to an acceptable level. A 3-MW test unit

is currently being designed and built by the Aerospace Research Corp. of Roanoke, Va. Economic

analysis of this technology in a cogeneration system looks very promising and may be competitive

with coal-fired central station electric power (35).

As with other systems described in this chapter,

the economics are highly dependent on the electric load factor. Consequently, they are more promising for industrial sites then for buildings.

COAL-LIMITED SCENARIOS

While few changes in fuel use are observed in

1990 and 2000 between the cogeneration and

the base-case standard scenarios, some changes

do occur in the special scenarios that limit coalfired capacity additions (thus allowing other types

to operate more frequently than they would without these limitations). As mentioned earlier, four

special scenarios that limit baseload additions

were constructed: two allowing cogeneration and

two restricting cogeneration. Figure 58 shows that

the addition of cogeneration to the sample sysUtility financing, however, would allow a lower return even for

a first-of-a-kind plant, perhaps close to that assumed in the original

calculation. This argues in favor of utility ownership of such

cogeneration facilities.
208 . Industrial and Commercial Cogeneration

Figure 58.— Fuel Used in 1990 and 2000

Baseload Intermediate

I

or Coal= Limited Scenarios

Thermal

boilers Cogeneration

70

60

50

40

30

20

10

0

NoCogen Cogen NoCogen Cogen NoCogen Cogen NoCogen Cogen

---1990 -- - ---2000 - - ---1990- — — - 2000 — -

----- Region 1 -- — -- - -- - -Region 2 — - — — —

SOURCE: Off Ice of Technology Assessment.

terns decreases total fuel use when the cogeneration scenarios (I-LOW COST COGEN/COALLIMITED and 3-LOW COST COGEN/COALLIMITED) are compared to their respective basecase scenarios (l-NO COGEN/COAL-LIMITED

and 3-NO COGEN/COAL-LIMITED). This is a result of two factors. First, there is considerably

more cogeneration that operates at higher capacity factors, as shown above. Second, this greater

penetration allows the higher overall fuel efficiency of cogeneration to significantly affect total fuel

use.

Most of the decrease in overall fuel use in the

coal-limited scenarios (when 1- and 3-LOW COST

COGEN/COAL-LIMITED are compared to 1- and

3-NO COG EN/COAL-LIMITED, respectively) results from the decrease in fuels used by the intermediate electric generating capacity. While the

baseload coal consumption remains identical between the base-case and the cogeneration scenarios, the efficiency of the cogenerators, combined with the reduction of intermediate capacity

generation, reduces overall fuel used for the two

special coal-limited cogeneration scenarios. Table

45 compares the use of oil and gas for the four

coal-limited scenarios.

In summary, cogeneration has only a small effect on utility fuel use as long as electricity can

be produced more cheaply with other types of

technologies. However, in the special coal-limited scenarios, cogeneration may cause less total

oil to be used and may displace fuel used by the

intermediate capacity.

Sensitivities to Changes in Assumptions

In addition to analyzing fuel use and operating

characteristics with and without cogeneration, we

must also determine the sensitivity of this analysis

to changes in some of the assumptions used in
Ch. 5—industrial, Commercial, and Rural Cogeneration Opportunities ● 209

Table 45.-Comparison of Fuel Use for Coal-Limited Scenarios

Region 1 coal-limited Region 3 coal-limited

scenarios (net change scenarios (net change

in percenta

) in Percenta

)

1990 2000 1990 2000

Total fuel . . . . . . . . . . . . . . . . . . . . . . . – 1 – 2 –7 –1

Total residual . . . . . . . . . . . . . . . . . . . – 6 – l o —

Total distillate/natural gas . . . . . . . . +155 + 121 –13 +3

Total oil . . . . . . . . . . . . . . . . . . . . . . . . – 3 – 5 –13 +3

aA 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.

SOURCE: Off Ice of Technology Assessment.

the scenarios. One important assumption is the

cost for installing and operating cogenerators. As

mentioned above in the discussion of capacity

additions, OTA formulated a scenario, 2-ZERO

COST COG EN, that uses zero capital cost cogenerators for Region 2.

The sensitivity of our results to the costs of

cogeneration is determined by comparing the

types of capacity that are installed and how the

utility system uses cogeneration for two scenarios:

the 2-ZERO COST COGEN scenario with the

2-LOW COST COG EN scenario. While the ZERO

COST scenario installs 81 percent of its capacity

as cogeneration, the LOW COST scenario installs

20 percent. Despite the difference in cogeneration capacity between the two scenarios, the fuels

consumed by cogeneration are only 2 percent

of the total fuels used in each scenario. In other

words, for our fuel price assumptions, baseload

electricity from coal is still cheaper so it is used

to meet the baseload demand. In the zero capital

cost case, however, cogenerators can supply

thermal energy much more cheaply than boilers,

so cogeneration is being used primarily to meet

space heating demands plus as much intermediate and peak electricity demand as possible. Zerocapital cost cogeneration therefore is used as an

inexpensive heater, without displacing any coalfired generation. Thus, the cogeneration in this

scenario displaces some of the peakload equipment, and does not use its steam during peak

summer days.

Summary

By using the DELTA model and our set of technical and economic assumptions, OTA was able

to determine the interaction of cogeneration with

several sample centralized utility systems. Under

most circumstances, cogeneration additions in

new buildings were very limited because they

could not compete economically with central station coal-fired generation. As a result, fuel usage

did not change greatly from an all-centralized system. When coal-fired expansion was limited,

however, cogenerators penetrated the utility system significantly and provided much of the heating demands and peak and intermediate electricity for the system.

Three specific conclusions can be made from

this analysis. First, given the assumptions, cogenerated electricity cannot compete with central

station, coal-fired capacity. Therefore, in commercial buildings, cogeneration will only contrib

ute to peak and intermediate demands and will

only operate when it can supply such electricity.

This holds for even a zero capital-cost cogenerator. Lower natural gas prices, however, could

greatly increase the opportunity for cogeneration.

in fact, natural gas prices somewhat above current gas prices would allow cogeneration to compete with new, baseload, coal-fired central station capacity. Alternatively, successful development of gasification technologies that can produce moderately priced (about $5/MMBtu) medium-Btu gas from coal, biomass, or solid waste

could expand the competitive position of cogeneration. Finally, cost relationships could be determined by high utility purchase rates for cogenerated power that would also make natural or synthetic gas-fired cogeneration preferable regardless

of the actual Iongrun marginal costs of new COA

fired capacity.

Second, existing electric generating plants

usually can provide power more cheaply than
210 . Industrial and Commercial Cogeneration

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 is

any gains from more efficient fuel use; and this used, the best opportunity for cogenerators is in

domination results in little significant penetration regions with high heating loads (about 6,000 heatof cogeneration. However, lower cost natural gas ing degree-days) and moderate electrical growth

could change these economics. In some regions (at least 2 percent annual growth in peak and total

this is the case now where natural gas-fired co- energy).

generation is the preferable choice to existing oilRURAL COGENERATION

Although industrial and commercial sector cogeneration opportunities are recognized widely,

little attention has been paid to cogeneration applications in rural areas, particularly in agriculture.

The rural cogeneration potential is not so large

as in the industrial sectors, but could present fuel

and cost savings on farms or in rural communities. The principal rural cogeneration opportunities arise where there are existing small powerplants or where agricultural wastes can be used

as fuel. Promising cogeneration applications for

rural communities include producing ethanol,

drying crops or wood, and heating livestock shelters.

Small, rural municipal powerplants can gain significant economic and fuel conservation advantages with cogeneration if a market for the thermal energy is available. Many of these powerplants use reciprocating internal combustion

engines or combustion turbines as their prime

movers. Dual fuel engines predominate (generally

burning natural gas, with small amounts of fuel

oil to facilitate ignition), but diesel engines and

natural gas fueled spark ignition engines also are

common. Generally, these small rural powerplants have a peak electric power rating of 10

MW or less, and they operate at around 33 percent efficiency in producing electricity (i.e., 33

percent of the fuel input energy is converted to

electricity and 67 percent is exhausted as waste

heat). If only half of the waste heat from these

plants were used, the energy output would double (IS).

Table 46 shows the distribution and maximum

temperature of waste heat sources in a supercharged diesel engine. As shown in this table,

Table 4&—Distribution of Waste Heat From a

Supercharged Diesel Engine

Percent of Maximum

total waste temperature

Heat source heat (Fo

)

. ,

Engine cooling jacket . . . . . . . . 20 165-171

Aftercoolers a. . . . . . . . . . . . . . . . 15 104-111

Lubrication system . . . . . . . . . . 10 140-150

Exhaust gasb. . . . . . . . . . . . . . . . 55 797-696

aAftercoolers 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 Untapped Energy Source,” Public Power January-February 1981.

most of the waste heat is in the exhaust gases.

The engine cooling jacket and lubrication system

together produce almost as much waste heat as

the exhaust gases, but at a much lower temperature (15).

The hot exhaust gas from an existing powerplant fueled with natural gas can be used directly in a waste heat boiler. Alternatively, water can

be preheated via heat exchange with the aftercoolers, lubrication system, and cooling jacket,

then flashed into dry steam through heat exchange with the exhaust gas. Steam temperatures

as high as 850° F can be obtained in this manner (15).

For on-farm systems, a small powerplant (with

direct heat recovery or steam production, as described above) could be connected with an anaerobic digester (using animal wastes as the feedstock) producing biogas, or with a small gasifier

that converts biomass (e.g., crop residues) to lowor medium-Btu gas. However, as described in

chapter 4, further development of combustion

turbine or internal combustion engine technol-
Ch. 5—industrial, Commercial, and Rural Cogeneration Opportunities . 211

ogy may be necessary if these systems are to operate efficiently for long periods of time with lowor medium-Btu gas derived from lower quality

feedstocks.

Potential Applications

Ethanol production is one promising application for rural cogeneration. Ethanol has been

shown to be a useful fuel for spark ignition engines, and it can be produced readily from renewable biomass feedstocks (e.g., grains and sugar

crops). If ethanol is used as an octane-boosting

additive in gasoline, and if the ethanol is distilled

without the use of premium fuels, then each gallon of ethanol can displace up to about 0.9 gallon

of gasoline. However, if ethanol distilleries are

fueled with oil, then ethanol production for gasohol could actually mean a net increase in oil use. *

Moreover, the premium fuels usually considered

for ethanol distilleries–diesel fuel and natural

gas–already are used widely in the agricultural

sector but often are in short supply. Using these

fuels in distilleries could aggravate any shortages.

One way to improve ethanol production’s premium fuels balance is to cogenerate with existing

small rural powerplants. The waste heat would

be flashed into dry steam (as described above),

and the steam distributed into the distillation columns of the ethanol recovery system. To facilitate

cooking (the process stage where starch grains

are ruptured for effective enzymatic action),

steam above atmospheric pressure and at about

300° F can be bled from the exhaust gas heat exchanger. In addition, warm water can be bled

from the aftercooler heat exhanger to soak the

milled corn and speed up water absorption. Finally, heat for drying wet stillage into distillers dried

grain (which can be used as a livestock feed supplement) can be obtained either directly from the

exhaust gas in a natural gas-fired plant, or by placing an air-to-exhaust gas heat exchanger downstream from the steam-producing heat exchanger

(15). Figure 59 shows a schematic of ethanol cogeneration with diesel engine heat recovery.

The waste heat from a 1 -MW powerplant operating 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 of

anhydrous ethanol per year with wet byproduct,

or 300,000 to 400,000 gallons annually with dried

distillers grain byproduct (15).

Cogeneration also can be used for grain drying, which requires relatively low-temperature

heat. Seed drying requires a temperature of approximately 110° F, while milling drying requires

130° to 1400 F depending on the crop, and animal feed drying needs around 180° F. These

temperatures are well below those of exhaust

gases, and thus, for grain drying, the exhaust gas

of natural gas-fired powerplants can be mixed

with flush air and used directly (i.e., without heat

exchangers). For plants that use fuels other than

natural gas, a heat exchanger may be required

in order to recover the energy without contaminating the grain with the exhaust gas. Due to the

low temperatures needed, waste heat from the

cooling water or lubrication oil also can be recovered and used to dry grain (15).

The waste heat from a 1-MW powerplant could

dry grain at a rate of approximately 370 bushels

per hour. In the case of field-shelled corn, this

would reduce the moisture content from around

25 to about 15 percent—a safe level for storage.

That grain-drying rate is comparable to that of

many commercial dryers, and is sufficient for the

grain-drying needs of small communities (1 5).

However, grain drying is a seasonal activity and

other uses for the waste heat would have to be

Photo credit: Department of Agrlculture

Small existing powerplants can be retrofitted for

cogeneration with the thermal output used for applications

such as drying grain
212 . Industrial and Commercial Cogeneration

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 grain

drying using existing powerplants will cost only

slightly more than a conventional grain drying

facility. A relatively small additional investment

would be required for the engineering design

needed to interface the exhaust stacks (or heat

exchanger) with the drier. The grain drying would

need flexible scheduling in order to coordinate

with the powerplant’s operation, especially when

expected electricity demands do not materialize,

but this is a relatively minor inconvenience. A

more important concern is that rural grain elevators usually have low priority or interruptible service from natural gas suppliers (unless they use

propane). Any resulting shutdowns can be a serious problem during a harvest season that is wet

and cold, because the grain could spoil before

it can be dried.

Drying crops with cogeneration can have significant dollar and fuel savings advantages. If the

cost of waste heat is set at so percent of the cost

per Btu for natural gas, then a facility drying 500

bushels of grain per hour would save $11.25 per

hour 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 for

continuous operation, and the fuel cost savings

would amount to $7,000 per month (1 5).

Wood drying is similar in many respects to

grain drying. Both commodities are dried prior

to shipping to minimize moisture weight. Historically, both drying processes have relied on relatively cheap and plentiful natural gas supplies,

but can do so no longer. Furthermore, most

wood drying kilns, like grain drying facilities, require relatively low-temperature heat–104° to

117° F–although a few kilns may need temperatures above 212° F (1 5).

Because most modern wood drying kilns use

natural gas combustion units, the exhaust gas

from a small powerplant can be substituted easily

for the natural gas burner. A 1-MW powerplant

will produce approximately 8,000 MWh of usable

drying heat annually (based on 24 hours per day,

330 days per year operation). This is sufficient to

dry as much as 11 million board feet of air dried

hardwood or 6.5 million board feet of green softwood per year.

As with grain drying, substantial savings can be

gained through cogeneration/wood drying. Because the basic design would not change in a

cogeneration retrofit, the capital and installation

costs of a cogenerating unit would not be substantially more than those of a new conventional

gas-fired kiln. It is estimated that 2 to 5 MCF of

natural gas would be saved for each 1,000 board

feet of lumber that is dried with cogeneration.

For the 1-MW powerplant drying 11 million

board feet, this would mean a savings of 22000

MCF/yr. If the cogenerated heat were sold at 50

percent 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 electricity generation.

Fuel Savings

The three rural cogeneration applications described above—producing ethanol and drying

grain or wood–rely on existing small powerplants fueled with oil or natural gas. In each case,

fuel savings is assumed to result when the plant’s

waste heat is recovered and substituted for a second oil- or gas-fired facility. However, as discussed earlier in this chapter, the fuel saved may

not always be oil. For example, recovering the

waste heat from a diesel oil fueled engine and

substituting it for heat previously provided by a

natural gas combustion unit will save gas but increase oil consumption. Similarly, if the waste

heat from a spark-ignition engine burning oil is

substituted for a boiler using coal or biomass, no

oil would be saved.

As a result of these fuel use considerations, rural

cogeneration opportunities that use fuels other

than oil (i.e., that do not rely on waste from an

existing powerplant) merit a good deal of attention. These opportunities are based on the direct

firing of cogenerators with fuels derived from

plentiful rural resources.

Wood wastes have long been the traditional

fuel in the forest products industry, which historically has been the largest industrial—and rural—

cogenerator. The cogeneration potential in the

forest products industry was discussed earlier in

this chapter. At this point it will be sufficient to

mention that, in the wood drying example cited

above, a steam turbine and boiler can be substituted for the powerplant and natural gas-fired

kiln. Although the capital costs of the boiler

system would be higher (about one boiler horsepower is needed to dry 1,000 board feet of hardwood), and it would not produce as much electricity, this system can burn wood wastes or coal

and thus save oil or natural gas. Similarly, fuel

savings in ethanol distilleries will be greater if coal

or biomass is used as the primary fuel for the

cogenerator. Savings also can be achieved in

grain drying but the potential for contaminating

the grain would be greater unless heat exchangers

were used.

Alternatively, internal combustion engines or

gas turbines can be adapted to alternate fuels.

These technologies, if successful, would require

a smaller investment for equipment than steam

turbines, an important consideration for small dispersed cogenerators. In some cases, fuel flexibility

can be achieved through advanced engine design, advanced combustion systems such as fluidized 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 with

combustion turbines or internal combustion engines are discussed in detail in chapter 4. Two

applications that are especially promising for rural

areas include gasification of crop residues and

anaerobic digestion of animal wastes. However,

small powerplants also can be modified to accommodate alternate liquid fuels such as ethanol

and methanol, which can be made from relatively

plentiful rural biomass resources; these liquid fuel

options are discussed in more detail in OTA’s

report on Energy From Biological Processes.

Gasification of crop residues has been suggested as a means of providing relatively cheap

nonpremium fuels for rural cogenerators. One

demonstration project being developed in lowa

uses downdraft gasifiers to produce low-Btu gas

from corn stover for use in retrofitted diesel engines. Some of the probable end uses for the thermal energy include grain drying, green houses,,

dairies, food processing, space heating, or drying the corn cob feedstock (22).

Downdraft gasifiers were selected for this project because they can generate producer gas that

has relatively low amounts of tars and other hydrocarbons and is suitable for use in steam generators, directly fired dry kilns, or internal combustion engines. Field tests with downdraft gasifiers in California have produced diesel quality

producer gas successfully from corn cobs, walnut

shells, and other crop residues (32).

The demonstration project focuses on stationary diesel engines for several reasons. First, the

wide number of domestic diesel models in place

allows a range of retrofit considerations to be

evaluated. Second, a number of tests are underway around the country using dual-fuel diesels

fired with 80 percent producer gas and 20 percent diesel oil. European firms have offered efficient commercial producer gas/diesel packages

capable of continuous operation on 90 percent

gas/10 percent diesel oil since World War 1.

Third, a large number of functional diesel powerplants are standing idle because of high oil prices.

A recent survey showed that more than 70 lowa

communities have diesel generators with a total

capacity of over 300 MW that operate at an average capacity factor of less than 2 percent (22).

Finally, the projects will use corn cobs as the

feedstock 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 and

store. * Other possible biomass gasification combinations for cogeneration include other types of

organic wastes (e.g., crop residues, wood waste)

and wood from excess commercial forest production or intensively managed tree farms.

Cost estimates for this project are shown in

table 47. Two rural test sites designed to demon-

*For an in-depth analysis of the technical, economic, and environmental considerations related to the use of crop residues as

a fuel or feedstock, see Energy From Biological Processes

(OTA-E-124, July 1980).

Table 47.—Model Community Gasification/Diesei

Eiectric Generation Energy Cost Estimate

Operating data from the fuel rate calculations:

Energy output: Maximum, 1,000 kW; average, 750 kW

Gas input for electrical powec 10.18 MMBtulhr

Solid fuel input for electrical power: 1,810 Ib/hr

Fuel 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 . . . . . . . . . . . . . . . . . . $259,610

Installation . . . . . . . . . . . . . . . . . . . . . . 64,800

Capital cost total . . . . . . . . . . . . . . . . . 324,410

Annualized at 5°/0 for 20 years . . . $33,670

Diesel retrofit @ $150/kW . . . . . . . . . 150,000

Annualized at 8.25% for 20 yrs. . . 15,564

Insurance 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 cost

6,570 hr/yr, operating at 75°/0 capacity:

Fuel handler, 1 person, 40 hr/wk, w/fringes . . . . . 31,200

Maintenance charge @ 5°/0 of plant cost . . . . . . . 16,200

Fuel costs:

Diesel oil @ $1.15/gal x 38,716 gal . . . . . . . . 44,523

Corn cobs at 18.80/T x 5,979 T/yr . . . . . . . . . 112,400

Total operational costs . . . . . . . . . . . . . . . . . . . . $204,323

6.57 MMkWh/yr, operational costs/kWh = $0.0311

Total cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . .$O.0396/kWh

Cost of hot producer gas from gasifier

Operating at 90°/0 capacity; with gas conversion efficiency

of 850/o

1,810 lb cobs/hr x 8,760 hr x 0.90 = 7,135 T/yr @

$18.80~ = (fuel) . . . . . . . . . . . . . . . . . . . . . . . . $134,138

Labor, maintenance, amortization, Insurance. . 87,560

Total cost. .$221,698(7,135 T cobs x 15 MMBtu x 0.85

efficiency) = $2.441 MMBtu

SOURCE: J. J. O’Toole, et al., “Corn Cob Gasification and Diesel Electric Generation,” in Energy Technology VIII: New Fuels Era Richard F. Hill (cd.)

(Rockville, Md.: Government Institutes, Inc., 1981).
Ch. 5—industrial, Commercial, and Rural Cogeneration Opportunities . 215

strate the technical and economic feasibility of

downdraft gasifiers using corn cobs to produce

low-Btu gas for diesels have been identified. The

sites (in Iowa) have different diesel models and

usage patterns as well as different biomass resource concentrations (one town has a local

source of excess corn cobs, one must set up a

collection and transportation system on neighboring farms). Thus, the sites will allow a sensitivity

analysis on a wide range of variables, including

energy prices, Btu value, moisture content, farmer participation rate, and cob processing costs.

Economic modeling for the project will yield data

on agricultural production for the site, the quantity of cobs used, the system kWh costs, emissions, and energy balance. If these and other tests

yield positive results, then gasification of crop

residues could become an important source of

energy for diesel cogeneration in rural communities—one that enables those communities to use

existing local resources and equipment at a cost

competitive with energy from central station

powerplants.

A second rural cogeneration option is the anaerobic digestion of animal wastes to produce

biogas (a mixture of 40 percent carbon dioxide

and 60 percent methane). The national energy

potential of wastes from confined animal operations is relatively low—about 0.2 to 0.3 Quad/yr–

but other important benefits are that anaerobic

digestion also serves as a waste treatment process and the digester effluent can be used as a soil

conditioner, or dried and used as animal bedding,

or possibly treated and used as livestock feed.

Digesters for use in cattle, hog, dairy, and poultry

operations are now available commercially and

are being demonstrated at several sites in the

United States. * Wastes from rural-based industries (e.g., whey from cheese plants) also are being used as a feedstock for farm-based digesters.

In a typical digester system (see fig. 60), a settling pond is used to store the manure prior to

digestion. The digester consists of a long tank into

which the manure is fed from one end. After several weeks, the digested manure is released at

the 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

SOURCE: Office of Technology Assessment.

Gas exits from the top of the digester tank, the

small hydrogen sulfide content is removed if necessary, and the biogas is used to fuel an internal

combustion engine that drives an electric generator. The system supplies electricity for onsite use

(or for export Off-Sit@. The heat from the engine

can be used onsite for a variety of purposes, including heating the animal shelter or a greenhouse (that could also use the soil conditioning

effluent), or for crop drying, or even residential

space heating.

Finally, it should be noted that the above applications can be combined in farm energy complexes that integrate methane and alcohol systems so that waste heat and byproducts are utilized more fully. For example, the waste heat

from generating electricity with biogas can be

used in alcohol production, while spent beer

from the distilling process can be used as a digester feedstock. Moreover, the waste heat from

a generator often is used to help maintain an

optimum digester temperature.

Summary

Significant energy and economic savings can

be achieved with cogeneration in rural areas.

Communities can improve the economics of operating small powerplants by recovering waste

heat for use in distilling ethanol, drying grain or

wood; heating homes, greenhouses, or animal

shelters, and other applications; or by retrofitting

existing powerplants to accommodate alternate
216 Industrial and Commercial Cogeneratlon

fuels. In addition, significant oil savings can be economy rather than being recirculated to proachieved if the cogenerator uses alternate fuels duce a second round of local income. Developor replaces two separate oil-fired systems. ing cogeneration opportunities could double the

Although the rural cogeneration potential is not productive 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 thermal the cost and fuel savings can be very important

for farms and rural communities. in rural econo- energy sales) and private income (from new jobs)

mies, much of the gross income escapes the local without increasing the base demand of energy.

1.

2.

3.

4.

5.

6.

7.

8.

9.

10.

11.

12.

American Gas Association, An Energy and Economic Analysis of Gas-Fired Cogeneration in Commercial and Industrial Applications (Arlington, Va:

American Gas Association, 1981).

American Gas Association, The Gas Energy Supply

Outlook: 1980-2000 (Arlington, Va: American Gas

Association, January 1982).

Bullard, Clark, University of Illinois at UrbanaChampaign, private communication to OTA.

California Energy Commission, Commercial Status: Electrical Generation and Nongeneration

Technologies (Sacramento, Calif.: California Energy Commission, P102-8O-OO4, April 1980).

California State Department of Water Resources,

et al., Cogeneration Blueprint for State Facilities

(Sacramento, Calif.: Department of Water Resources, March 1981).

DOW Chemical Co., et al., Energy Industrial Center Study (Washington, D. C.: National Science

Foundation, June 1975).

Energy Information Administration, Analysis of

Economic Effects of Accelerated Deregulation of

Natural Gas Prices (Washington, D. C.: U.S. Government Printing Office, August 1981).

Energy Information Administration, Annual Report

to Congress, Volume Two (Washington, D. C.:

U.S. Government Printing Office, April 1981).

Energy Information Administration, Typical Electric Bills, January 1, 1980 (Washington, D. C.: U.S.

Government Printing Office, December 1980).

Exxon Corp., Energy Outlook 1980-2000 (Houston: Exxon Corp., December 1980).

“Gasification Plant Finds Private Aid,” The New

York Times, Dec. 14, 1981.

General Energy Associates, Industrial Cogeneration Potential: Targeting of Opportunities at the

P/ant Site (Washington, D. C.: U.S. Department of

Energy, 1982).

13.

14,

15.

16.

17.

18

19.

20.

21

22.

23.

Harkins, William, testimony before the New York

Public 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, “Rural

Cogeneration: An Untapped Energy Source,” Pub

lic Power, January-February 1981.

North American Electric Reliability Council, Electric Power Supply and Demand 1981-1990

(Princeton, N.J.: North American Electric Reliability Council, July 1981).

Office of Technology Assessment, U.S. Congress,

Application of Solar Technology to Today’s Energy

Needs, OTA-E-66 (Washington, D. C.: U.S. Government 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 Office, 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. Government

Printing Office, March 1980).

Office of Technology Assessment, U.S. Congress,

Residential Energy Conservation, OTA-E-92

(Washington, D. C.: U.S. Government Printing Office, July 1979).

Office of Technology Assessment, U.S. Congress,

Synthetic Fuels for Transportation, OTA-E-185

(Washington, D. C.: U.S. Government Printing Office, September 1982).

O’Toole, J. J., et al., “Corn Cob Gasification and

Diesel Electric Generation,” in Energy Technology

V///: New Fuels Era, Richard F. Hill (cd.) (Rockville,

Md.: Government Institutes, Inc., 1981).

Resource Planning Associates, Inc., The Potential

for Industrial Cogeneration Development by 1990
Ch. 5—industrial, Commercial, and Rural Cogeneration Opportunities 217

(Cambridge, Mass.: Resource Planning Associates,

1981 ).

24. Resource Planning Associates, Inc., The Potential

for Cogeneration Development in Six Major Industries by 7985 (Cambridge, Mass.: Resource Planning Associates, Inc., December 1977).

25. Rosenthal, Arnold, Consolidated Edison Co. of

New York, private communication to OTA.

26. Schlesinger, Ben, American Gas Association, private communication to OTA.

27. Solar Energy Research Institute, A New Prosperity (Andover, Mass.: Brick House Publishing Co.,

Inc., 1981).

28. SRI International, et al., Draft Environment/ Impact Statement, Small Power Production and Cogeneration Facilities–Qualifying Status/Rates and

Exemptions (Washington, D. C.: U.S. Government

Printing Office, FERC/EIS-0019/D, June 1980).

29. Synergic Resources Corp., Industrial Cogeneration

Case Studies (Palo Alto, Calif,: Electric Power Research Institute, EPRI EM-1531, 1980).

3 0

31

32

33.

34.

35.

Thermo Electron Corp., A Study of Inplant Electric Power Generation in the Chemical Petroleum

Refining and Paper and Pulp Industries (Waltham,

Mass.: Thermo Electron Corp., TE5429-97-76,

1976).

U.S. Department of Energy, Month/y Energy Review (Washington, D. C.: U.S. Government Printing Office, February 1982).

Williams, R. O., and Lang, R. C., “Fuel From

Waste Products,” Food Engineering October

1979.

Williams, Robert H., “Industrial Cogeneration,”

3 Annual Review of Energy 313-356 (Palo Alto,

Calif.: Annual Reviews, Inc., 1978).

Williams, Robert H., Princeton University, private

communication to OTA, February 1982.

Williams, Robert H., Princeton University, “Biomass Cogeneration as a Major Option in the Swedish Context, ” draft report, October 1982.
Chapter 6

Impacts of Cogeneration

.
Contents

Page

Environmental Effects of Cogeneration . . . . . . 221

Characteristics of Cogeneration Systems and

Their Effects on Air Quality . . . . . . . . . . . . 221

Emissions Balances: Cogeneration v.

Separate Heat and Electricity. . . . . . . . . . . 229

An Air Quality Analysis of Urban Diesel

Cogeneration. . . . . . . . . . . . . . . . . . . . . . . . 231

Emission Controls. . . . . . . . . . . . . . . . . . . . . . 233

Health Effects From Cogenerator

Emissions. . . . . . . . . . . . . . . . . . . . . . . . . . . 236

Effects of Some Cogeneration Technology/

Fuel Options . . . . . . . . . . . . . . . . . . . . . . . . 238

Policy Options: Removing EnvironmentAssociated Regulatory Impediments . . . . . 239

Other Potential Impacts. . . . . . . . . . . . . . . . . 241

Potential Regulatory Burden on

Environmental Agencies . . . . . . . . . . . . . . . 242

Environmental Permitting and Enforcement

Agencies . . . . . . . . . . . . . . . . . . . . . . . . . . . 242

Potential Impacts on Agency Caseloads. . . . 244

Summary. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 246

Economic and Sociall Implications . . . . . . . . . . 246

Economic Impacts . . . . . . . . . . . . . . . . . . . . . 247

Utility Planning and Regulation ., .....*.* 254

Other Economic and Social Impacts . . . . . . 257

Centralization and Decentralization of

Electricity Generation . . . . . . . . . . . . . . . . . 259

Chapter 6 References . . . . . . . . . . . . . . . . . . . . 263

Tables

Table No.

48. Effect of Cogeneration Characteristics on

Air Quality. . . . . . . . . . . . . . . . . . . . . . . . . . 222

49. Uncontrolled Emissions of Competing

Combustion Technologies Using the

Same Fuel, in Pounds/MMBtu Fuel Input . 223

50. Maximum Size Cogenerator Not

Requiring New Source Review . . . . . . . . . 226

51. Selected Emissions Balances for

Cogeneration Displacing Central Power

Plus Local Heat Sources. . . . . . . . . . . . . . . 231

52.

53.

54.

554

56.

Page

Summary of NOX Emission Control

Techniques for Reciprocating IC Engines . 234

NOX Control Techniques that Achieve

Specific Levels of NOX Reduction . . . . . . . 235

Costs of Alternative NOX Controls for

Diesel Cogenerators . . . . . . . . . . . . . . . . . . . 235

Emissions From Oil- and Coal-Fired

Diesels . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 238

Approximate Costs of procedures

Required Under the Clean Air Act . . . . . . 240

57. Penetration Scenario for Cogeneration in

California and Colorado . . . . . . . . . . . . . . . 244

58. Increase in Agency Workloads Due to

the Deployment of Cogeneration

Technologies in Colorado. . . . . . . . . . . . . . 245

59. Increase in Agency Workloads Due to

the Deployment of Cogeneration

Technologies in California . . . . . . . . . . . . . 246

.60. Market Penetration Estimates for

Cogeneration . . . . . . . . . . . . . . . . . . . . . . . . 248

61. Scenarios for Cogeneration

62

63

64

Implementation . . . . . . . . . . . . . . . . . . . . . . . 249

Assumptions Used to Compare Capita!

Costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 250

Comparison of Capital Requirements . . . . 251

Assumptions Used in Estimating

Operating and Maintenance Costs. . . . . . . 251

65. Comparison of Operating and

Maintenance Costs . . . . . . . . . . . . . . . . . . . 252

66. Comparison of Construction Labor

Requirements. . . . . . . . . . . . . . . . . . . . . .. ..253

67. Craft Requirements for Central Station

Powerplant Construction . . . . . . . . . . . . . . 254

68. Estimated Operating and Maintenance

Labor . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 254

69. Pacific Gas & Electric Cost Structure

Adjusted for PURPA, 1990 . . . . . . . . . . . . . 256

Figures

Figure No..

61. CWE Fixed Cost Structure as a Function

of Sales Growth. . . . . . . . . . . . . . . . . . . . . . 256
Chapter 6

Impacts of Cogeneration

ENVIRONMENTAL EFFECTS OF COGENERATION

The major environmental issue that has arisen

from the promotion and deployment of cogeneration technologies concerns whether the

widespread use of cogeneration may lead either

to improved or degraded air quality. This issue

is especially critical in urban areas, where air

quality may not be in compliance with national

ambient standards or where the allowable margin

for additional emissions may be small. A corollary

issue, also critical for urban areas, concerns the

relative value of promoting cogeneration by easing environmental standards. Examples of suggested regulatory changes designed to favor

cogeneration include basing emission standards

on energy output rather than (currently used) fuel

input, * and awarding emissions “offsets”**

created by the cogenerator’s substitution of

cogenerated electric power for utility-generated

electric power. Clearly, the issues are interconnected, because cogeneration’s effect on air

quality will provide a powerful argument for or

against any changes in environmental standards.

This analysis of the environmental effects of

cogeneration focuses on these air quality issues,

with a final section devoted to other potential impacts (such as noise). First, cogeneration is characterized according to a list of attributes that affect air quality. These attributes are then discussed qualitatively and, to the extent possible,

quantitatively. Next, a series of cogeneration applications are evaluated to determine their “emissions balances:” the net emissions increases or

decreases in the total system (the utility grid plus

local heat and electricity sources), and the net

changes at the cogenerator site. Then, an evaluation of an existing air quality study of cogeneration is presented, followed by discussions of emis-

*Because a cogenerator produces more usable energy per unit

of fuel consumed than a similarly sized electric generator using the

same technology, an output-based standard would allow the cogenerator to emit more pollutants per unit of fuel consumed and

thus incur lower pollution control costs.

**New sources attempting to locate in an area that has not attained Federal ambient standards must obtain pollution “offsets”

(i.e., reduced emissions), from existing sources in the area so as

not to increase total emissions.

sion controls and the health effects of exposure

to the major pollutants emitted by cogenerators.

The air quality evaluation concludes with a discussion of the potential air quality concerns associated with advanced cogeneration technologies and an analysis of some suggested policy options for promoting cogeneration by easing environmental regulations. The chapter ends with

a discussion of other potential impacts of

cogeneration, including water discharges, solid

waste disposal, noise, and cooling tower drift.

Characteristics of Cogeneration

Systems and Their Effects on Air Quality

The deployment of cogeneration systems may

involve a number of changes in the physical characteristics of electricity generation and (useful)

heat or steam production. These physical changes

may, in turn, alter the magnitude and dispersion

characteristics of emissions from these activities.

The result will be a change in air quality.

At a minimum, cogeneration will increase fuel

efficiency by replacing separate devices producing either electricity or thermal energy with a

single device providing both. Thus, less fuel

would have to be burned to produce the same

energy. Cogeneration may involve merely the addition of waste heat capturing equipment to existing electric generators, or the addition of turbines to existing steam producers; in this case,

cogeneration technology is different from only

one of the separate technologies. However, many

cogeneration systems use technologies different

from both the separate electricity generator and

heat or steam producer. Cogeneration systems

generally are different in scale from separate

electricity and thermal energy systems; for virtually all applications except simple additions of

waste heat recovery equipment, they are smaller

in scale than the central electricity generating

systems they substitute for, and in many applications they are larger in scale than the thermal

energy systems. Cogeneration systems often use

221
—

222 ● Industrial and Commercial Cogeneratlon

a different fuel from either or both systems they

replace, and often they have a different location–usually closer to the electricity demand

source, at times slightly farther away from the

thermal demand sources.

Table 48 summarizes the separate impact on

air quality of each of these cogeneration characteristics, assuming all other factors remain the

same. For example, a reduction in fuel burned

will lead to decreased emissions and improved

air quality if everything else remains the same.

Usually, however, lots of things have changed.

For example, the substitution of several small

cogenerators for a central power station may

imply:

●

●

●

●

●

fewer controls, because most regulations increase in stringency as size increases;

lower stacks, which have greater impacts on

ground level air quality per unit of emission;

dispersal of powerplant emissions sources–

i.e., more sources with lower emissions from

each separate source;

different technology-e. g., diesels instead of

fossil boilers and gas-fired furnaces;

use of a different fuel—e.g., diesel fuel used

instead of coal and natural gas.

The complex mixture of effects in this example

and in table 48 implies that cogeneration as a

general concept cannot be characterized easily

as environmentally beneficial or adverse. A more

detailed exploration of cogenerator characteristics is necessary in order to identify those circumstances where the environmental value of cogeneration can be defined less ambiguously.

Increase in Fuel Efficiency

As noted above, all near-term cogeneration applications involve the use of a fuel burning technology that produces both electricity and thermal energy, and that substitutes for a separate

electric generator and thermal system. Although

most applications involve a change in the scale

of electricity generation (from central station to

inplant generation) and many involve a basic

technology change as well (e.g., steam turbines

to diesels), combining the production of both

electric and thermal energy in one unit creates

a substantial energy savings by itself. For example, using a diesel cogenerator in place of a diesel

electric generator and an oil-fired furnace can

reduce total fuel use by at least 25 percent if

three-quarters of the potentially usable heat can

Table 48.–Effect of Cogeneration Characteristics on Air Quality

Effect on air quality

Technological characteristic Direct physical effect (positive or negative)

1. Increased efficiency Reduction in fuel burned Positive

2. Change in scale (usually Change in pollution control Negative for electrica

smaller for electric generation, requirements (stringency Positive for heat

at times larger for heat/steam increases with scale)

production) Change in stack height and Negative for electric

plume rise (increases with Positive for heat

scale)

Changes in design, combustion Mixed

control

3. Changes in fuel combustion Changes in emissions Mixed

technology production, required controls,

types of pollutants, physical

exhaust parameters

4. Change of fuels Change in emissions Mixed

production, type of

pollutants

5. Change of location (most often Change in emissions density Mixed

for electric generation) and distribution—electric

power more distributed, heat/

steam may become more

centralized

aThe air quallty effect of replacing the electric power component of the conventional system with the electric component

of the cogeneratlon ayetem is negative.

SOURCE: OffIce of Technology Assessment.
Ch. 6—Impacts of Cogeneration .223

be recovered* (11). Similar savings can be

achieved by using a gas turbine cogenerator in

place of a gas turbine electric generator and a

separate furnace. Substitution of a steam electric

cogenerator for a steam electric generator and

separate low-pressure steam boiler can reduce

fuel use by 15 percent (42).

Such substitutions may lead to substantial reductions in total emissions because they eliminate

emissions from the heat source. For example, a

diesel cogenerator could reduce sulfur oxide

(SOX) emissions by about 0.1 Ib for every 100 kilowatthours (kWh) of electricity it generated, by

displacing oil heat using 0.2 percent sulfur distillate oil. Similarly, a gas turbine cogenerator

could reduce nitrogen oxide (NOX

) emissions

from a displaced oil-fired industrial boiler by 0.3

lb/loo kWh (see app. B for emissions information). In some cases, however, fuel used–and

thus emissions generated—by the cogenerator to

produce thermal energy and electricity may be

greater than for electricity generation alone, and

theoretically total emissions could increase if the

separate thermal system that is displaced were

a particularly clean one. A coal or residual oilfired steam turbine that was used for both electricity and space or process heat, for example,

would add to total SOX emissions if it replaced

a similarly fueled electric generator and a separate

heat system that used gas or low sulfur distillate

oil.

Aside from any benefits attained by reducing

emissions at the fuel combustion source, the

cogenerator should be credited with environmental benefits from the remainder of the fuel cycle—

i.e., the benefits of extracting, refining, and

transporting less fuel. For example, reducing the

use of oil for heating is most likely to reduce the

impacts of importing and refining crude oil and

transporting the refined product from refinery to

market area. These impacts include spills of the

crude and refined product and a number of pollution problems generally associated with refineries.

These benefits must be balanced by any negative

effects related to increased fuel transportation requirements for multiple cogeneration units.

● The reduction is 27 percent assuming a heat rate for the diesel

of 10,700 Btu/kWh, potentially recoverable heat of 4,300 Btu/kWh,

furnace efficiency of 80 percent.

Quantification of these costs and benefits is not

attempted in this report, but it is important not

to forget that they exist. In fact, as the more accessible fuel reserves become exhausted and extraction becomes more difficult and potentially

more damaging, the magnitude of the potential

benefits will grow.

Different Technology and Fuel

Although the alternative to a cogeneration system can be the identical electricity generating

technology (without heat recovery) with a separate thermal energy source (boiler or furnace),

often a cogeneration system replaces a completely different (usually large-scale centralized) electric generation technology. A common example

is a cogenerator with diesel or gas turbine technology being used in place of electricity supplied

by a central oil- or coal-fired steam or nuclear

steam generating plant. Also, the smaller cogeneration systems typically use cleaner fuels (distillate oil or natural gas) than central station fossil

plants (coal or residual oil). The technological and

fuel differences both create sharp differences in

emissions rates.

Table 49 displays typical levels of uncontrolled

emissions from the three major competing cogeneration technologies; the steam turbine also

represents the technology used in most central

station powerplants. Although the same fuel is

assumed, there are substantial differences in

NOX and carbon monoxide (CO) emissions, and

small differences in particulate and hydrocarbon

emissions. The magnitude of uncontrolled SOX

emissions is not technology-dependent because

essentially 100 percent of the sulfur in the fuel

is converted to SOX regardless of the technology.

Table 49.—UncontroIled Emissions of Competing

Combustion 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 0.20

Gas turblneb. . . . . . . 0.90 0.02 0.04 0.20

Steam turbinec. . . . . 0.16 0.01 0.04 0.01 0.20

aBased on sales-weighted averages for large-bore dlesels, in Environmental protection Agency (39).

bBased on Environmental Protection Agency (40) and particulate emissions data

from a GE 7821B combustion turbine.

cBased on Environmental ProtectIon Agency (38).

SOURCE: Office of Technology Assessment.
224 . Industrial and Commercial Cogeneration

A shift from central station electricity to diesel

or gas turbine generation generally will be accompanied by a substantial increase in NO-X emissions. CO emissions also will increase significantly

with diesel generation. As discussed later, however, significant differences in efficiencies and

emission rates among diesels and gas turbines of

different sizes, configurations, and manufacturers

make it imperative that considerable caution be

used in applying “average” emission factors and

efficiencies to analyses of cogeneration impacts.

Aside from their relatively high levels of NOX

and CO emissions compared to alternative combustion technologies, diesel cogenerators face the

additional problem of producing particulate emissions that appear to have a possibility of causing

adverse health effects because of their chemical

makeup. The potential effects of these particulate are discussed below in the section on

health effects.

Diesel and gas turbine cogenerators must use

cleaner fuels (primarily distillate oil or natural gas)

than those burned in fossil-fueled powerplants

(generally coal or residual oil), yielding emission

benefits to the cogenerators. * Natural gas, for example, contains virtually no sulfur, and distillate

oil may contain only 0.1 or 0.2 percent sulfur

compared with more typical 1 percent sulfur

residual oil and 1 to 5 percent sulfur coal; SOX

emissions are roughly proportional to these

percentages. Although scrubbers will be used on

newer utility powerplants, substantial differences

among technologies in expected SOX emissions

will remain.

Fuel choice is also important for particulate and

NOX emissions, even though widely required particulate controls may eliminate some of the differences for particulate. The differences in uncontrolled industrial steam turbine NOX emissions for coal, oil, and natural gas are displayed

below:

*However, if use of these fuels were supply limited, then their

use by cogenerators would have to be balanced by the withdrawal

of supply from an alternative combustion source. At the moment

there is no such limitation.

NO, emissions (lb/MMBtu) (38):*

Coal (bituminous) . . . . . .....0.60

Oil (residual) . . . . . . . . . .....0.40

Gas ., . ...................0.1 7

Because some large diesels (e.g., those in

marine applications) use residual oil, and others

are being developed that can use coal as well,

some of these “clean fuel benefits” may disappear in the future as cogenerators begin to use

the same types of fuels as the powerplants they

displace.

Finally, fuel choice dictates the costs and benefits associated with eliminating the environmental effects of exploring for, extracting, refining and

transporting the fuel used in the (displaced) conventional system, and adding these effects for the

cogenerator fuel. Although many cogeneration

systems use natural gas and oil, which may have

fewer than or the same noncombustion environmental costs per unit of energy as fuels used in

central station powerplants, cogeneration systems

based on steam turbines may use coal and displace oil and natural gas. In these cases, cogeneration’s net environmental benefit associated

with the noncombustion portion of the fuel cycle

may be negative even though total energy usage

has decreased, because of the relatively greater

adverse impacts of coal mining and transportation.

Change in Location and Scale

Even when fuel type, technology type, and efficiency are not considered, the substitution of

several smaller energy producers for one or a few

large producers can have substantial air quality

impacts. Control requirements will vary with the

size of the equipment, resulting in changes in

total emissions, while the substitution of several

more widely distributed, smaller smokestacks for

a few large ones will change the dispersion of

those emissions. Poor enforcement of control

compliance for the dispersed system (due to the

multiplicity of sources and the limited local en-

*Large commercial and general industrial boilers (10 to 100

MMBtu/hr), bituminous coal heat content 25 MMBtu/ton.
Ch. 6—Impacts of Cogeneration . 225

forcement capabilities of regulatory agencies) also

may affect air quality. Of course, to the extent

that the cogenerators may represent a centralization of heat production (e.g., in a total energy

system for an apartment complex that replaces

multiple small heating units), these effects may

be reversed.

In general, control requirements for energy production technology become more stringent as

size increases. Many cogenerators will be controlled less stringently than utility generators using

the same combustion technologies, but controlled more strictly than small heating systems.

Examples of the effect of size on control requirements for each cogenerator technology are:

New steam generators and steam turbines

must comply with Federal New Source Performance Standards (NSPS) only if they are larger than

250 million Btu per hour (MMBtu/hr) fuel input

(45). * Smaller units are subject only to local and

State rules, some of which may not be so stringent. Furthermore, generators larger than this

cutoff are subject to different emission limits

depending on whether or not they are utilityoperated. New utility-operated steam generators

must achieve 90 percent SOX control for oil and

for medium to high sulfur coal, and 70 percent

for low sulfur coal, with an upper limit of 1.2

lb/MMBtu input. In addition, they are restricted

to 0.03 lb of particulate per million Btu input.

in contrast, new large steam generators used as

industrial cogenerators need achieve only 1.2 lb

of SOX per million Btu input and 0.10 lb of particulate per million Btu input.

New gas turbines with fuel rates greater than

about 100 MMBtu/hr must achieve 75 ppm NOX

(about 70-percent reduction from uncontrolled

levels) under Federal NSPS, whereas turbines in

the 10 to 100 MMBtu/hr range need reach only

1 so ppm (40-percent reduction) (46). The iatter

standard does not go into effect until about 1983.

Gas turbines smaller than 10 MMBtu/hr are subject only to State and local regulations (if any),

although gas turbines in this size range currently do not appear to be a likely technological

choice for cogeneration applications.

*Equivalent to about 200,000 lb of steam per hour or 25 MW

of electrical capacity.

Thus, it appears that new gas turbine cogenerators will have either emission standards equal

to those of large utility gas turbines or, for the

smaller units, half as stringent. Future improvements in the efficiency and economics of

very small gas turbines conceivably might lead,

however, to turbine cogenerators below the

NSPS cutoff and thus only subject to local emission standards.

Stationary diesels currently are not regulated

at the Federal level. The Environmental Protection Agency (EPA) has proposed new source performance standards for stationary diesels above

560 cubic inch displacement per cylinder, which

essentially includes most low- and medium-speed

diesels (less than 1,000 rpm) (39). In the absence

of the NSPS, it appears likely that most cogenerators would fall in this size range. However, it

is unclear whether the incentive of potential escape from controls might lead, upon the promulgation of a Federal emission standard, to deployment of smaller displacement diesel cogenerators. In fact, incentives to purchase such smaller

displacement diesels may precede a Federal

standard; at least one EPA regional office is

reported to be requiring control to the proposed

NSPS level even without the benefit of a formal

standard (8).

Small cogenerators could escape the effect of

additional emission limitations (beyond the Federal NSPS) in nonattainment and prevention of

significant deterioration (PSD) areas (see ch. 3).

These limitations are triggered by annual emissions of either 100 tons per year (tpy) (steam turbine) or 250 tpy (diesel and gas turbine) of any

criteria* pollutant (44). For example, a 1-MW

diesel achieving the proposed NSPS NOX level

(600 ppm or about 2.20 lb/MMBtu) (2,39) would

emit a maximum of 96 tpy of NOX even if it ran

continuously at full load. Thus, it could avoid the

nonattainment or PSD requirements, whereas a

large utility plant could not.

Table 50 indicates the size limit necessary to

avoid a nonattainment or PSD review (i.e., to emit

*A “criteria” pollutant is one that is regulated under the Clean

Air Act by a National Ambient Air Quality Standard. Current criteria

pollutants are sulfur oxides, particulate matter, nitrogen dioxide,

hydrocarbons, photochemical oxidants, carbon monoxide, and

lead.
226 . Industrial and Commercial Cogeneratlon

Table W.—Maximum Size Cogenerator Not Requiring

New Source Review

Technoloav Megawatts

Dlesels 300/0 efficient

NO, limit:

Oil-fired uncontrolled . . 1.5

Dual-fuel uncontrolled . 2.2

Proposed NSPS . . . . . . . 2.5

Gas turbines 30°A efficient

NOX limit, assuming NSPS 17.0

SOX limit:

1.O% sulfur oil . . . . . . . . 5.0

0.30% sulfur oil . . . . . . . . 16.5

0.20% sulfur oil . . . . . . . . 24.8

Steam turbines 150/0 efficient

NOX limit:

Coal-fired . . . . . . . . . . . . 7.9

Oil-fired . . . . . . . . . . . . . . 3.4

Gas-fired . . . . . . . . . . . . . 2.2

SOX limit:

0.2% sulfur oil . . . . . . . . 5.0

1.0% sulfur oil . . . . . . . . 1.0

200/0 efficient

11.5

7.5

10.8

16.3

100/0 efficient

5.6

2.4

1.6

3.3

0.7

aPlant electrical efficiency, Btu (electrlcity) 100/Btu (Input fuei).

SOURCE: Office of Technology Assessment.

less than 100 or 250 tpy of a criteria pollutant)

for a cogenerator operating at 100 percent load.

Under existing regulations, cogenerators larger

than this size also could avoid review by applying sufficient controls to reduce their emissions

to just below the limit.

The change in scale and location associated

with cogeneration replacing conventional energy

systems can have a substantial effect on the dispersion characteristics of the emissions. In some

circumstances, this change in dispersion will influence ambient air quality more strongly than

the changes in the amount of emissions. The air

quality changes, however, will depend on a variety of factors including meteorological conditions,

effective stack heights, terrain, and location of the

emissions sources. This large number of physical

factors, coupled with a wide range of technology choices, makes air quality modeling of an appropriate range of cogeneration and conventional

systems expensive, and it was not attempted.

However, by relying on existing studies and diffusion theory, some of the qualitative differences

between alternative electric and thermal energy

production systems can be described.

Although both a cogeneration-based system

and a conventional system consist of combinations of centralized and dispersed sources (the

cogeneration system usually requires central station backup), a good part of the air quality differences between the two systems can be understood by comparing the pollution effects of centralized emission sources with tall stacks to the

effects of multiple dispersed sources with shorter

stacks. This is because cogeneration installations

often are added to a large existing (conventional)

system (i.e., a utility grid and a series of localized

heat sources) and in many cases simultaneously

increase the emissions from dispersed sources*

and decrease the centralized emissions. The air

quality tradeoff between dispersed and centralized sources thus is an important determinant of

whether adding cogeneration is environmentally

preferable to maintaining the conventional system.

The air quality tradeoff between central and

dispersed sources–between a few sources with

tall smokestacks and multiple sources with relatively short stacks—is difficult to evaluate

because the tradeoff changes with local conditions. Some of the general features of the tradeoff

can be described, however, by looking at a simplified example and then showing the effects of

varying conditions, one at a time.

The simplified example considers a very large

area with a relatively flat terrain. The centralized

system is represented by a few large emission

sources with tall stacks—on the order of several

hundred feet in height. The dispersed system is

represented by many smaller sources with short

stacks scattered relatively uniformly throughout

the area. The total emissions from each system

are assumed to be equal.

As long as the area in question is very large and

the air quality is averaged over a long period—a

year, for example–striking differences in air

quality between the two systems usually will not

be seen. * The few tall stacks achieve a relatively

uniform dispersion of pollution because of their

superior diffusion characteristics; the more numerous shorter stacks achieve a somewhat sim-

● There are important exceptions to this, e.g., when the heat

source 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 prevailing 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 in

location, stack height, magnitude, and type of air emissions and can have significant impacts on air quality
228 ● Industrial and Commercial Cogeneration

ilar effect (albeit with many small peaks and

valleys in pollutant concentration levels) because

they are spread out.

The actual characteristics of the choice facing

a decision maker usually are quite different from

this idealized case. Often, the short stacks—the

cogenerators—are clustered within a relatively

small area rather than being widely scattered.

Short-term meteorological conditions may disrupt

the smooth dispersion of pollutants from tall and

short stacks in drastically different ways. When

the cogenerators are located in urban areas, their

proximity to other buildings may affect emissions

dispersion. And sometimes the tall stacks–the

central power stations—are located in a different

area from the cogenerators. Each of these conditions affects air quality and must be considered

in examining the tradeoff between cogenerators

and conventional central utility systems.

Clustering of the small sources within an urban

area makes the dispersion characteristics of a tall

stack in the same area superior to those of the

small stacks. This is because the effective area of

dispersion of a tall stack is very large, whereas

the clustering of small sources has defeated their

potential for geographically based dispersion.

Thus, a series of emission sources with relatively

short stacks—such as cogenerators—located in a

relatively small area will have a considerably

greater impact on local (average annual) air quality than a single source with a tall stack located

in the same area.

However, if the tall stack is located some distance from the cluster of short stacks, the air

quality of areas at a distance from the cluster of

small sources may show some improvement as

a result of reducing emissions from the tall stack.

In situations where the problems associated with

long-distance transport of air pollution (e.g., acid

rain) are considered to be more important than

existing local air pollution problems, a switch to

short stacks may be viewed as beneficial to overall air quality.

Short-term meteorological conditions may

substantially change dispersion characteristics

and alter the air quality tradeoffs between short

and tall stacks. Under inversion conditions, when

high levels of pollutant concentrations can result

from sources under the inversion layer, the

buoyant plume from a tall stack may be able to

punch through the inversion layer and, consequently, have minimal impact on local air quality. Emissions from lower stacks, on the other

hand, are trapped beneath the layer and are

poorly dispersed. During other conditions,

plumes from either tall or short stacks may be

forced to ground level (“fumigation”). Under

fumigating conditions, the concentration peaks

from the few large sources with tall stacks can

be considerably larger than the concentrations

possible with a series of dispersed, smaller

sources with low stacks. Fumigation conditions

include the breakup of a night-time inversion, certain kinds of shoreline wind conditions, and thermal instability causing looping plumes. Mountainous terrain can also cause powerplant plumes

to touch down. Other conditions, such as the

trapping of emissions beneath elevated inversions, may also diminish the dispersion advantages of tall stacks.

Careful siting of cogenerators can be critical

in urban situations because the unique terrain

conditions can adversely affect dispersion of

emissions. Plumes from cogenerator stacks may

be caught in aerodynamic downwashes caused

by the action of wind around neighboring buildings (or, in some cases, around the stack itself)

and cause high pollutant concentrations in the

immediate area of the stack. In addition, the

plume may impinge on surrounding buildings,

especially if they are taller than the stack or fairly close to it.

Pollutant concentrations caused by this “urban

meteorology” may be much higher—perhaps by

an order of magnitude or more—than predicted

by models assuming unobstructed dispersion. For

example, a calculation of the effect of downwash

caused by airflow around a small building housing a diesel cogenerator showed an increase

in 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 still

higher on the faces and roofs of surrounding

buildings. Because roof areas may be used as

recreation areas or for fresh-air intake, and building faces may have open windows, downwash

problems must be taken extremely seriously.
Ch 6—Impacts of Cogeneration ● 229

Aerodynamic problems from the cogenerator’s

building or from surrounding buildings of similar

height can be eliminated by the simple expedient

of increasing the stack height. Unless surrounding buildings are close and their height is considerably taller than the stack, the stack height

levels needed either to avoid any effects or to

avoid the worst downwash effects usually are not

so high as to render the system infeasible. For example, for a 7 m high building with no problems

from surrounding buildings, stack heights that

avoid all building interaction effects are on the

order of 10 to 14 m above the roofline if the building is of moderate horizontal dimensions. A 6 m

stack might be tall enough to avoid the worst

downwash effects (5). The presence of nearby

buildings of similar height adds to the downwash

problem, but the additional stack height necessary to avoid problems is not great; for 9 m high

buildings, only 3 m would have to be added to

the stack (5). If the surrounding buildings are

much taller than the cogenerator’s building and

closer than about three times their height, however, then the cogenerator can only free itself of

their adverse aerodynamic influence by raising

its stack above their height (5). The economic and

esthetic effects of this requirement will be quite

high in some cases.

Finally, in cases where an area’s electricity is

imported from distant powerplants, the tradeoff

between short stack cogenerators and central

powerplants with tall stacks is complicated: the

emissions from each alternative affect different

areas that may have different meteorological conditions, background air quality, and other factors

that determine pollution impacts. Also, because

a utility often can choose among a variety of supply alternatives, including different types of

powerplants within its airshed (possibly using different fuels or maintaining different levels of

pollution control) and long-distance power imports, the air quality tradeoff becomes still more

complex and is difficult to evaluate properly.

One factor in this tradeoff is fairly consistent,

however. New powerplants generally are located

far from densely populated urban areas, whereas

cogenerators serving urban areas are located

there. Thus, peak pollutant concentrations

caused by short-term unfavorable meteorological

conditions generally fall outside of the urban

areas for powerplants and inside these areas for

cogenerators. Consequently, the actual population exposure due to the cogenerators may be

higher than the exposure caused by the powerplant even during conditions when the cogenerator-related concentrations are much lower

than the concentrations associated with the

powerplant. These differences may have important implications for the health effects of alternative centralized and decentralized systems,

although there are other effects (such as ecological damage) for which the above differences are

either unimportant or imply higher costs from the

powerplants.

Emissions Balances: Cogeneration v.

Separate Heat and Electricity

Computing the air quality effects of any technological change is always made difficult by the

complexity, expense, and inaccuracy of air quality modeling. In the case of cogeneration, this

computation is further complicated by difficulties

in determining the emissions changes occurring

in the central utility system and by substantial

variability in the emissions factors to be applied

to the cogenerators.

The response of the utility system to an increase

in cogenerated power—a critical parameter in determining not only emissions impact but also oil

savings (or Ioss)—is difficult to predict. The addition of significant levels of cogenerated power to

a utility’s service area will affect both its current

operations and future expansion. If the cogenerated power represents a displacement of current electricity demand in the service area (i.e.,

with retrofit of an existing facility for cogeneration), the utility will either reduce its own electricity production or reduce power imports, with

its decision based on costs, contractual obligations or, perhaps, politics. It may also move up

the retirement date for an older powerplant or

cancel planned capacity additions in response to

cogenerators’ displacement of either current or

anticipated future demand. Because most uti{ity

grids draw on a mix of nuclear-, coal-, and oilfired steam electric generators for base and intermediate loads, and oil- or natural gas-fired tur-
230 . Industrial and Commercial Cogeneration

bines for peaking capacity (as well as hydroelectric and natural gas-fired steam electric plants in

some parts of the country); because these plants

may be scattered over a wide area; and because

control systems for the fossil plants may vary

drastically in effectiveness, the pollution implications of the response of the utility system to cogeneration are highly variable.

Aside from problems in computing the utility

system impacts, a variety of factors create analytical difficulties in calculating the emissions likely to be produced by a cogenerator. For example, the potential variability in organic nitrogen

and sulfur content of future fuel supplies for gas

and steam turbines and diesels may have substantial impacts on the level of NOX and SOX emissions unless appropriate controls are applied to

compensate for fuel quality. Differences in the

specific design and duty cycle of cogenerators

also may create substantial variability in emissions

from engines of the same size and technology.

CO and unburned hydrocarbon emissions from

diesels depend on injection pressure (range:

several hundred to 20,000 psi, though not for the

same size engine), engine speeds, use of a precombustion chamber, and other factors. NOX

emissions depend on combustion and postcombustion temperatures, which can vary substantially in diesels and gas turbines. Emissions of all

three of the above pollutants depend on load,

which can vary from application to application.

Data from EPA and other sources show that uncontrolled 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 (0.3

to 14.6 g/hph), and NOX emissions by a factor of

eight (2.1 to 17.1 g/hph) (39). Although controls

required by uniform emission standards should

reduce this variability, it is likely that even controlled emission rates will vary substantially from

one installation to another, because controls are

unlikely to be “fine-tuned” to account for variations in fuels and operating procedures, and because different manufacturers will choose different margins of safety and control techniques

to ensure compliance.

OTA calculated the emissions impact–both at

the cogenerator site and over a larger area encompassing the cogenerator site and the entire

utility grid—for a variety of situations where a

cogenerator replaces or substitutes for a more

conventional electricity and heat supply option

(e.g., central station power plus onsite boiler).

The results are shown in table 51. The substantial number of combinations of: 1) cogenerator

type and fuel, 2) central power station type and

fuel, and 3) local heating type and fuel that are

analyzed, and the normalization of the calculations to 100 kWh of electricity generation are

designed to compensate in part for the site-specific variability of cogeneration installations discussed above. Emissions data for each of the separate modules are given in appendix B, and these

data may be readily used to compute additional

combinations. Unfortunately, the variability in

emissions factors caused by design and operating

variations is not accounted for in table 51.

A key conclusion that can be drawn from table

51 is that substituting cogeneration for more conventional systems will not result in automatic

pollution gains or losses despite the increased efficiency. If the variability not accounted for in the

table is further considered (e.g., alternative fuel

compositions, or the considerable range of emissions factors possible within a cogenerator technology type), the potential for achieving a wide

range of positive and negative emissions effects

by varying the precise cogeneration system design becomes even more readily apparent.

Diesel cogeneration may be an important exception to this conclusion. Diesel cogenerators

will tend to cause a strong increase in NOX both

at the cogeneration site and in the overall regional

balance (utility plant reduction included), mainly because diesels are very high emitters of NOX

.

Although CO emissions increase by about the

same order of magnitude as NOX

, the CO increases are far less significant because the toxic

effects of NOX occur at concentrations that are

at least 10 times lower than the levels at which

CO becomes toxic.

The actual effect of diesel cogenerators on

emissions and air quality will depend on the

degree of attention paid to environmental control. If minimum NOX emissions were judged to

be of critical importance in a series of cogeneration installations in an area, appropriate selection
Ch. 6—Impacts of Cogeneration . 231

Table 51.—Selected Emissions Balances for Cogeneration Displacing Centrai Power

Pius 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 +0.65 +0.09 –1.12 +3.3 9 +0.07 +0.90 +0.10 +0.20

Older oil-fired plant Domestic oil +2.69 –0.01 +0.88 +0.08 –0.93 +3.3 7 +0.06 +0.89 +0.10 +0.12

Existing 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 +0.09 +0.03 –4.52 +0.3 0 +0.02

011-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 –0.79

Older oil-fired plant Coal-fired

Industrial boiler –0.84 –0.40 +0.05 +0.01 -3.27 -0.0 4 -0.35

New coal plant

+0.09 +0.02 –2.18

Gas-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 Industrlal

boiler –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-fired

fired 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 steam

boiler, coal –0.38 –0.01 –0.02 o –0.49 +0.32 +0.04 +0.02 +0.01 +0.56

Older natural gas- NSPS steam

fired 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 steam

boiler, 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 Industrial

boiler +0.38 –0.13 o 0 -0.11 +1.0 8 -0.06 +0.04 +0.01 +0.94

Older oll-fired

boiler 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.

SOURCE: Office of Technology Assessment.

of diesel designs and use of controls could lower

emissions from the level shown in table 51.

Gas turbine cogenerators do not appear to

cause consistently strong changes in emissions

either locally or regionally, except for: 1 ) regional

SOX reductions due to turbines’ clean fuel requirements, 2) regional NOX reductions resulting

from the increased efficiency of the cogeneration

systems, and 3) small NOX increases locally. The

regional NOX reductions would be largely lost

and local increases made larger by 0.4 to 0.8

lb/100 kWh if NOX controls were no longer

required.

Finally, coal-fired steam turbine cogenerators

are likely to create mild increases in NOX and

somewhat larger increases in SOX emissions

locally because of the increased fuel consumption at the site. Regional effects are mixed.

An Air Quality Analysis of

Urban Diesel Cogeneration

To our knowledge, there have been few analyses of the air quality effects of an areawide installation of cogeneration equipment, and only

one non hypothetical area—New York City—has

been modeled explicitly. Both Consolidated

Edison (ConEd), the utility serving New York City,

and the New York State Public Service Commission staff have conducted dispersion modeling

studies to evaluate the impacts of installing multiple cogenerators with a combined electric capacity of as much as 1,000 MW* (14,19,21). The

results of these studies, which generally show

● The Con Ed analysis is reported in detail in Environmental Research and Technology, Inc. (19), and updated and revised in

Freudenthal (21). The Public Service Commission analysis is described in Domaracki and Sistla (14).
232 ● Industrial and Commercial Cogeneration

adverse effects on air quality, have been widely

disseminated by ConEd, which is opposed to

urban cogeneration, and they have become controversial. Consequently, they deserve closer

examination.

The most recent study by Con Ed examines the

impact of installing 141 cogenerators in Manhattan, displacing 514 MW of ConEd’s capacity as

well as a considerable amount of space heating.

In this study, annual nitrogen dioxide (N02

) concentrations in a large part of Manhattan were

predicted to increase by more than 14 pg/ms,

with a resulting violation of Federal ambient

standards in this area (21). This most recent version of ConEd’s analysis corrects two major problems affecting the results of an earlier study examining the impacts of 1,086 MW of cogeneration capacity: collocation of multiple emission

sources and location of receptors too close to

emission sources (19).

However, evaluation of the most recent ConEd analysis should take into account the following considerations:

1.

2.

The analysis assumes an emission rate of

17.3 g/kWh of NOX for the diesels. This appears to be a reasonable value for uncontrolled oil-fired diesels, but it is substantially higher than the approximately 10 g/kWh

proposed for the Federal NSPS. Furthermore, diesels that do considerably better

than the assumed uncontrolled rate are

available, so that careful selection of manufacturers and models could yield significantly

lower emissions even without adding controls. Consequently, the assumed emission

rate is valid only if selection of diesels is

made with no concern about their emission

rate and if manufacturers of diesels make no

attempts to reduce emission rates in the next

few years.

The analysis examines only one distribution

of sources and does not attempt to find a

more acceptable pattern (e.g., by removing

a few critical cogenerators). This implicitly

assumes that air quality considerations will

play no role in the siting of cogenerators, and

thus that permitting procedures are ineffective. This implicit assumption has been chal3.

Ienged by the State Department of Public

Service (DPS) (14). DPS notes that most

cogenerators will undergo PSD reviews, and

also that proliferation of cogeneration will

result in an appropriate regulatory response

on the part of the State. DPS believes that

the present inadequacy of regulations for cogenerator siting is the result of the lack of

development activity. However, there is no

guarantee that local reviews, currently considered by some to be inadequate, will be

sufficiently upgraded in response to a surge

in cogeneration activity. In the testimony

cited above, the witnesses agreed that none

of the cogeneration sources included in the

Con Ed analysis would have been prohibited

under existing regulations,

ConEd has assumed that commercial cogenerators will be able to use only 50 percent

of their recoverable heat (thermal efficiency of 52 percent), and residential cogenerators will use 75 percent of their recoverable

heat (62 percent thermal efficiency). Available studies of cogeneration assume significantly higher thermal efficiencies, which in

turn would change the emissions balance of

cogenerator, central power station, and furnace or boiler in favor of the cogenerator.

As discussed in chapter 5, ConEd’s assumptions imply no thermal storage and “electrical dispatch”—running the cogenerator

only when sufficient electrical demand exists. With the Public Utility Regulatory

Policies Act of 1978 (PURPA), cogenerators

are more likely to operate on “thermal dispatch” and distribute any excess electricity

to the grid. Consequently, their overall efficiencies should be higher than what Con Ed

assumes, with more favorable emissions

balances.

Despite the inherent inaccuracy of diffusion

models, especially in urban applications, it seems

prudent to consider the prediction of a general

increase in NOX concentrations to be roughly accurate for the particular situation examined. The

potential problems in ConEd’s analysis with the

cogenerator thermal efficiencies should not drastically affect this prediction. The remaining problems with the analysis, however, demand a very
Ch. 6—impacts of Cogeneration 233

careful interpretation: OTA interprets the ConEd analysis as showing that any additional development—including multiple installations of

diesel cogenerators—that could produce an increase in local urban emissions, might create air

quality problems if adequate controls were not

required and if permits were issued without

careful consideration of stack height, siting, and

other parameters affecting pollutant dispersion.

In areas where existing air quality is not substantially better than the Federal ambient standards,

it appears likely that some permits may have to

be denied to avoid violations of these standards.

Emission Controls

Potential air quality problems like the ones

described above can be ameliorated if emissions

can be controlled sufficiently. As noted previously, however, controls will not automatically be

required by law in many situations, especially for

small cogenerators such as diesels and sparkignition engines that are not covered by Federal

NSPS and may not be subject to State and local

regulation. For technologies to which NSPS do

apply (e.g., gas turbines) the required level of control may not be as stringent as the local air quality situation might call for, because most State and

local environmental authorities are reluctant to

go beyond the NSPS requirements. This section

describes the available controls for NOX emissions from reciprocating internal combustion

engines and gas turbines. Emissions from industrial boilers (for steam turbine cogenerators)

are not discussed, but EPA is preparing an NSPS

background document for these emissions

sources. *

Reciprocating Internal Combustion Engines

In 1979, EPA proposed an NSPS of 600 parts

per million (ppm) NOX corrected to 15 percent

oxygen (equivalent to about 7 g/hph or about 2.2

lb/MMBtu fuel input) (2) for diesels burning oil

or oil/natural gas combinations (39). This is an

order of magnitude higher than emission rates

from other combustion sources such as industrial

boi!ers or even gas turbines (38). “Typical” uncontrolled 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 8

g/hph (about 2.5 lb/MMBtu) for dual-fuel engines

(39). As noted above, emission levels vary widely among different engine manufacturers and

models.

Table 52 lists the wide variety of control options available to reduce NOX emissions. In its efforts to formulate the internal combustion engine

NSPS, EPA concluded that, of the methods shown

in table 52, only retarded ignition timing, air-tofuel ratio changes, decreased manifold air temperatures and engine derating were demonstrated to be effective and readily available for

large engines (39). Exhaust gas recirculation and

combustion chamber modification were considered to require additional development and

durability testing, and the remaining methods

were considered to have serious technical or cost

problems, or to be of uncertain effectiveness for

these engines.

The available control techniques do not work

identically on diesel, dual-fuel, and natural gasfired spark-ignition engines. Table 53 shows

which techniques will achieve emission reductions of 20, 40, and 60 percent for the three

engine types; the table also shows the expected

increases in fuel consumption with these levels

of emissions reductions. The increased fuel use,

combined in some cases with higher maintenance costs and capital charges from add-on

equipment, can cause significant increases in total

costs; table 54 shows the increases in total annualized costs for different control types and

emission reductions applied to diesel engines. ignition retard, with or without an air-to-fuel ratio

change, and a combination of air-to-fuel change

and manifold cooling can reduce NOX emissions

by 40 percent with total annualized cost increases

of less than 10 percent. This level of control was

selected by EPA for its proposed NSPS, although

the proposal was withdrawn.

More recent information implies that greater

NOX emission reductions than those indicated by

EPA may be possible. For example, although EPA

rejected water induction as a viable control strategy because of its potential for corrosion and oil

contamination (39), the use of fuel/water emulsions or carefully timed direct injection apparently can bypass these problems (15). Control levels
234 ● Industrial and Commercial Cogeneration

Table 52.—Summary of NOX Emission Controi Techniques for Reciprocating IC Engines

BSFCa

Control -- . . . . -. Princicple of reduction Application . .Increase comments-limitations

Retard Reduces Desk temperature

Injection (Cl b

Ignition (SI)c

Alr-to-fuel(A/F) Ratio

change

Derating

Increase-speed

Decreased Inlet manifold

air temperature

Exhaust gas recirculation

(EGR)

External

Internal:

Valve overlap or

retard

Exhaust back

pressure

Chamber modlflcation

Precombustion (Cl)

Stratified charge (SI)

Water lnduction

Catalytic conversion

by delaying start of combustion during the comustlon period.

Peak combustion temperature Is reduced by offstolchiometrlc operation

Reduces cylinder pressures

and temperatures.

Decreases residence time

of gases at elevated temperature and pressure.

Reduces peak temperature.

Dllutlon of incoming combustion charge with inert

gases. Reduce excess

oxygen and lower peak

combustion temperature.

Cooling by increased scavenging, richer trapped

air-to-fuel ratio.

Richer trapped air-to-fuel

ratio.

Combustion In antechamber

permits lean combustion

In main chamber (cyllnder) with less available

oxygen.

Reduces peak combustion

temperature.

Catalytic reduction of NO

to N2.

An operational adjustment.

Delay cam or Injection

pump timing (Cl); delay

ignition spark (SI).

An operational adjustment.

Increase or decrease to

operate on off-stoichiometric mixture. Reset

throttle or Increase air rate.

An operational adjustment,

limits maximum bmepd

(governor setting).

Operational adjustment or

design change.

Hardware addltlon to increase aftercooling or add

aftercoollng (larger heat

exchanger, coolant pump).

Hardware addition; plumbing

to shunt exhaust to Intake;

coollng may be required

to be effective; controls

to vary rate with load.

Operational hardware

modification: adjustment

of valve cam tlmlng.

Throttling exhaust flow.

Hardware modification; requires different cylinder

head.

Hardware addition: inject

water into inlet manifold

or cylinder dlrectly; effective at water-to-fuel ratio

1 (lb H2)/lb fuel).

Hardware addition; catalytic

converter installed In exhaust plumbing or reducing agent (e.g. ammonia)

injected Into exhaust

stream.

Yes

Yes

Yes

Yes

No

Noe

Yes

Yes

Yes

No

No

Particularly effective with moderate

amount of retard; further retard

causes high exhaust temperature

with possible valve damage and substantial BSFC Increase with smaller

NOX reductions per successive

degree of retard.

Particularly effective on gas or dual

fuel engines. Lean A/F effective but

Ilmited by mlsfirlng and poor load

response. Rich A/F effective but substantial BSFC, HC, and CO Increase.

A/F less effective for diesel-fueled

engines.

Substantial Increase In BSFC with additional units required to compensate

for less power. HC and CO emission

increase also.

Practically equivalent to deratlng because bmep is lowered for given bhp

requirements. Compressor applications constrained by vibration considerations. Not a feasible technique

for existing and most new facilities.

Ambient temperatures Iimit maximum

reduction. Raw water supply may be

unavailable.

Substantial fouling of heat exchanger

and flow passages; anticipate increased maintenance. May cause

fouling in turbocharged, aftercooled

engine. Substantial Increases In CO

and smoke emissions. Maximum recirculation Ilmlted by smoke at near

rated load, partlcularly for naturally

aspirated engines.

Not applicable on natural gas engine

due to potential gas leakage during

shutdown

Limited for turbocharged engines due

to choking of turbocompressor.

5 to 10 percent increase In BSFC over

open-chamber designs. Higher heat

loss implies greater cooling capacity.

Major design development.

Deposit buildup (requiring demineralizatlon); degradation of lube oil,

cycling control problems

Catalytic reduction of NO is difficult in

oxygen-rich envlronment.-Cost of

catalyst or reducing agent high.

Little research applied to large-bore

IC 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 gas

reduction 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 4

External EGR (7%) o Manifold air coollng 1 Manifold air cooling o

Derate (25 to 5070) 3 to 5 External EGR (lO%) 1 External EGR (4%) o

Air-to-fuel change (25%) 10 Derate (12 to 25%) O to 8 Derate (5 to 35%) 2 to 6

Retard and manifold o to 1 Air-to-fuel changes (5 to IO%) o to 2 Air-to-fuel change (570) 2

air cooling

Retard and manifold o to 1

air cooling and air-to-fuel

change

40% Retard (7 to 8°) 4 to 8 Retard (5°) 2 Retard (10°) 2

Derate (50%) 14 to 17 Manifold air cooling 1 Derate (10 to 50%) 2 to 24

Air-to-fuel change and 3 to 5 Derate (30 to 50%) 2 to 8 Air-to-fuel change (7%) 2

manifold air cooling

Retard and air-to-fuel change 3 to 5 Air-to-fuel change (lO%) 2 Retard and manifold 7

air cooling and

Retard 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 22

Retard 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 7

cooling and air-to-fuel

change

Table 54.-Costs of Alternative NOX Controls for Diesel Cogenerators (percent Increase In total annualized costs)

NOX control Retard External Air to fuel

Percent reduction (R) Derate EGR (A) R + Ma R+M+ A R + A A +M

200/0 o-3 9-31 6 8 2 3

40% 3-6 37-40 4 4

60% 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 with

these techniques, with some parallel decreases

in particulate emissions* (43). Another, more

speculative NOX control approach is the use of

catalytic reduction systems. The staff of the

California Air Resources Board (CARB) reports

that NOX reductions of 90 to 95 percent can be

obtained from such catalytic systems (35). They

also expect the systems to reduce CO emissions

by 80 percent and hydrocarbon emissions by 75

percent. Catalytic reduction systems are currently

available for rich-burning natural gas sparkignition engines, and the CARB staff expects them

*Wilson (42) reported that water/fuel emulsion achieved 50 percent NOX reduction at full engine load with no fuel penalty. At partIoad (66 to 93 percent), NO, reductions of 75 percent were

achieved with a combination of exhaust gas recirculation and water/

fuel emulsion.

to be available for the other engine types within

a year or so, at costs below 10 percent of total

annualized costs (3). However, this projection is

viewed with various degrees of skepticism by

other researchers (2).

Combustion Turbines

The Federal NSPS for large combustion turbines

(above 100 MMBtu/hr) is 75 ppm NOX corrected

to 15 percent oxygen, which is equivalent to

about 0.3 lb/MMBtu NOX (40). For comparison,

a typical emission factor for NOY emissions from

an industrial boiler burning distillate oil is about

half as much, or 0.16 lb/MMBtu (38). “Typical”

uncontrolled NOX levels from turbines are 0.6

lb/MMBtu for natural gas-fired engines and 0.9

lb/MMBtu for oil-fired engines (40). However, the
variation in emissions among different turbine

designs and sizes and even in the same turbine

under different operating conditions is extremely high. Thus, the “typical” values are of limited

usefulness in air quality analyses.

The most widely used emission control systems

for combustion turbine NOX emissions are socalled “wet” controls, which consist of water or

steam injection into the combustion zone of the

turbine. The injected fluid absorbs some of the

heat of reaction, reducing peak combustion temperatures and, consequently, the rate of NOX formation. This control is accepted by the industry

and does not have significant adverse side effects.

Generally, a water/fuel injection ratio of 1.0 will

produce a 70- to 90-percent reduction in NOX

emissions, with a loss of fuel efficiency of 1 percent (40).

This range of control effectiveness, coupled

with the variability in uncontrolled emission

levels, results in actual controlled emissions that

vary widely. EPA has measured “controlled”

NOX emissions of 15 to 50 ppm for gas-fired turbines and 25 to 60 ppm for oil-fired turbines (40).

This implies that appropriate selection of turbine

design could allow the use of turbines in certain

situations where an “NSPS” turbine would be unsatisfactory.

Still more stringent control may be available by

adding so-called “dry” controls. These are operating or design modifications such as exhaust

gas recirculation, two-stage combustion, catalytic

combustion, and other types of modifications.

NOX reductions of at least 40 percent have been

demonstrated for some dry controls, and this

reduction should be additive to any achieved

with wet controls (40).

Finally, catalytic exhaust gas cleanup systems

achieving NOX reductions of 80 to 90 percent

have been tested (40). Although these systems

do not appear to be economically competitive

with wet and dry controls, they could be useful

if fuels with high nitrogen content were to be used

(otherwise, the only viable control for NOX generated by fuel-bound nitrogen is two-stage combustion) (40).

EPA has calculated the net NOX emission control costs using wet controls for a baseload 4,000

hp industrial turbine. For a plant located close

to a water source, the controls cost about 0.6

mills/kWh v. a total electricity cost of 32.5

mills/kWh, or a 1.75-percent increase (40). Transporting water for a turbine located in an arid

climate could add considerably to this cost, however. Considering this and other cost variables,

EPA considers the range of potential control costs

to achieve the 75 ppm NSPS to be about 1.5 to

10.0 percent of the electricity cost for industrial

turbines (40).

Health Effects From

Cogenerator Emissions

Theoretically, any allowed increases in the

deployment of cogeneration technologies should

have no significant adverse effects on human

health due to the protection afforded by environmental standards—especially the National

Ambient Air Quality Standards (NAAQS). As

discussed above, however, these standards might

be violated because of ineffective permit review

processes that miss “micro” (close to the emission source) effects in urban areas or that allow

small cogenerators to escape careful analysis. The

smallest cogenerators generally will be diesels,

and these may therefore have the highest potential to escape detailed review of monitoring and,

possibly, to pose health hazards. Judging from

the emissions balances displayed in table 53 and

from other environmental analyses of cogeneration, the pollutants of major concern are NOX

,

sulfur dioxide (S02

), and particulates-the latter

not because of a high emission rate but because

of their toxic character.

Due to of a variety of difficulties in measuring

the health effects of pollutants, several of the

Federal ambient standards–especially the standard for S02—have been criticized severely. A recent review in the Journal of the Air Pollution

Control Association (JAPCA) concludes, however,

that the standards “seem adequate to protect the

health of the public” and, “until more data are

available . . . should not be changed” (20). On

the other hand, a number of other researchers

disagree, arguing that some of the standards have

proved to be unnecessarily stringent (23). The

health and other considerations relevant to eval-
Ch. 6—impacts of Cogeneration . 237

uating the NAAQS for S02, NOX, and particulate are reviewed briefly below.

Sulfur Oxides

The 80 ug/m3 long-term standard for S02 is

the most controversial NAAQS because of the

substantial expense involved in reducing sulfur

emissions and, until recently, the lack of firm

evidence of adverse health impacts from S02 exposure even at levels several times the current

standards. Recent experiments, however, have

demonstrated health effects in asthmatics (increases in bronchoconstriction) at levels near the

current 24-hour standard (36). Also, exposure to

S02 virtually always occurs in the presence of particulate and other gases, and generally there is

a heightened response from the combination of

pollutants. At levels around the ambient standards (100 ug/m3 S02 and 150 ug/m3 particuIates, annual averages), respiratory symptoms, including general lung function impairments and

increased asthma attacks, have been detected

(33).

Nitrogen Oxides

The form of most of the NOX emitted directly

by diesels and other cogenerators is nitrous oxide,

or NO; eventually, the NO is transformed by

photochemical oxidation to the far more toxic

N02. Because this oxidation takes sometime, the

danger associated with a cogenerator’s plume impacting on nearby buildings or the ground is considerably lessened.

At levels that maybe experienced in polluted

areas (a few hundred ug/m3

), N02 appears to be

associated with lung irritation in asthmatics and

some increases in respiratory illness in the general

population. According to the JAPCA review cited

above, the epidemiologic evidence for the latter

effect is not particularly strong (20). In any case,

there seems to be little disagreement that the 100

ug/ms (annual average) ambient standard is adequate to protect public health. EPA currently is

investigating the need for a short-term standard

to protect against the acute effects of brief pollution episodes. It appears likely that this standard

will be no stricter than about 500 ug/m3 for 1

hour.

Diesel Particulate

Aside from their relatively high levels of NOX

and CO emissions compared to alternative combustion technologies, diesel cogenerators face the

additional problem of producing particulate emissions that may cause adverse health effects. These

effects, if they occur, would most likely stem from

toxic substances such as polycyclic organic material that adhere to the carbon core of the exhaust particles. The small size of the particles

complicates their control, allows them to remain

airborne for weeks at a time, and allows deep

penetration into and retention by the lungs.

The National Academy of Sciences recently released a report on diesel exhaust health effects

that stresses the uncertainties in measuring the

potential for adverse effects of these exhausts,

while emphasizing that conclusive evidence of

harm is not available (25). Some of the conclusions of the report are:

●

●

●

Although current epidemiologic evaluations

(statistical analyses of human populations)

are inadequate, the available evidence

shows no excess risk of cancer from diesel

exhaust in the populations studied.

Organic extracts (in which the potentially

harmful organic compounds are removed,

using a solvent, from the carbon particles to

which they adhere) of diesel particulate

have been shown to be mutagenic and carcinogenic in animal cell and whole animal

skin applications. The mutagenic and carcinogenic potencies of these organic extracts

appear to be similar to those of extracts of

gasoline engine exhaust, roofing tar, or cokeoven effluent.

Unlike the extracts, inhaled whole diesel exhaust has not been shown to be carcinogenic

or mutagenic in laboratory animals. A possible reason for this could be that many of the

potentially dangerous compounds may not

be released from the particles and thus may

not become biologically available to cause

harm. *

*However, another reason could be that the tissue tests used for

these investigations do not adequately reflect what would actually

go on inside the body.
238 . Industrial and Commercial Cogeneratlon

● Potentially toxic particles can accumulate in

the lungs when diesel exhaust is inhaled, but

long-term effects are uncertain. In the short

term, cell damage (mostly reversible) can

occur because the diesel exhaust can adversely affect the lungs’ defense and clearance mechanisms; it is not clear if this is

caused by the particles or by the gases in the

exhaust.

● The design and operating characteristics of

the engine may be a significant determining

factor in the carcinogenicity of diesel engine

exhaust materials.

Evaluating the potential for harm of diesel particulate from cogenerators is complicated by differences in operating characteristics between cogenerators running at constant speeds and relatively stable loads, and mobile sources running

at varying speeds and loads. Mobile sources (from

which most of the emission data have been gathered) operate at far less optimal combustion conditions and produce more particulate matter. It

is not unreasonable to speculate that the human

health risk from diesel cogenerators per unit of

energy input or output may be significantly lower

than the risk from mobile diesels; however, scientific data with which to confirm or deny this

speculation do not appear to be available.

Effects of Some Other Cogeneration

Technology/Fuel Options

Although oil-fired and dual-fuel diesels, oil- and

natural gas-fired combustion turbines, and multifuel steam turbines are the most likely cogeneration options for the immediate future, other technology or fuel choices will be open to potential

cogenerators.

Spark=lgnition Engines

Fiat recently introduced a natural gas-fired

spark-ignition cogenerator—called TOTEM–

based on its automobile engines. Because the

TOTEM modules are extremely small (15 kw),

they may escape careful permitting by local

authorities. Proliferation of such cogenerators in

urban areas could conceivably lead to air quality problems.

EPA data indicate that gas-fired spark-ignition

engines have higher NOX emissions than diesels

(sales-weighted average of about 4.6 lb/MMBtu

v. about 3.5 lb/MMBtu for diesels) (39). On the

other hand, Fiat and Brooklyn Union Gas claim

NOX rates of about 3 lb/MMBtu as well as extraordinarily high thermal efficiencies (91 percent) that

would maximize the emission displacement of

the cogenerator (6). Either emission level can present a problem, however, because the small

TOTEM engines would not be subject to the proposed NSPS for stationary internal combustion

engines, and even the lower rate is quite high in

comparison with competing combustion sources.

Alternate-Fuel Diesels

Although natural gas/diesel fuel mixtures and

straight diesel fuel are used in stationary diesels

today, residual fuel currently is used in large

marine diesel engines and will be available for

stationary engines. Coal-derived fuels in the form

of synthetic oil, coal slurry, and dry powdered

coal may be used in future engines (see ch. 4).

Use of residual oil in diesels should affect SOX

emission levels because residual oil generally has

higher sulfur levels than distillate fuels. According

to available data, however, levels of other emissions should not be affected significantly in comparison to current diesels (27). Diesels using coalderived synthetic residual oil exhibit similar characteristics, although synfueis that have not been

hydrotreated will contain levels of fuel-bound

nitrogen that are generally higher than those in

natural oils and consequently will cause elevated

NOX emissions (24).

The use of coal slurries and powdered fuels

should adversely affect levels of NOX, SOX, and

particulate. Table 55 shows expected values of

Table 55.-Emissions From Oii- and Coai-Fired Dieseis

Emissions (lb/M MBtu)

Fuel NO. so.. Particulate

Diesel Oila . . . . . . . . . . 3.46 0.2c

0.07

Coal slurryb . . . . . . . . . 3.61 l.5

d

3.26

Coalb

. . . . . . . . . . . . . . . 4.35 1 .5d

8.91

aSource is app. A.

bReference 47.

cAssumes 0.2% sulfur distillate oil.

dAssumes 2% sulfur coal, 25 MMBtu/ton.
Ch. 6—Impacts of Cogeneration ● 239

these fuels compared to average emissions from

oil-fired diesels. The level of particulate emissions

is so high as to virtually guarantee that an uncontrolled coal-fired engine would be environmentally unacceptable. Based on an extrapolation

from ConEd modeling studies (19), it is possible

that a proliferation of such diesels in urban areas

would create significant problems with all three

pollutants unless emission controls were used.

Atmospheric Fiuidized Bed

Steam turbines using coal-fired atmospheric

fluidized bed (AFB) boilers can achieve low SOX

emission rates without generating large amounts

of scrubber sludge, and probably will have NOX

emissions below current NSPS for steam turbines.

Although the action of the bed creates potentially

high levels of particulate emissions, baghouse

controls should keep actual emissions to ve~ low

levels. The AFB boiler at Georgetown University in Washington, D.C. (which is a potential

cogenerator although it currently does not

generate electricity) has now been operating

without environmental complaints for a few

years.

Closed-Cycle Gas Turbines

Closed-cycle gas turbines use an external heat

source to produce high-temperature gas. Although emissions depend on the nature of the

heat source and fuel used, emission control

should present no unusual problems.

Methanol-Fired Gas Turbines

There is a reasonable probability that significant quantities of methanol from biomass and

coal resources may become available within a

few decades. Methanol is a suitable fuel for gas

turbines and might be an advantageous fuel in

turbine cogenerators because of the expected

substantial drop in NOX emissions. Methanol has

achieved 76-percent reductions in NOX emissions from large turbines because it has a significantly lower combustion temperature than distillate fuels (28).

Policy Options: Removing Environment=

Associated Regulatory Impediments

In general, Federal, State, and local authorities

treat cogenerators in an identical fashion with

other stationary combustion sources. For example, both Federal NSPS and local emission standards for all combustion sources are tied to fuel

input rather than energy output, and thus do not

consider the energy efficiency of the system. In

other words, two diesel generators that use the

same amount of fuel are limited to the same levels

of emissions, even if one produces more usable

energy than the other. Also, facilities are designated as “major sources” subject to PSD and

nonattainment review only on the basis of their

emissions output, without consideration of any

emissions reductions their use might cause in

other facilities. Finally, new sources locating in

nonattainment areas are awarded emission offsets only to the extent that other sources within

the same locale agree to reduce their emissions

permanently and transfer the pollution rights obtained by the reduction to the new source. Thus,

cogenerators are not automatically given preferred treatment to account for their increased

efficiency or their displacement of centrally

generated electricity.

It has been suggested that cogenerators should

be given various types of preferred treatment with

regard to air quality concerns to facilitate their

market entry (12, 16,22). Two basic changes that

have been recommended are:

That emissions standards account for high

cogenerator efficiency, either by being tied

to the energy output rather than the fuel input of the source, or by having separate

(more lenient) standards for cogenerators.

That restrictions on new sources under PSD

and nonattainment area provisions of the

Clean Air Act (see ch. 3) be reduced or eliminated for cogenerators. For example, the
240 . Industrial and Commercial Cogeneration

250-tpy emissions trigger could be relaxed

by allowing the cogenerator to subtract emissions that are eliminated at the central power

station. Only if net emissions exceed the trigger levels would the provisions apply. An alternate or additional policy would be to shift

the responsibility for obtaining emissions offsets to the State, or to allow the cogenerator

to count any reduction in central station

power generation as an offset.

Each of these policy alternatives is evaluated

below.

Emission Standards Based on Output

Because cogenerators generally produce considerably more useful thermal and electric energy

than the same equipment generating only electricity, basing emission standards on energy output rather than fuel input would significantly

reduce the emission control requirements for cogenerators and should lower their overall costs.

Thus, this policy would make cogeneration more

competitive in the marketplace, although the extent of any advantage will vary substantially from

case to case.

The major environmental argument for this policy alternative is that, for a given amount of useful

energy, a cogenerator will produce less pollution

than a separate generator and thermal energy

source and thus should be rewarded for this benefit (4,41 ). This argument generally is valid only

when a cogenerator would replace an otherwise

identical generator, using the same technology

and fuel. As discussed above, many cogenerator

applications involve new technology or fuel

substitutions (e.g., diesel cogenerators replacing

steam turbines and boilers or furnaces), as well

as changes in scale. As shown in the section on

emissions balances, the net result is quite often

an emissions increase. Furthermore, the pollution impact of most concern often is the local air

quality impact, and this may not be improved by

the reduced emissions at a distant powerplant as

a result of the addition of cogeneration. Finally,

the legislative philosophy associated with NSPS

is that all important new stationary sources should

apply the best control technology available to

them, taking into account energy, economic, and

non-air quality environmental factors. Some

potential cogenerators might try to argue that

these energy and other considerations justify a

different interpretation of “best technology” in

their case. Based on the analysis of the environmental costs and benefits of cogeneration in this

report, however, it appears that such an argument would not be valid for all cogenerators.

Thus, cogeneration emission standards based on

energy output should only be applied on a caseby-case, or technology- and area-specific basis,

if at all.

Changes in Offset Requirements

As shown in table 56, the costs incurred in being designated a “major source” under either

PSD or nonattainment area provisions are high

and will affect the economic attractiveness of

cogeneration (17). In addition to the costs of performing the necessary environmental analyses,

the added costs of obtaining emissions offsets (if

any are available) and installing lowest achievable

emission rate (LAER) controls may effectively

block cogenerators (and most other types of stationary sources) from locating in nonattainment

areas. Thus, policies that reduce or eliminate the

review requirements (and, for nonattainment

areas, the offset requirements) for cogenerators

would be removing important impediments to

these technologies.

The major argument against automatically crediting the reduction in central station power requirements in applying PSD and nonattainment

Table 56.-Approximate Costs of Procedures Required

Under the Clean Air Act

cost to

Procedure cogenerator

Engineering review . . . . . . . . . . . . . . . . . . . . . $100-500

Stage 1 PSD review (attainment) . . . . . . . . . $1,000-2,000

Monitoring—1 year

One pollutant . . . . . . . . . . . . . . . . . . . . . . . . $30,000

Six pollutants. . . . . . . . . . . . . . . . . . . . . . . . $125,000

Stage 1 interpretive ruling

(nonattainment) . . . . . . . . . . . . . . . . . . . . . . $2,000

TSP/S02 modeling . . . . . . . . . . . . . . . . . . . . . .$10,000-20,000

NOTES: Any of these costs may or may not be incurred, depending on the individual case. These figures assume a simple, “major source” case.

SOURCE: Office of Technology Assessment, from Michael S, Dukakis, Governor’s Commlss\on on Cogeneratlon, Cogeneration: Its Beneflts to New

England (Governor of Massachusetts, October 1978).
Ch. 6—impacts of Cogeneration . 241

rules is that the benefit of this reduction to the

airshed in question is often either illusory or very

difficult to calculate. As noted previously, the corresponding emission reduction may be out of the

airshed altogether, or the reduced power requirements may be shifted among different plants at

different times according to the utility’s economic

dispatch methods and the overall supply/demand

balance of the grid. Also, when the central powerplant has a very tall stack, its effect on the air

quality of a particular airshed maybe far less, per

unit of power, than the effect of cogenerators.

Finally, in the case of a large new cogenerator,

the “offset” utility emissions may be from a projected powerplant rather than from an existing

facility. Because any future powerplant would

have to comply with PSD or nonattainment requirements if its emissions affected the airshed,

it is not logical that the plant’s replacement or

“offset” —the cogenerator—should be freed from

these requirements.

To summarize, these policy alternatives do appear to be attractive if the primary objective is

to promote cogeneration. However, widespread

application of regulatory relief to cogenerators

as a class is difficult to justify on environmental

grounds. On the other hand, the existence of

situations where air quality benefits and oil savings will accrue from cogenerators may justify

awarding some relief on a case-by-case or technology- and area-specific basis.

Other Potential Impacts

Although the potential air quality effects are the

major environmental concern associated with cogeneration systems, potential impacts from water

discharges, solid waste disposal, noise, and cooling tower drift are important and must be addressed satisfactorily to avoid local opposition to

these cogenerators.

Water Quality

Water discharges are associated primarily with

blowdown from boilers and wet cooling systems.

Pollutants of concern are suspended solids, salts,

chlorine, oil and grease, and chemical corrosion

inhibitors. For large coal-fired steam turbine

cogenerators, potential discharge sources include

runoff from coal storage piles, scrubber effluent

from S02 control systems, and discharges from

ash quenching. These discharges are the same

as would occur in conventional steam turbine

combustion systems, although any wet cooling

systems clearly would be smaller because much

of the waste heat is captured in a cogenerator

and need not be discharged to the environment.

Some of the discharges may present special problems, however, because the cogenerators may

be located in urban areas whose sewage treatment facilities are not designed to handle industrial discharges. Onsite pretreatment (before

discharge into the municipal system) may be

necessary to avoid problems from these discharges.

Solid Waste Disposal

Disposal of ash and scrubber sludge could also

present some difficulties for urban and suburban

coal-fired cogenerators due to the lack of secure

landfill areas. Municipal landfills may be inadequate due to the toxic metals content of the ash,

and long-distance and expensive shipping of

these wastes might be necessary.

Noise

Operating cogenerators and trucks supplying

fuel to cogenerators may produce high noise

levels in urban areas. For example, a recent study

of the Jersey City Total Energy Demonstration

project, which uses diesel cogeneration, measured sound levels of 65 dB(A) (loud enough to

interfere with a normal conversation) at a distance

of 75 ft from the equipment building (1 3). This

might be considered unacceptably loud for a

night-time noise level in a residential area. Similarly, the noise from fuel trucks may be considered

disruptive, although the effect of supplying oilfueled furnaces and boilers may be as disruptive,

if not more so, because furnaces and boilers are

likely to require more frequent fuel deliveries than

cogenerators. In any case, noise control measures

are readily available. These include careful scheduling of fuel deliveries, installing mufflers, or adding sound absorbing materials to equipment and

buildings to reduce engine noise.
242 ● Industrial and Commercial Cogeneratlon

Cooling Tower Drift

Cooling tower drift-the discharge and dispersal of small droplets of water from wet cooling

towers—is a potential source of problems in

urban areas. These droplets will contain anticorrosion chemicals and biocides and will have a

high salt content caused by the concentrating effect of the evaporative cooling. In the Jersey City

quate maintenance of the system led to spotting

of nearby automobiles and an annoying misting

of pedestrians (1 3). Although the effects in the

Jersey City case appear to represent a nuisance

rather than a hazard, negative community reaction to this as well as other visible adverse effects

of cogenerators may play a significant role in their

further deployment.

demonstration project mentioned above, inadePOTENTIAL REGULATORY BURDEN ON ENVIRONMENTAL AGENCIES

Cogeneration usually involves shifting environmental impacts-primarily effects on air quality—

away from a few central powerplants to a larger

number of small sources. Although cogeneration

will not be subject to as many permitting requirements as large central generating plants (see ch.

3), multiple installations could lead to increased

permit applications and more sources that must

be monitored and inspected. In some areas, State

and local environmental protection agencies may

not have the resources to accommodate such an

increase in their workload. If this is the case,

cogenerators could be inadequately monitored

and controlled, and substantial adverse impacts

could occur (see discussion of environmental impacts, above). *

To determine whether cogeneration would significantly increase the workload of environmental agencies, OTA first estimated current workloads and resources of the various Federal and

State permitting agencies in two States–Colorado

and California—based on interviews with agency personnel.** Those interviews also revealed

current management concerns about existing and

future caseloads. Then the increased permitting,

monitoring, and enforcement responsibilities attributable to cogeneration were calculated from

State agency market penetration projections, and

compared to the existing workloads to determine

the potential regulatory burden.

*The analysis in this section is drawn from Energy and Resource

Consultants, Inc. (17)0

**In Colorado, the Department of Natural Resources, the Office

of Energy Conservation, and the Colorado Energy Research Institute

were contacted. In California, the California Energy Commission

and the Cogeneration Task Force were contacted.

The results of this analysis suggest that cogeneration is likely to have a minimal impact on environmental caseloads in these two States because the increase in agency resources needed

to regulate cogeneration is very small when compared to existing workloads. Possible exceptions

would be areas where agencies were already understaffed prior to the Federal (and many State’s)

budget reductions of 1981 and 1982–usually

water quality and right-of-way programs, or

where economic or other legislative incentive

programs for cogeneration impose significant

new responsibilities on agency staff.

Environmental Permitting and

Enforcement Agencies

Four regulatory agencies in Colorado have

direct jurisdiction over cogeneration facilities,

while approximately seven others regulate associated facilities such as transmission and distribution systems.

Permitting and enforcement of the Clean Air

Act are shared by the region Vlll offices of EPA

and the Air Pollution Control Division of the Colorado Department of Health. The division administered approximately 400 permits in 1980 and

conducted approximately 4,900 inspections. Discussions with agency personnel revealed no

major enforcement problems in 1980. EPA region

Vlll administers the PSD program in Colorado.

They processed 40 to 50 permit applications in

1980 and they typically conduct oversight inspections of roughly 10 percent of the major sources

in the State each year.
Ch. 6—Impacts of Cogeneratlon . 243

The water programs are administered by the

Water Quality Control Division of the State

Department of Health and by the Army Corps of

Engineers. The Water Quality Control Division

administers the section 401 and the National

Pollution Discharge Elimination System (NPDES)

permits. The section 401 program (primarily applicable in this context to transmission and

distribution systems) had one staff member who

issued 200 water quality certificates in fiscal year

1980. The NPDES program also suffers from insufficient manpower; almost 300 applications for

new permits or for amendments to existing permits were awaiting action at the end of 1980.

Time pressures on the staff members are felt to

impair the quality of the reviews for permits being issued, possibly resulting in inadequate controls. The Water Quality Control Division initiates

30 to 45 enforcement actions per year, but many

violations by minor sources are ignored due to

lack of manpower.

The Army Corps of Engineers administers the

section 404 permits through their district offices

in Sacramento and Omaha. The Sacramento District maintains an area office in Grand Junction,

Colo., with three full-time personnel. In 1980, this

office issued approximately 40 applications for

section 404 or section 10 permits in process,

50 violations (generally involving unpermitted

work—their biggest problem), and 150 to 175 individual permits (these have a normal term of 3

years, with extensions available). They also supervised approximately so operations under general

permits.

Applications for rights-of-way in Colorado are

handled by the State Board of Land Commissions,

the Bureau of Land Management (BLM), and the

U.S. Forest Service. Right-of-way applications

have been a bottleneck in the permitting process,

with application processing lasting up to 1 year.

In summary, the programs concerned with

water quality (sec. 401, sec. 404, NPDES) are at

present less effective than they might be, due

largely to manpower limitations. Delays in processing right-of-way applications in the district offices of BLM and the Forest Service, which in

large measure reflect manpower limitations,

change from year to year and district to district,

reflecting the variability in applications filed and

resources at each district. If dispersed facilities

sharply increased the number of right-of-way applications, this permit could become a severe bottleneck.

California environmental agencies are subdivided into numerous regional and district offices (see ch. 4). For example, 46 separate air

pollution control districts (APCDS) are responsible for administering air permits and each district

has different permitting requirements. As a result,

only sampled agency districts or regions that are

considered representative are discussed explicitly.

The 46 APCDS in California vary from rural

counties with one full-time employee, to the Bay

Area and South Coast Air Quality Management

Districts with over 200 and 400 full-time

employees, respectively. The Sacramento County

APCD employs two people to permit 150 to 200

sources per year. permits require up to 2 months

to be processed. There are no sources in the

district with continuous monitoring, and one of

three inspectors visits each major source from

two to five times per year. Telephone contacts

with these and other APCDS revealed no major

enforcement concerns in 1980.

The nine Regional Water Resources Control

Boards administer the waste discharge requirement program in California. Region 5, headquartered in Sacramento, has approximately 20

personnel to handle all phases of the program.

Approximately 150 permits are issued each year,

25 percent of which are NPDES permits. Major

sources are inspected twice a year, minor sources

perhaps once every 3 years, and about 2,000

sources maintain self-monitors and report

quarterly to the regional board. Telephone contacts with these and several other regional boards

revealed no major management problems.

California is included in two Corps of Engineers

Districts, Los Angeles and Sacramento. The “navigation” branch of the LOS Angeles District is in

charge of permitting and enforcement under the

section 404 program. The Corps presently suffers

from a manpower shortage, as revealed by the

increased number of unresolved violations (from
244 ● industrial and Commercial Cogeneration

66 to 78); enforcement generally is the lowest

priority action for the district.

Rights-of-way for dispersed generating facilities

in California will be sought from three agencies:

the State Lands Commission, BLM, and the Forest

Service. Conversations with agency personnel indicated that at present they were adequately

staffed in 1980, with the possible exception of the

Forest Service.

In summary, the information collected regarding the caseloads and personnel of California environmental agencies showed them to be, in general, better staffed than their counterpart agencies in Colorado. However, legislation enacted

in California in 1981 that requires the State Air

Resources Board and the APCDS to mitigate the

air quality impacts of cogenerators smaller than

50 MW, and to secure offsets for them, could tax

the resources of the APCDS. Also, as in Colorado,

the agencies administering the water programs

(NPDES, sec. 404 and sec. 401 programs) appear

to suffer from manpower shortages that result in

lax enforcement. Finally, the rights-of-way for

facilities on Federal lands administered by BLM

or the Forest Service could be a bottleneck in the

permitting process if the number of applications

increased significantly or the number of personnel to process them decreased.

Potential Impacts on Agency Caseloads

Few market penetration estimates are available

for cogeneration (see ch. 5). Therefore, to gauge

the effects of cogeneration permitting and enforcement on agency caseloads, State agencies

primarily responsible for cogeneration’s development or regulation were contacted and asked to

provide their best estimates for potential development through 2000. The results of this informal

survey are presented in table 57. It should be emphasized that these are not official or precise

estimates based on any formalized methodology,

but instead typically were the result of “brainstorming” sessions held by agency personnel. To

determine the permit and other regulatory requirements of the amount of cogeneration capacity shown in table 57, assumptions were made

concerning, among other things, the size and

location of the facilities.

Table 57.—Penetration Scenario for Cogeneration

in California and Coiorado

MW capacitv installed

Year California Colorado

1,700 170

1990 . . . . . . . . . . . . . . . . . . . . 2,300 230

1995 . . . . . . . . . . . . . . . . . . . . 3,600 360

2000 . . . . . . . . . . . . . . . . . . . . 6,000 600

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).

First, it was assumed that, in Colorado, all new

cogeneration units will file an Air Pollution Emissions Notice (APEN). Second, PSD permits were

assumed to be required under the Clean Air Act

for all sources over 10 MW and for one-half of

the sources under 10 MW. Third, 25 percent of

cogeneration units were assumed to require an

NPDES, section 401 or 404 permit under the

Clean Water Act. Fourth, 25 percent of cogeneration units would require State and/or Federal

rights-of-way, and 25 percent also were assumed

to require consultations with wildlife and historical agencies.

The market penetration assumptions and their

assumed regulatory requirements were combined

to estimate the increased agency responsibilities

for permitting and enforcement due to cogeneration. The results of this analysis must be viewed

as one possible scenario out of many plausible

futures due to the large uncertainties in working

with informal market penetration estimates. However, it can be stated that the results presented

below are a high estimate of the increased

regulatory burden because the deployment assumptions described above are based on size or

siting conditions that would result in many cogenerators being subject to the full range of

regulatory requirements. If cogenerators tend to

be smaller or located in different areas, then the

increase in permitting and enforcement responsibilities would be less than that shown below.

Colorado

The projected increases in agency workloads

in Colorado due to the future deployment of cogeneration technologies are presented in table

58. There is expected to be an increase of less
Ch. 6—Impacts of Cogeneration ● 245

Table 58.—increase in Agency Workloads Due to the Deployment of Cogeneration Technologies in Colorado

Projected average increases

Current in cases per year

Agencv staff

Current

case load 1981-85 1988-90 199; -95 1998-2000

1. Air Pollution Control Division, Colorado

Department of Health:

1. Air Pollution Emission Notices. . . . . . . . . 4

2. Inspections. . . . . . . . . . . . . . . . . . . . . . . . . . 20

Il. Region VIII–EPA:

1. PSD permits . . . . . . . . . . . . . . . . . . . . . . . . . 5

2. Inspections. . . . . . . . . . . . . . . . . . . . . . . . . . 8

Ill. Water Quality Control Division,

Colorado Department of Health:

1. NPDES permits . . . . . . . . . . . . . . . . . . . . . . 12

2. Sec. 401 certificates . . . . . . . . . . . . . . . . . . 1

3. 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 and

commercial leases) . . . . . . . . . . . . . . . . . . . . . . . 1

VI. BLM-State Office (right-of-way

applications) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12

VII. State Division of Wildlife (consultations) . . . . 18

Vlll. Colorado Historical Society

(consultations) . . . . . . . . . . . . . . . . . . . . . . . . . . . 6

480 2

6

3

18

4

39

7

81

45

300

1

3

2

9

3

18

7

39

300

200

1,000

1

1

3

1

1

6

2

2

15

475a 1 1 1 2

40 1 1 1 2

75 1 1 1 2

185

75

1

1

1

1

1

1

2

2

1,200 1 1 1 2

a 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 cogeneration during the 1981-85 period, and only

a 3-percent increase (over the 1980 base year)

during 1996-2000. Increases in other types of permits are even smaller.

The impact on the number of inspections can

be greater (depending on the current caseload)

due to the fact that a permit is only granted once,

whereas each facility must be inspected every

year. Thus, inspections are cumulative and the

agency must inspect not only the facilities permitted this year, but also all facilities permitted

in previous years that are still operating. Still, only

a 10-percent increase in the number of required

air pollution inspections is shown through 2000.

California

Table 59 presents a similar estimate of the

potential impacts of cogeneration on agency

workloads in California. These impacts are more

difficult to quantify because data on air and water

permit applications are tabulated on a regional

or district basis, and statewide totals were not

available. Table 59 is based on data from selected

California air and water quality districts that tend

to be representative of the potential statewide

agency impact, but the table does not include

the impact of the 1981 legislation (mentioned previously) that shifts the burden of attaining offsets

under the nonattainment area provisions of the

Clean Air Act to the local APCDS.

Table 59 shows that the projected number of

air and water permit applications for cogenerators

and the subsequent enforcement cases is greater

in California than in Colorado due to the larger

assumed penetration of cogeneration in California. However, California agencies tend to have

more staff and other resources and thus the

overall workload impact can be expected to be

roughly similar. But, several of the California environmental agencies already are overextended

and even a minor increase in the workload or

reduction in staff may be difficult to accommodate under present conditions.
246 ● Industrial and Commercial Cogeneratlon

Table 59.—increase In Agency Workloads Due to the Deployment of

Cogeneration Technologies in Caiifomia

Projected average increases

Current Current in cases per year

Agency staff case load 1981-85 1986-90 1991-95 1996-2000

1. California Air Quality Division

State-wide total . . . . . . . . . . . . . . . . . . . . . . . . 1,000+ NA 20 17 37 41

Sacramento District:

1. New Source Review . . . . . . . . . . . . . . . . . . 2 175 1 1 1

2. Inspections . . . . . . . . . . . . . . . . . . . . . . . . . 3 3 6 9 12

II. Water Resources Control Board

State-wide total . . . . . . . . . . . . . . . . . . . . . . . . NA NA 5 4 9 10

Region 5—Sacramento:

1. Waste Discharge Requirementa . . . . . . . . 20 150 2

2.inspections . . . . . . . . . . . . . . . . . . . . . . . . . — 1,500 3 6 9 12

Region 9—San Diego:

1. Waste Discharge Requirementa 

. . . . . . . . 2 8 1 2 2

2. Inspections . . . . . . . . . . . . . . . . . . . . . . . . . 17 1,000 3 6 12 18

Ill. Army Corps of Engineers

Los Angeles District:

404 applications . . . . . . . . . . . . . . . . . . . . . . . 11 120 3 2 5 6

IV. State Lands Commission

(rights-of-way) . . . . . . . . . . . . . . . . . . . . . . . . . 100 450 5 4 9 10

V. BLM State Office

(rights-of-way) . . . . . . . . . . . . . . . . . . . . . . . . . 15 150 5 4 9 10

VI. Fish and Game Department

(consultations) . . . . . . . . . . . . . . . . . . . . . . . . . 35 10,OOO 10 9 19 20

VII. Office of Historic Preservations

(consultations) . . . . . . . . . . . . . . . . . . . . . . . . . 4 20 10 9 19 20

NA - 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 most

cases, the deployment of cogeneration should

only increase State and Federal agency caseloads

by a small percentage. The resulting increases in

staff workloads vary depending on present load

and resources. But many of the agencies currently

are understaffed and not able to handle their present caseload. Thus, even small percentage increases in workload would represent a substantial burden for these agencies. Moreover, under

current policies designed to reduce Federal agency budgets and staff resources and turn over more

of the responsibility for permitting, monitoring,

and enforcement to already understaffed State

agencies, the impact of cogeneration may be

more significant than suggested by these data. If

this is the case, then cogeneration projects could

be delayed in the permitting process, or could

be reviewed inadequately resulting in insufficient

controls and enforcement, and therefore a greater

potential for adverse environmental impacts.

ECONOMIC AND SOCIAL IMPLICATIONS

Cogeneration (and other onsite generating institutions traditionally involved in the supply

technologies) 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 and

energy efficiency, the environment, and utility natural gas dwindle, major changes must occur

planning and operations, but also for its possi- in the technical, economic, and institutional conble implications for the economic and political text for energy supply and demand in industrial-
Ch. 6—Impacts of Cogeneration ● 247

ized societies. Cogeneration and small power

production are likely to be a part of these energy

system changes. Moreover, many people advocate the use of dispersed generating technologies not solely because of the perceived technical, economic, or environmental advantages,

but also due to the belief that an energy system

based on these technologies will be more compatible with traditional democratic, participatory,

and pluralistic institutions than a strategy based

on continued reliance on large-scale centralized

technologies. Although a thorough assessment of

these implications is beyond the scope of this

report, some general considerations are discussed

below.

In general, there are two ways in which technological change can be associated with social

or political change: 1 ) a change in the number,

type, or responsibilities of organizations associated with the production, distribution, and/or

operation of a technological system; and 2) the

more general benefits and costs for individuals,

groups, and society as a whole. In the context

of cogeneration, the first type of change relates

primarily to those institutions described in chapter

3–the traditional suppliers, users, and regulators

of electric energy, while the second set of impacts

concerns the likelihood of cogeneration’s resulting in greater centralization or decentralization

in social organization.

The general background for an analysis of the

social and political implications of cogeneration

is described in chapter 3, including the national

energy context, the current status of the electric

utility industry, and the regulatory and institutional aspects of cogeneration. Clearly a fundamental feature of the electric utility industry-its

ability to provide a reliable supply of electricity

at a relatively low price while maintaining its

financial health–has changed dramatically in recent years. Virtually all aspects of the technological and institutional context of the industry have

contributed to this change: capital and fuel cost

increases and environmental concerns have limited the choice of generating technologies and

operating conditions, and have increased the

price of electricity significantly. At the same time,

the rate of demand growth has declined substantially, resulting in excess utility capacity in many

areas, which has contributed to utilities’ financial problems. As a result of these recent changes

in the status of electric utilities, the industry and

its customers and regulators have sought alternate means of achieving the goal of reliable service at a low price. One such means is through

small-scale generating technologies such as cogeneration.

The widespread use of cogeneration could

bring a wide array of changes to the context

described in chapter 3. In general, these changes

can affect the roles, responsibilities, or authority

of energy suppliers or consumers and the relationships among them. Thus, with cogeneration,

the traditional roles of utilities—as suppliers of

electricity—and their customers would have to

be recast as former customers feed cogenerated

power into the grid, and thus become suppliers

of electricity themselves. Alternatively, electric

utilities could own dispersed cogeneration capacity and establish a new role for the industry

as providing alternative energy supply options

(and, in most cases, a new product–thermal

energy) rather than merely facilitating the

development of those options by other parties.

This section focuses on the economic and social implications of cogeneration for utilities and

their customers. It begins with an analysis of the

potential capital cost and employment impacts

of three scenarios for cogeneration market penetration, discusses the effects of the scenario

results on utilities’ planning and operation, and

then briefly outlines some potential impacts in

other economic sectors. The section concludes

with a review of cogeneration’s implications for

the centralization or decentralization of electricity

generation.

Economic Impacts

Due to the large number of uncertainties about

future energy development patterns, it is extremely difficult to develop a quantitative—or even

qualitative—basis for comparing the economic

characteristics of these different development

scenarios. For example, the rate of growth in electricity demand, the rate of inflation, future capital

costs for powerplant construction, and changes

in the regulatory climate all may affect the future
—

248 Industrial and Commercial Cogeneration

costs and deployment characteristics (e.g., plant

size) of utility generating capacity. Similarly,

uncertainties about ownership, future capital

costs, and the choice of technologies make it difficult to project the economic effects of the

widespread use of cogeneration. Furthermore,

due to the lack of recent cogeneration experience, reliable data are not available for items

such as the operating and maintenance (O&M)

labor required for cogenerators. Without a large

computer modeling effort, clearly beyond the

scope of this assessment, it is not possible to

determine the sensitivity of the economic impacts

of cogeneration development to these uncertainties.

However, OTA wanted to be able to define the

problem areas in order to lay the groundwork for

future impact assessments. Therefore, OTA developed three rough market penetration estimates for cogeneration. The assumptions underlying these rough estimates and their derivation

are reviewed briefly, and then the ranges of impacts that could be associated with each estimate

are discussed.

Market Penetration Scenarios

A wide range of penetration estimates are available in the literature on cogeneration and are

displayed in table 60. The highest estimate shown

in the table—which represents 10 to 16 percent

of total projected electricity generation capacity

Table 60.-Market Penetration Estimates

for Cogeneration

Source MW Qualifications

FERC 5,910 Estimate of the marginal increase in

cogeneration capacity caused by

PURPA by 1995.

FERC 27,405 Estimate of the potential for

cogeneration capacity in 1995.

ERA 1,312 Amount initially allowed under FUA

regulations.

ERA 3,920 Likely cogeneration penetration by 1990.

ERA 45,190 Maximum oil/gas-fired generating

capacity potentially displaceable by

cogeneration.

SERI 93,000 Amount of central station baseload

capacity potentially displaceable by

cogeneration.

KEY: FERC—Federal Energy Regulatory Commlssion; ERA—Economic Regulatory Admlnistration; and SERI—Solar Energy Research Instltute.

SOURCE: Off Ice of Technology Assessment.

in the year 2000-is around 70 times larger than

the smallest. To bracket the ranges of penetration estimates, OTA chose three estimates. The

first, a penetration of 50,000 MW by 2000, is an

approximation of the Economic Regulatory Administration’s high estimate for the maximum

oil/gas electric generating capacity potentially

displaced by cogeneration. The implementation

of 50,000 MW of cogeneration would represent

approximately 5 to 8 percent of total projected

installed generating capacity in 2000. Second, as

the middle range, OTA chose the high number

in table 60—approximately 100,000 MW of cogeneration–which would represent 10 to 16 percent of potential installed generating capacity in

2000. Finally, in order to gauge the impacts of

phenomenal success, OTA postulated a penetration of 150,000 MW by 2000, which would be

16 to 24 percent of total projected installed

capacity.

Once these three penetration estimates were

established, it was necessary to disaggregate for

the types of utility generating capacity that would

be backed out by cogeneration and in what parts

of the country. In order to do this it was assumed

that:

●

●

●

●

●

●

30 percent of existing oil-fired steam generating capacity would be converted to coal

or permanently retired;

oil-fired steam plants would be backed out

before gas-fired steam plants;

only oil- and gas-fueled capacity would be

backed out (i.e., no coal, nuclear, hydro, or

other non-oil/gas capacity is replaced by cogeneration);

steam plants would be backed out before

combustion turbines;

oil-fired combustion turbines would be

backed out before gas-fired combustion turbines; and

no utility region would replace all its com-
Ch. 6—Impacts of Cogeneration ● 249

●

●

●

by 2000 and would not be available for

replacement by cogeneration;

of the remaining 70 percent of oil steam

capacity, approximately 40 percent would

be replaced by cogeneration;

approximately 40 percent of the gas steam

capacity would be replaced by cogeneration; and

approximately 1 percent of the oil-fired

combustion turbine capacity would be

backed out by cogeneration.

2. 100,000 MW penetration by 2000:

● 30 percent of oil steam would be converted or retired, and 75 percent of the

remainder would become cogeneration;

. 75 percent of the gas steam capacity

would be backed out;

. 18 percent of the oil combustion turbine

capacity would be replaced by cogeneration; and

. 11 percent of the gas combustion turbine

capacity would be replaced by cogeneration.

3. 150,000 MW penetration by 2000:

●

●

●

●

30 percent of the oil steam capacity would

be converted or retired, and 100 percent

of the remaining oil steam would become

cogeneration;

100 percent of the steam gas capacity

would be backed out by cogeneration;

70 percent of the oil combustion turbine

capacity would be replaced by cogeneration; and

30 percent of the gas combustion turbine

capacity would become cogeneration.

These assumptions were applied to the nine

North American Electric Reliability Council

regions based on 1981 regional oil and gas steam

and combustion turbine capacity (i.e., the

analysis assumes no new oil/gas capacity will be

brought on-line after 1981, regardless of utility

announced plans). Thus, these penetration estimates do no necessarily correspond to the regional cogeneration opportunities that have been

identified in the literature. This is simultaneousIy a result of the linear approach to the analysis

and a desire to gauge the impacts of overwhelming success for cogeneration policy and financial

incentives. The results of this exercise are shown

in detail in table 61.

Financial and Employment impacts

It has been claimed widely that investment in

smaller capacity increments, such as cogeneration systems, would contribute to the improved

financial health of the electric utility industry.

Therefore, OTA undertook a comparison of the

capital costs of the scenarios in table 61 with and

without cogeneration. For the base case—utility

development of 50,000, 100,000, and 150,000

MW of capacity without cogeneration—two sets

of assumptions were used (see table 62). The first

(Case A) uses coal-fired plants with scrubbers to

meet all the baseload capacity requirements. The

capital cost for baseload coal was set at $1,014/

kW (1980 dollars), the same figure used in modeling commercial cogeneration opportunities (see

ch. 5). In the second base case (Case B), 50 percent of the baseload capacity was assumed to be

coal-fired (at $1,01 4/kW) and the other 50 percent assumed to be nuclear powered (at $1,400/-

kW, the average cost, including interest during

construction, for those plants that came on-line

in 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 4,629

ERCOT. . . . . . . . . . . . . . . . – 12,400 1 – 12,401 – 23,260 10 150 23,420 – 31,010 40 398

MAAC . . . . . . . . . . . . . . . . 3,350 – 72 – 3,422 0,300

31,448

— 1,30 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 1,245 329

MARCA . . . . . . . . . . . . . . . 150

5,121

65 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 21,379

SERC . . . . . . . . . . . . . . . . . 5,260 70 103 – 5,433 9,665 140 1,630 12 11,647 13,150 184 7,122 33 20,489

SPP . . . . . . . . . . . . . . . . . . 2,050 2,870 15 – 10,935 3,650 16,635 265 120 20,870 5,130 22,179 1,031 322 28,662

WSCCc . . . . . . . . . . . . . . . . 6,540 1,000 37 – 7,577 12,271 1,875 675 101 14,992 16,362

NERC–U.S. totals. . . . . . 26,960

2,499 2,623 272 21,756

22,695 345 – 50,000 50,542 42,600 6,195 663 100,OOO 67,362 56,782 24,098 1,758 150,000

CT - combustion turbine.

SOURCE: Office of Technology Assessment.
250 ● Industrial and Commercial Cogeneration

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 46,571 124,144

1,400 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 37,500

320-900 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

SOURCE: Office of Technology Assessment.

capacity was assumed to have a capital cost of

$200/kW, the same figure used in the analysis in

chapter 5.

Additional assumptions were needed to develop a capital cost comparison for meeting these

capacity requirements with cogeneration. First,

a mix of cogeneration technologies was established by selecting four mature systems–diesels,

combustion turbines, steam turbines, and combined cycles–that represent a wide range of possible cogeneration applications, and then choosing two sets of penetration mixes for the four

systems (see table 62). The first set (Case C)

assumes that each of the technologies would contribute 25 percent of the capacity requirements.

The second set (Case D) assumes that diesels

would contribute 5 percent, combustion turbines

15 percent, steam turbines 35 percent, and combined cycles 45 percent. Capital costs for these

four technologies vary widely depending on the

size of the system, the fuel used, and the industrial or commercial application. Therefore, the

full range of costs given in chapter 4 was used

(see table 18).

Table 63 shows the capital investment needs

for meeting the three capacity scenarios based

on these assumptions. As can be seen in table

63, the assumptions used in estimating capital

costs play a substantial role in determining the

impact of substituting cogeneration for central station capacity. For example, in the 50,000 MW

scenario, the central station capital requirements

are as much as 90 percent higher than those for

lower cost cogenerators, and up to 17 percent

lower than those for higher cost cogenerators.

Case B

62,072

62,072

25,856

Case D

7,500

22,500

52,500

67,500

Similarly, the mix of technologies affects the cost

comparison, with Cases A and C having significantly lower capital requirements than Cases B

and D. Equally wide ranges of results are shown

for the 100,000 and 150,000 MW scenarios.

However, if the mean of the cogenerator case

costs is compared to the central station costs, the

cogeneration cases require around 20 to 40 percent less capital than the central station cases.

Still greater uncertainties are introduced into

the capital cost comparison if one factors in interest costs and construction duration. The cost

of capital is heavily dependent on its source, including whether a project is financed through

debt, equity, or internal funds; the source of debt

or type of equity; and the interest rates and rate

of return on equity. If one assumes that all factors except construction duration are equal, then

the cost of capital obviously would be lower for

smaller capacity increments such as cogeneration

than for large central station plants. However,

high interest rates mean that the shorter Ieadtime

for cogenerators offers substantial short-term

financing advantages over central station powerplants.

In addition to examining capital cost differences, OTA also estimated differences in O&M

costs for equal amounts of central station and

cogeneration capacity. The same capacity assumptions as in the capital cost estimates were

used (see table 62), but additional assumptions

had to be made with regard to O&M costs and

capacity factors (see table 64). The results of the

O&M cost comparison are shown in table 65. As

can 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 Percent

difference 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 54,106

Peakload . . . . . . . 69 69

Total . . . . . . . . 46,363 54,175 15.5

100,000 MW:

Baseload. . . . . . . 94,446 112,422

Peakload . . . . . . . 1,372 1,372

Total . . . . . . . . 95,818 113,794 17.2

150,000 Mw:

Baseload. . . . . . .125,680 149,642

Peakload . . . . . . . 5,171 5,171

Total . . . . . . . . 131,051 155,013 16.8

50,000 MW

Diesels . . . . . . . . . . . 4,375-10,000

Gas turbines . . . . . . 4,000-11,250

Steam turbines . . . . 6,875-20,000

Combined cycle . . . . 5,375-10,000

Lowest total. . . . . 20,625

Highest total . . . . 51,250

Mean . . . . . . . . . . . 35,938

100,000 MW:

Diesels . . . . . . . . . . . 8,750-20,000

Gas turbines . . . . . . 8,000-22,500

Steam turbines . ...13,750-40,000

Combined cycle. . ..10,750-20,000

Lowest total. . . . . 41,250

Highest total . . . . 102,500

Mean . . . . . . . . . . . 71,875

150,000 MW:

Diesels . ..........13,125-30,000

Gas turbines . .....12,000-33,750

Steam turbines . ...20,62540,000

875-2,000

2,400-6,750

9,625-28,000

9,675-18,000

22,575 9 76.8 69.0 90.0 82.3

54,750 6.6 –10.0 –16.6 5.5 –1.1

38,663 7.3 25.3 18.1 40.5 33.4

1,750-4,000

4,600-13,500

19,250-56,000

19,350-36,000

45,150 9 79.6 71.9 93.6 66.4

109,500 6.6 –6.7 –13.3 10.4 3.8

77,325 7.3 28.6 21.4 45.2 38.2

2,625-6,000

7,200-20,250

28,875-64,000

Combined cycle. . . . 16,125-30,000 29,025-54,000

Lowest total. . . . . 61,875 67,725 71.7 63.7 65.9 78.4

Highest total . . . . 153,750 164,250 6

9

6 –15.9 –22.5 0.8 –5. 8

Mean . . . . . . . . . . . 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.

SOURCE: Office of Technology Assessment.

Table 64.—Assumptions Used in Estimating Operating and Maintenance Costs

Annual fixed Variable Consumable

Size 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 2.6

Light 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 3.0-5.1

Diesel . . . . . . . . . . . . . . . . . . .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, depending

on the mix of equipment types, sizes, and capacity factors. In general, however, the figures in table

65 suggest that O&M costs for cogeneration will

be lower than those for central station capacity

when the cogenerators are larger units suitable

for industrial sites (i.e., steam turbines, combined

cycles), or when they are operating at a lower

capacity factor. Conversely, small cogenerators

with a higher proportion of diesels and gas turbines, and those operating at a higher capacity

factor, tend to have higher O&M costs than central station capacity.

The labor requirements for construction and

for O&M of equivalent amounts of central station

and cogeneration capacity also were compared.

This was extremely difficult due to a lack of consistent data. For example, estimated construction

work-hour requirements by craft and region are

available for central station capacity, but not for

cogeneration. On the other hand, construction
Table 65.—Comparison of operating and Maintenance Costs (1978 dollars x 1Oa

)

Without Cogeneration With cogeneration Percent differences

Percent Percent

difference

Percent

difference 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.lW

Peakload . . . . . 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 2.350-8.063

Combined 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 –19.0

Highest total . 29.679 28.410 4.4 16.425 15.942 3.0 –57.7 –53.6 –90.7 –87.2

Mean. . . . . . . . 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 1.266-2.37

Peakload . . . . . 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 4.7-16.185

Combined cycle 7.163-11.425 12.89-20.57 4.2-6.4 7.57-11.52

Lowest total . 29.838 28.996 9.9 16.530 15.078 9.2 11.9 21.8 –26.2 –16.3

Highest total . 59.355 58.820 4.4 32.850 31.860 3.0 –55.4 –51.3 –88.5 –85.0

Mean. . . . . . . . 44.596 41.909 6.2 24.690 23.479 5.0 –28.1 –22.0 –64.2 –58.5

150,000 MW: 150,000 MW:

Baseload . . . . . 44.582 30.322 Diesels . .......17.03-32.6 3.414.513 9.64-17.78 1.93-3.58

Peakload . . . . . 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 7.05-24.25

Combined cycle 10.7$17.14 19.34-30.85 6.31-9.6 11.36-17.28

Lowest total . 44.750 40.510 9.9 24.785 22.620 9.2 1.1 11.0 –36.3 –28.6

Highest total . 89.070 85.223 4.4 49.260 47.630 3.0 –85.3 –61.3 –96.7 –93.3

Mean. . . . . . . . 66.910 62.887 6.2 37.023 35.225 5.0 –36.6 –32.6 –73.4 –67.9

aA negative percent difference means that cogeneratlon costs are higher, and a positive percent difference indicates that central~ station costs are higher.

SOURCE: Office of Technology Assessment.

88.0 74.0 29.8 36.7

–0.2 2.8 –36.2 –35.3

28.2 33.1 –10.7 –5.1

88.1 76.1 32.4 41.3

2.3 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 –42.7

20.0 24.9 –17.7 –12.8
Ch. 6–Irnpacts of Cogeneration ● 253

labor costs are available for cogenerators, but

usually are not broken out in surveys of central

station installation costs. Moreover, labor requirements and costs for central station capacity vary widely by region and type and size of

capacity.

However, in order to derive broad estimates

for comparison purposes, the available data were

applied to the three scenarios described above

based on the capital and O&M cost estimates in

tables 63 and 65. To estimate cogeneration construction labor requirements in work-hours, OTA

used existing estimates of labor costs and divided

by the 1979 average cost per work-hour for construction labor. The results were then compared

to existing estimates of work-hour requirements

for central station powerplants (see table 66).

As with the cost estimates in tables 63 and 65,

the construction labor requirements in table 66

vary widely due to the wide range in the underlying assumptions. For example, for the 50,000

MW scenario, cogeneration is shown as requiring from 40 percent fewer to as much as 70 percent more work-hours than central station plants,

depending on the size, type, and location of the

central station capacity, and the size and type of

cogenerators. Similar wide ranges are shown for

the 100,000 and 150,000 MW scenarios. In general, construction labor needs for cogeneration

are higher than those for an eqivalent amount

of central station capacity when small-to mediumsized cogeneration units are installed, and lower

when large cogenerators are used.

Although it is not possible to project actual construction labor needs without additional information on the size and type of cogeneration capacity

to be used, it is possible to qualitatively compare

the types of jobs that might result. Powerplant

construction labor may be broken down into approximately 15 different craft requirements (see

table 67). Not all of the skills listed in table 67

would be needed for cogeneration installation,

nor would the proportion of each craft be similar

(although actual craft needs for installing cogeneration have not been published).

The location and duration of labor needs also

will be quite different for cogeneration and central powerplants. Central station capacity construction is likely to occur in larger capacity increments at relatively isolated rural sites, and to

Table 66.–Comparison of Construction Labor Requirements (WH x 106)

Without cogeneration With cogeneration Percent dlfferencea

Percent Percent

difference 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. . . . . . . . 389.8-452.0

Peakload. . . . . . . . 0.88-1.24

Lowest total. . . 370.88

Highest total . . 453.24

Mean . . . . . . . . . 411.98

100,000 MW:

Baseload. . . . . . . . 754.45-922.1

Peakload. . . . . . . . 17.59-24.63

Lowest total . . 772.04

Highest total . 946.73

Mean . . . . . . . . 859.39

150,000 MW:

Baseload, . . . . . . 1)005 .6-1,229.0

Peakload. . . . . . . . 88.3-92.8

Lowest total. . 1,071.9

Highest total 1,321.8

Mean . . . . . . . . . 1,196.9

497.6-646.0

0.88-1.24

498.48

847.24

572.88

1,015 .2-1,318.0

17.59-24.63

1,032.79

1,342.63

1,187.7

1,353 .2-1,758.5

66.3-92.8

1,419.5

1,849.3

1,634.4

29.4

35.3

32.7

28.9

34.6

32.1

27.9

33.3

30.9

50,000 MW

Diesels . . . . . . . . . . . . 72.92-186.67

Gee turbines . . . . . . . 46.15-129.81

Steam turbines . . . . . 132.21484.62

Combined cycle , . . . 82.69-153.85

Lowest total . . . . . 333.97

Highest total . . . . . 834.96

Mean. . . . . . . . . . . . 584.48

100,000 MW:

Dlesels . . . . . . . . . . . . 145.84-333 .34

Gas turbines . . . . . . . 92.30259.82

Steam turbines . . . . . 264.42-789.24

Combined cycle . . . . 185.38-307.70

Lowest total . . . . . 887.94

Highest total . . . . . 1,689.90

Mean . . . . . . . . . . . . 1,188.9

150,000 MW:

Diesels . . . . . . . . . . . . 218.76-500.01

Gas turbines . . . . . . . 138.45389.43

Steam turbines . . . . . 396.63-1,153.86

Combined cycle . . . . 248.07-481 .55

Lowest total . . . . . 1,001.9

Highest total . . . . . 2,504.9

Mean . . . . . . . . . . . . 1,753.4

14.58.33.33

27.69-77.89

185.05-537.96

148.85-276.95

378.17

926.13

661.15

29.18-86.67

55.38-155.78

370.1-1,075.92

297.7-553.9

752.34

1,852,3

1,302.3

43.74-100.00

83.07-233.67

555.15-1,613.88

446.55-830.85

1,128.5

2,778.4

1,953.5

11.9

10.4

10.8

11.9

10.4

10.8

11,9

10.4

10.8

10.4 1.5 39.5 28.0

–59.3 –68,6 –25.3 –35. 5

-34.6 –45. 0 –2.0 –12.8

14.5 2.6 42.9 31.4

–55.3 –64.7 –21.7 –31. 9

–30.5 –41.0 1.6 –9.2

6.8 –5.1 34.5 22.8

-61.8 –71.1 -30.1 -40. 2

-37.7 –48. 0 –7.0 –17. 8

a A negative percent difference means that cogeneration labor requirements are higher, and a posltlve percent difference Indicates that central station Iabor requirements

are higher.

SOURCE: Office of Technology Assessment.
. —

254 Industrial and Commercial Cogeneration

Table 67.—Craft Requirements for Central Station

Powerplant Construction

Table 68.—Estimated Operating and

Maintenance Labor

Percent of total construction labor Capacity type Size (MW) WH/MWh

Craft Nuclear Fossil

Asbestos workers/insulation. . 1.6 3.5

Boilermakers . . . . . . . . . . . . . . . 3.3 15.0

Bricklayers/stone masons . . . . 0.4 0.5

Carpenters . . . . . . . . . . . . . . . . . 11.1 8.5

Cement/concrete finishers . . . 1.4 1.1

Electricians . . . . . . . . . . . . . . . . 16.3 14.3

Ironworkers . . . . . . . . . . . . . . . . 7.7 9.0

Laborers . . . . . . . . . . . . . . . . . . . 15.0 11.8

Millwrights . . . . . . . . . . . . . . . . . 2.4 2.9

Operating engineers. . . . . . . . . 6.2 7.6

Painters . . . . . . . . . . . . . . . . . . . 2.5 1.5

Pipefitters . . . . . . . . . . . . . . . . . 26.5 18.6

Sheet metalworkers . . . . . . . . . 1.5 2.0

Truck drivers . . . . . . . . . . . . . . . 3.2

Other workers . . . . . . . . . . . . . . 0.5 0.4

SOURCE: U.S. Department of Energy, Off Ice of Energy Research; and U.S. Department of Labor, Employment Standards Administration, Projections of

Cost Duratlon, and On-Site Manual Labor Requirements for Constructing Electric Generating Plants, 197~19&3 DOE/lFf-O 057 and

DOUCLDS/PP2, September 1979.

entail large influxes of workers (either temporary

residents or commuters) for several years. The

social and economic disruption that can result

from powerplant construction is well documented in the literature. Cogenerators, on the

other hand, are more likely to be installed at commercial or industrial sites, usually located near

population centers. Moreover, because cogeneration would be installed in smaller capacity increments, fewer workers would be required for

each installation. Although the installation jobs

would be of much shorter duration, they would

occur more frequently, providing a steadier regional employment profile. Thus, the potential

for adverse socioeconomic impacts would be

much lower with cogeneration.

Estimated requirements for O&M labor are

compared in table 68. These were not translated

into the three scenarios due to the large number

of uncertainties and gaps in the data. However,

it is clear from table 68 that the labor requirements for cogeneration per megawatthour

of output will be greater than those for central

station capacity. How much greater will depend

on the size, type, and operating characteristics

of the cogenerator. The crafts involved (engineering, fuel handling, general labor) are likely to be

similar for cogeneration and coal-fired powerplants, but, as with construction labor, the location of the jobs will be very different.

Central station. a

Nuclear . . . . . . . . . . . . . . . . . 1,000-2,000

Coal . . . . . . . . . . . . . . . . . . . . 1,000-2,000

Diesel C

b

ogeneration:

. . . . . . . . . . . . . . . . . . 0.24

0.7

1.135

2.84

Gas turbineb . . . . . . . . . . . . . 0.5

10.0

50.0

Steam turbinec . . . . . . . . . . . 15-30

45-70

140-190

0.0389-0.0761

0.0462-0.0793

27.8-55.6

9.5-19.0

5.9-11.7

2.1-4.7

12.6-26.7

0.63-1.3

0.13-0.27

1.114-1.968

0.378-0.464

0.136-0.159

SOURCE: Office of Technology Assessment.

The above comparisons of capital and O&M

costs and labor requirements for equivalent

amounts of central station and cogeneration

capacity indicate that cogeneration has the potential to reduce the cost of supplying electric power

while increasing the number of jobs associated

with electricity generation. * However, depending

on the size and type of cogenerators deployed,

it could have the opposite effect-higher capital

costs and/or lower labor requirements. That is,

the financial and employment effects of cogeneration are highly correlated with economies of

scale. Based on the mean values, however, it is

more likely that cogeneration costs will be lower

and labor needs higher than those for central station powerplants.

Utility Planning and Regulation

Where utilities face financial, fuel availability,

or other constraints on capacity additions, or

where they are heavily dependent on oil-fired

capacity that cannot be converted to coal, co-

*Note that this seemingly anomalous result is possible only if cogeneration installation and operation/maintenance require less

skilled (and thus lower paid) labor than central station plants, which

is likely to be the case.
Ch, 6—impacts of Cogeneration 255

generation can benefit utility finance, planning,

and operations. If utilities own cogeneration

capacity, the potentially lower capital costs—

together with the lower cost of capital that results

from short construction Ieadtimes and smaller

capacity increments—will mean lower shortrun

costs to be passed on to their customers. Other

financial characteristics also would be likely to

improve, including utilities’ ability to finance projects internally and the amount of Allowance for

Funds Used During Construction (AFUDC) (or

Construction Work In Progress–CWIP) and deferred taxes they carry on their books. All of these

factors would tend to slow the rate of growth in

retail electricity rates as well as make utilities

more attractive to investors.

The short construction Ieadtimes and small unit

size of cogenerators also can have important benefits for utility planning and operations. If the demand for electricity increases more rapidly than

utility planners project, smaller plants can be

brought on-line more quickly (i.e., a 2- to 3-year

Ieadtime for cogenerators compared to an 8-to

10-year leadtime for baseload coal plants and 10

to 12 years for nuclear plants). Similarly, if demand grows more slowly than expected, smaller

capacity increments can be deferred more easily and inexpensively than large powerplants for

which planning and construction must begin

years before the power is projected to be needed.

In addition, small unit sizes will have lower

outage costs (less unserved energy) than larger

units, assuming that both sizes present approximately the same degree of reliability.

The potential for all of these benefits would be

enhanced if utilities were allowed to own a 100

percent interest in cogeneration capacity and still

receive unregulated avoided cost rates under

PURPA. That is, their qualifying cogeneration

capacity would be unregulated and the cogenerated power could be valued at the avoided cost

rather than the average cost. Thus, the utility

could earn a higher rate of return on it than on

their regulated generating capacity. This higher

return would compensate them more fully for the

perceived risks of investment in “unconventional” technologies with relatively uncertain

operating characteristics, but probably would still

be lower than the rate of return required by industrial or commercial owners. Similarly, the

higher return would increase the cost that would

have to be passed on to customers, but that cost

might still be lower than under nonutility ownership.

Utilities with long-term contracts for purchases

of cogenerated power could still use the smaller

capacity increments to reduce the downside risk

of sudden unexpected changes in demand

growth. outage costs also would probably remain

relatively equal under either form of ownership,

although utilities may consider cogenerators they

own to be more reliable due to perceived or actual differences in dispatchability and other factors affecting reliability. But these considerations

are tempered by the probability that cogeneration would supply more electricity to the grid

under utility ownership. Utilities typically require

a lower rate of return—even when unregulated—

than private investors, and financially healthy

utilities often have access to lower cost capital.

Thus, cogeneration investments maybe economic for utilities when they wouId not be for users

or third parties. Furthermore, except where

avoided costs are very high, utilities would be

more likely to invest in cogeneration systems with

a high ratio of electricity-to-steam production (E/S

ratio).

For nonutility ownership, the benefits from cogeneration’s potentially lower power production

costs would accrue to the cogenerator rather than

to the utility or its customers. Under the original

FERC rules implementing PURPA, the cogenerator would be paid for power supplied to the grid

based on the utility’s avoided cost of alternative

energy (or marginal cost), rather than on the average energy cost (see ch. 3). This higher cost would

be passed on to the utility’s noncogenerating customers. Moreover, the utility would have administrative and other expenses related to capacity that were not included in its rate base and on

which it would not earn a rate of return.

Finally, utilities may be subject to planning and

financial risks from the increased competition

posed by nonutility-owned cogenerators. When

competition takes away utility customers, the

joint or common costs get a reduced revenue

contribution. This reduction in fixed cost
256l Industrial and Commercial Cogeneration

coverage either endangers service to other

customers or imposes a greater share of the cost

burden on them. This phenomenon is not unique

to electric power. It has occurred in the transportation industry, most dramatically with the competition between trucking and railroads, and the

same problems currently are being faced by the

telecommunications industry. It is essentially the

same as the issue of loss exposure raised by ConEd in the New York Public Service Commission

hearings on cogeneration (see ch. 3). Remedies

for such problems, insofar as they exist, must be

found in the rate structure of the utility, or

through changes in Federal policy that would

equalize utilities’ competitive position in cogeneration markets.

The following material analyzes the potential

effects of competition on two utilities: Commonwealth Edison (CWE), which is committed

to major central station capacity construction,

and Pacific Gas & Electric (PG&E), which is constrained from adding large amounts of new central station capacity and has been ordered by the

California Public Utilities Commission to aggressively seek cogeneration capacity. Background information on the implementation of

PURPA in these utilities’ service areas may be

found in chapter 3.

Current cost conditions in the electric power

industry can give rise to reduced fixed cost

coverage. These are illustrated for CWE in figure

61, which shows the average fixed cost portion

of CWE revenue requirements, based on their

current construction plans, for growth rates of 4,

2, and O percent (CWE projects 4 percent load

growth). Any load growth lower than 4 percent–

whether it is due to competition from onsite generation or from conservation-will result in sales

below CWE expectations and thus a rising burden

of fixed costs for remaining customers. As shown

in figure 61, the larger the shortfall in sales, the

faster the fixed cost burden rises.

Turning to the California context, it is more

readily apparent that PURPA payments to cogenerators can lead directly to reduced fixed cost

coverage. PURPA payments for capacity are fixed

costs from the ratepayers’ point of view, even if

their basis in value comes from fuel savings.

Figure 61 .—CWE Fixed Cost Structure as a

Function 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 from

a private party, on an avoided cost basis, the

PURPA payments should drop with decreasing

demand. However, this may not be the case, or

at least not to any significant degree. To demonstrate this proposition, the cost structure of

PG&E is illustrated in table 69.

The differences between the base case and the

PURPA case in table 69 are due to two factors.

First, there is more than twice as much cogeneration in the PURPA case compared to the base

case (940 MW v. 2,000 MW). The larger amount

of cogeneration represents a fulfillment of the

goal set for PG&E by the California public Utilities

Commission. The second difference is that the

Table 69.—Pacific Gas & Electric Cost Structure

Adjusted for PURPA, 1990

Base case PURPA case

Fixed 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 kWh

Fixed cost/kWh to

noncogenerators . . . . . . . . . . 80.8 mills 81.4 mills

SOURCE: Edward Kahn, and Michael Merritt, Dispersed Electricity Generation:

Plannlng and Regulation (contractor reporl to the Office of Technology

Assessment, 1981).
Ch. 6—impacts of Cogeneration . 257

base case assumes utility ownership while the

PURPA case assumes private ownership.

Table 69 shows the same qualitative phenomenon as figure 61—a rising burden of fixed or

common costs to be borne by the nongenerating

customers remaining on the utility system. In the

PG&E case, the shift is clearly due to the effects

of cogeneration. Moreover, a significant part of

the increase in fixed cost comes from PURPA incentives under the simultaneous purchase and

sale provision—estimated at roughly $445 million,

assuming that cogenerators will pay rates for their

own use that are roughly 70 percent of the average price (18). The estimate may, of course, be

too high. If it is high, the net fixed costs would

be less and the risk less extreme. However, the

simultaneous purchase and sale incentive is only

about one-third of the fixed cost differential (445/

1,270) in the two cases. Therefore, even a change

in the rate structure to reduce that incentive

would not by itself eliminate the problem. Customers remaining on the utility system would

have fewer incentives to conserve electricity at

this point because reduced sales would only increase the fixed cost burden (29).

Thus, the increasing burden of fixed costs can

result from either excess capacity (CWE) or competition (PG&E). Of the two distinct routes to the

high fixed cost situation, it is likely that the competition risk may be smaller than the excess capacity risk. The reason for this is the potential

escalation in fuel costs. The calculations in table

69 show fuel costs ranging from about 50 percent of total cost in the base case to about 37 percent of total cost in the PURPA case. The fuel cost

fraction would rise if fuel cost escalated faster

than assumed (roughly 10 percent nominal annual rate). Although no one can predict future

oil prices (the dominant fuel in California), the

tendency in the past has been to underpredict

price increases (29).

On the other hand, the excess capacity risk results in part from the “lumpiness” of investment

in baseload facilities. New central station plants

come in large unit sizes and require long construction and licensing times. Further, accurate

demand forecasting is difficult, and the tendency in the past has been to overestimate the future

size of the electricity market. However, demand

growth is more sensitive to price increases than

pre-1 973 behavior seemed to indicate and large

baseload projects are difficult to adjust to reduced

growth. Powerplant construction can be deferred

(which means extra carrying cost) or canceled

(which means losses). Thus, once large projects

are initiated there is a tendency to continue them

regardless of changing circumstances.

Therefore, where construction commitments

are large (as in the CWE case), the balance of

economic and institutional forces points toward

a greater risk from excess capacity than from

competition. At the present time, however, the

risks from cogeneration competition are more

potential than real due to its low market penetration. One way utilities can deal with possible

future competitive threats is by trying to capture

the new markets with their own investment.

Other Economic and Social Impacts

OTA’s analysis focused on the economic and

social impacts of cogeneration on electric utilities

and their customers. However, cogeneration may

also have important socioeconomic implications

in other sectors, such as business development

patterns for fuel and technology suppliers and

capital markets, and the role of policy/politics in

energy supply. A detailed assessment of these

issues is beyond the scope of this report, but

some generaI considerations are outlined below

as a framework for future analysis.

PURPA’S partial deregulation of entry into the

electricity generation market has received a lot

of attention for the opportunities it presents for

new and small businesses, and for the changes

it may bring to existing economic sectors. For example, the primary sources of fuel for cogenerators in the near term are not expected to be different from the fuel sources for electric utilities

(oil, gas, and coal). However, as advanced cogeneration technologies with greater fuel flexibility emerge, new opportunities should arise for

suppliers of alternate fuels such as municipal solid

waste (MSW), biomass, and synthetic liquids and

gases. In some cases, these markets will be captured by existing large energy companies seek-
258 . Industrial and Commercial Cogeneration

Photo credit: Environmental ProtectIon Agency

Advanced cogeneration technologies with greater fuel flexibility may be able to burn municipal solid waste, contributing to

the solution of waste disposal problems and providing a new source of revenue for disposal collection agencies

ing diversification opportunities. But othe r

markets may be served by local governments or

private entrepreneurs (e.g., MSW), or supplied

onsite (biomass), or captured by utilities or

cogenerators themselves. For instance, one promising scheme for alternate-fueled cogeneration

uses a centrally located gasifier that converts coal,

biomass, petroleum coke (from refineries), or

other nonpremium fuels to a low- or mediumBtu gas for distribution to cogenerators within a

limited radius. The gasifier could be owned jointly

by the cogenerators (e.g., in an industrial park)

or by the local utility as a means of diversifying

its energy supply business. A central gasification/remote cogeneration scheme proposed by

Arkansas Power & Light is described in detail in

chapter 5. Such a scheme would enable cogenerators who cannot use nonpremium fuels (e.g.,

due to environmental, economic, or site limitations) to centralize the costs of fuel conversion

and distribution. Thus, economic and policy considerations that discourage the use of oil and gas

in cogeneration also may help to create new

business opportunities for a wide range of fuel

suppliers. In many cases these opportunities will

go to local distribution companies, as opposed

to the large producers or distributors that supply central station powerplants.

Markets for technologies also could change as

a result of the widespread use of cogeneration.

Electric utilities or their construction contractors

generally interact directly with the major manufacturers of powerplant equipment. Cogenerators, on the other hand, will be more likely to

purchase a total system from vendors acting as

middlemen between manufacturers and purchasers. Such vendors will be able to offer a wider
Ch. 6–impacts of Cogeneration .259

range of “package” systems than a single manufacturer, and to tailor the package more closely to a user’s specific needs. Moreover, whereas

utilities generally perform their own maintenance,

cogeneration vendors may evolve as total service

companies that offer repair and maintenance as

part of the sales contract. The potential role for

such service companies in spreading the burden

of maintenance costs and labor requirements

contributes to the uncertainty (discussed earlier

in this chapter) in assessing these factors. Alternatively, if utilities own cogenerators, they may

tend to continue to deal with the major manufacturers with which they are familiar, and to provide their own maintenance.

Similar changes might appear in capital markets

with widespread investment in cogeneration. The

small unit size of cogenerators will mean smaller

but more frequent investments in generating capacity increments. If utilities are investing, then

their capitalization is likely to shift away from

long-term debt and equity to short-term debtor

retained earnings. Alternatively, utilities may

establish innovative low-interest loan programs

for cogenerators. Third-party investors may play

a major role due to the tax incentives introduced

by the Economic Recovery Tax Act of 1981. Or

potential cogenerators may shift their investment

priorities from process equipment to cogeneration. As a result of all these types of owners, new

capital markets for energy projects will be introduced. Traditional lending institutions such as

banks could become financiers for energy projects. Investment firms will have a new option for

sheltering their clients’ income. A wide range of

traditional financiers may establish leasing subsidiaries.

The potential impacts on fuel, technology, and

capital markets outlined above will themselves

have far-reaching effects. For example, concern

is frequently expressed about the anticompetitive

aspects of utility investment in cogeneration. It

is argued that utilities may favor their own subsidiaries in contracting for cogenerated power,

or favor one or two manufacturers or vendors of

cogeneration systems, and thus foreclose small

business opportunities and/or stifle the development of innovative technologies. Similarly, utility loan programs have raised questions about

competition in the banking industry, where

market entry traditionally has been regulated.

Although these concerns may be real, closing

these markets to utilities could also stifle the

development of cogeneration capacity, and it

may be more sensible to resolve any questions

about the competitive effects of utility investment

through carefully drafted legislation and regulations, and through established legal and administrative remedies.

The introduction of new fuel supply configurations could have significant impacts on other fuel

users as well as on land use patterns and other

environmental factors. If oil- or gas-fired cogeneration achieved a significant market penetration,

changes could occur in the way these fuels are

allocated among noncogenerating residential,

commercial, and industrial customers. Centralized fuel conversion systems such as gasifiers

would require new dedicated distribution systems, and would strongly influence the location

of new cogenerating industries. Where fuel conversion is not centralized, fuel delivery and

storage may pose substantial problems, especially

in urban areas. If the cogeneration site is not able

to accommodate large fuel storage facilities (e.g.,

30 days’ supply), then frequent deliveries could

involve noise and/or air pollution as well as traffic congestion. As with the concerns about the

anticompetitive aspects of utility ownership of

cogenerators, these potential land use problems

are probably best solved through careful design

and siting of cogenerators and rational local planning, rather than through general disincentives

to cogeneration.

Centralization and Decentralization of

Electricity Generation

In the two decades following World War II, the

electric power industry operated under a declining production cost curve even during periods

of general increases in the cost of fuels and the

overall consumer price index. The primary contributor to these declining costs was the capture

of significant economies of scale that allowed

larger powerplants to use fuel more efficiently

(see ch. 3). At the same time, obvious cost sav-
260 ● Industrial and Commercial Cogeneration

ings became associated with the location of multiple units on single sites, and planning responsibilities, decisionmaking authority, and capital assets

became concentrated in a rapidly diminishing

number of institutions—primarily investor-owned

utilities (32). The resulting combination of large

powerplants concentrated at a central location

and under the authority of a limited number of

large organizations has become known as the

centralization of the utility industry.

When engineering economies of scale were no

longer able to offset other costs for larger powerplants, and the electric power industry’s declining cost curve disappeared in the late 1960’s, the

value of such centralization became increasingly

debated. Questions have been raised about the

role of centralization in the adverse environmental impacts of large powerplants, in utilities’ financial deterioration, and in more qualitative concerns such as individual’s feelings that they have

lost some control over important aspects of their

lives and livelihoods. As a result, it is frequently

suggested that the electric power industry should

be restructured in favor of a decentralized system

based on small-scale technologies located at or

near the point of use and subject to local or individual control. This position is advocated by a

wide range of groups with varying goals, but the

central features of the argument generally are

considered to be embodied in the writings of

Amory Lovins and colleagues on the “soft energy

path” (31).

This section reviews the context of the debate

over centralized and decentralized electric energy systems, then analyzes the role that cogeneration might play within that debate. *

Technology and Values

One of the critical features of the current energy policy debate is the lack of consensus on both

the facts and the values surrounding energy policy. Thus, there are radically different perceptions

about the actual nature of the “energy problem”

as well as disagreements about the role energy

plays in structuring social organization. One of

the most pervasive of these disputes is over the

*Much of the following discussion is from Hoberg (26).

centralization or decentralization of electric

power production.

The point of view that argues for “decentralization” is embodied in a number of separate movements (e.g., appropriate technology, environmentalist, antinuclear), each of which has its own

criteria for evaluating energy technologies. But

they all tend to converge with regard to proposals

for small-scale renewable energy technologies,

as embodied in the “soft-path” future first

described by Lovins.

The three primary components of Lovins’ soft

energy path are:

●

●

●

prompt commitment to maximizing end-use

efficiency;

rapid development and deployment of smallscale renewable-fueled technologies whose

energy quality closely matches the required

service; and

special transitional fossil fuel technologies.

The first component would minimize the energy

input into a given end-use function. The second

would accelerate reliance on renewable fuels and

on energy technologies that contribute to selfreliance, and the third would “tide us over” until the system adjustments anticipated by the first

two can be made. Because of Lovins’ overriding

concern with thermodynamic efficiency, cogeneration—primarily industrial cogeneration using

coal-fired fluidized bed combustion systems—is

viewed as a major contributor to the transitional

fossil fuel technologies.

Lovins’ writings have played a major role in

winning a place for alternative technologies in

the energy policy debate. However, as in other

energy policy areas, the facts and values surrounding soft energy paths are subject to debate.

With respect to the facts, the uncertainties in capital and operating costs and in output characteristics are especially important. In regard to the

values, there is disagreement not only between

soft and hard path advocates, but also between

different segments of the alternative energy movement.

For example, Lovins only applies soft energy

technologies at the margin; he does not advocate

the early replacement of existing central station
—

Ch. 6—impacts of Cogeneration 261

powerplants and their accompanying transmission and distribution networks. Other “appropriate” technology advocates focus on stand-alone

applications that are totally incompatible with the

existing electricity supply system (e.g., windmills

or photovoltaics coupled with battery storage).

Moreover, there is no real consensus among soft

path advocates as to which values should predominate in such technological decisions. Some

place a great deal of emphasis on fostering decentralization in order to gain control over the technologies that affect their lives, while others emphasize economic efficiency.

The debate about the role of cogeneration in

energy policy typifies these fact and value disputes in several ways. It can be a small-scale technology located at the point of use, or larger systems can be centrally located and the energy

products distributed among several co-owners or

customers. Cogenerators can use coal or other

alternate fuels as their primary energy source, but

the most economic systems for some applications

will rely on oil or gas in the near term (e.g., gas

turbines, diesels). Cogeneration can present significant energy savings when compared to central station generation and separate thermal power production, but it also will be competing

against conservation, coal, and renewable fuels

on many electric systems, and its electric power

output is less certain. Thus, whether cogeneration will be a favored technology to advocates

of decentralized energy systems will depend

heavily on the technology and the mode of deployment chosen.

Centralization and Decentralization

The concepts of centralization and decentralization are critical to an assessment of the social

and institutional impacts of dispersed electricity

generation, but are all too often left undefined.

In this discussion, these terms will be used to

describe a measure of the distribution of control,

authority, or autonomy throughout a system (in

this case the energy and social systems), where

“control” refers to the ability to affect the

behavior of others or of the system itself. A situation in which a single component controls all

others and the system itself (e.g., a monopoly or

monopsony) defines the centralized extreme,

while at the decentralized extreme each individual is autonomous and therefore cannot change

the system or its components (e.g., perfect competition). This concept of centralization is similar

to that in organization and administration theory,

where the concern is locating the decision making authority within an organization or institution.

The concepts of centralization and decentralization of control are particularly important to the

structure of organizations because mismatches

between that structure and the task it is designed

to accomplish can result in inefficiencies (7).

The centralization or decentralization of control should be distinguished from other concepts

that focus on size or geographical concentration.

While these factors may influence the degree of

centralization, they do not define it. Similarly, it

is useful to distinguish technical from social centralization. Thus, technical systems can be defined in terms of their dependence on one or a

few components (e.g., central dispatch of an interconnected electric utility system) without necessarily implying an equal degree of authority

over a related social system.

Centralization/Decentralization

and Cogeneration

How cogeneration fits into this definition of

centralization and decentralization will depend

on its deployment and operating characteristics.

Thus, the lower minimum efficient scale of cogeneration relative to conventional powerplants can

contribute to decentralization because the smaller size and lower costs make the technology accessible to more people. On the other hand, cogenerators are more complex than traditional onsite thermal energy systems (e.g., boilers, furnaces), and they are likely to require new technical and managerial skills in industrial and commercial enterprises that own and operate them,

or in utility companies that deploy them in their

service areas. Whether a firm decides to train or

acquire its own expertise or to rely on a vendor,

utility, or other service company may determine

that firm’s perceptions of autonomy.

Similarly, the resource/demand characteristics

of cogeneration, including the type of primary

energy source and its concentration or density,
. — —

262 Industrial and Commercial Cogeneration

the type of technology and its concentration, and

the actual number of components in the resource, conversion, and demand categories will

influence the degree of centralization. In general,

decentralization might occur if the energy required within a given area is approximately equal

to the energy available in that area. If energy must

be imported, the system will be more vulnerable

to external control and thus relatively centralized.

Similarly, where the energy can be exported or

distributed over a larger area, a relatively centralized dependence of dispersed users on a concentrated resource may result.

Finally, the amount of political or social importance associated with cogeneration will be a

significant factor in determining centralization

and decentralization of control. For example,

PURPA encourages grid-connected cogeneration,

offering economic incentives for operating characteristics (such as central dispatch) that increase

utilities’ control over the deployment and use of

the technology.

Because all these characteristics will vary widely, it is clear that cogeneration cannot automatically be considered a decentralized technology

that will lead to a decentralized social structure.

Similarly, central station powerplants will not always lead to centralized social organization, although this has been the predominant trend in

the electric power industry. Rather, it is possible

to envision centralized technologies that contribute to a decentralized social or political system,

as well as decentralized technologies leading to

centralization of control. For example, Franklin

Roosevelt saw centralized generation of electricity with transmission to outlying areas as the key

to a decentralized society:

Sheer inertia has caused us to neglect formulating a public policy that would promote the opportunity to take advantage of the flexibility of

electricity; that would send it out wherever and

whenever wanted at the lowest possible cost. We

are continuing the forms of overcentralization of

industry caused by the characteristics of the

steam engine, long after we have had technically

available a form of energy which should promote

decentralization of industry (34).

The central theme underlying the possibility of

such a centralized energy system supplying a

decentralized society is the proposition that the

most effective means of preserving diversity, flexibility, and freedom of choice in social structure

is to ensure abundant supplies of energy at the

lowest possible cost (termed the “cornucopia

strategy”). The less scarce the fundamental energy input, the less influence energy would have

on the structure of social organization. Cogeneration (and other alternative technologies) would

be included in the cornucopia strategy to the extent that they pose economic advantages over

conventional technologies. Moreover, a recent

analysis suggests that cogeneration combined

with the centralized electricity grid will contribute

to decentralization in the economy(1). This analysis argues that the lack of significant scale effects

associated with connection to a centralized grid

will mean that large firms will not have competitive advantages over small firms in energy access

(ignoring declining block rates or relative process

efficiencies). Thus, diversity and decentralization

of organizational structure in industry and business might be promoted.

The idea of centralized energy systems leading

to decentralized social organization looks more

to fragmentation of power among interest groups

and various levels of government wherein freedom and flexibility in lifestyles are fostered and

preserved, while the appropriate technology

movement embodies a notion of decentralization

that consists of a loosely coupled system of nearly

autonomous and self-reliant communities. As

such, the former view can accommodate a great

deal of specialization and differentiation in societal function, at aggregate levels, that the latter

fundamentally opposes.

On the other hand, it is also possible to envision a decentralized energy system in a centralized political economy. This might come about

in two ways. One analysis considers the case

where some combination of a deterioration in the

economics of utility generated electricity and an

enhanced competitive position of cogeneration

systems brings about an industrywide movement

towards cogeneration as the source of electric

power and process heat/steam. Because there are

economies of scale (in capital equipment, O&M,

pollution control, etc.) inherent in cogeneration

devices, the larger firms in a certain industry
Ch. 6—impacts of Cogeneration . 263

group will be able to produce energy more

cheaply than the smaller firms, which would give

the larger firms a competitive advantage, contributing to the elimination or absorption of smaller

firms by the larger firms. The end result is centralization in industry (as measured by industrial

concentration) (26).

A second view of this configuration-decentralized energy systems in the context of centralized

control—also could result from policy considerations. In fact, some commentators have suggested

that this is the most likely result:

The most plausible vision of a renewable-energy future is one that offers less freedom and

less true diversity, more centralization of decision, and more state (i.e., government) interference and corporate domination in our lives, than

is the case in the present society in the United

States . . . (37).

Clearly, this combination of decentralized energy

and centralized social organization depends

more on policy orientations than on any of the

other factors that influence the degree of centralization/decentralization. Lovins terms this alternative a coercive one in that it is most likely to

result from policies that mandate—rather than use

CHAPTER 6

1. Asbury, Joseph G., and Webb, Steven B., Centralizing or Decentralizing: The Impact of Decentralized Electric Generation (Argonne, Ill.: Argonne

National Laboratory, ANL/SPG-16, 1979).

2. Bell, Douglas, Standards Development Branch,

U.S. Environmental Protection Agency, private

communication to OTA.

3. Bhargava, Vijay, California Air Resources Board,

private communication to OTA, September 1981.

4. Bioenergy Bulletin, vol. 11, No. 3, published by

U.S. DOE, Region X, Mar. 15, 1981.

5. Breitstein, L. and Gant, R. E., M/US Systems Analysis–Effects of Unfavorable Meteorological Conditions and Buildings Configuration on Air Quality

(Oak Ridge, Term.: Oak Ridge National Laboratory, ORNL/HUD/MIUS-29, February 1976).

6. Brooklyn Union Gas/FIAT, TOTEM Technical Description, October 1978.

7. California Air Resources Board, Proposed Strategy

for the Control of Nitrogen Oxide Emissions from

market incentives for—a decentralized energy

system (or the proverbial distinction between the

carrot and the stick). Alternatively, such centralization could result from demands for control of

the impacts of decentralized technologies in that

it is easier to impose and enforce controls in a

centralized manner (e.g., uniform Federal standards for system design at the point of manufacture) than it is to monitor and enforce such controls at myriad points of use. At the extreme,

authoritative solutions may be seen as necessary

to meet an industrial society’s need for adequate

and reliable supplies of energy, or to allocate

losses in the event of an energy supply shortfall

(37).

As has been seen above, cogeneration (and

other dispersed generating systems) cannot necessarily be considered either a decentralized or

a centralized energy system nor will they necessarily lead to either centralization or decentralization of social organization. Rather the degree of

centralization/decentralization will depend on

site specific, market, and policy factors such as

the mode of operation, form of ownership, resulting profit and competitive aspects, and relative

policy emphasis on their deployment.

REFERENCES

Stationary Internal Combustion Engines (State of

California, October, 1979).

8. Casten, Thomas, Cogeneration Development

Corp., private communication to OTA.

9. Chandler, Alfred D., Jr., Strategy and Structure:

Chapters in the History of American Industrial Enterprise (Cambridge, Mass.: The MIT Press, 1962).

10. “Cogeneration Proponents Will Seek An Air Act

Change Recognizing Greater Efficiencies,” Inside

EPA, Apr. 3, 1981.

1 I

, Consolidated Edison Co. of New York, written testimony before the New York State Department of

Public Service, “Environmental Assessment of Cogeneration in New York City,” Mar. 17, 1980, p.

13.

12. Dadiani, John, Cogeneration—Status and Environmental Issues (contract 68-03-2560, draft report to

EPA, 1980),

13. Davis, W. T., and Kolb, J. O., Environment/ Assessment of Air Quality, Noise and Cooling Tower
264 ● Industrial and Commercial Cogeneration

140

15.

16.

17.

18,

19,

20.

21.

22.

23.

24.

25.

26,

27,

28.

29.

Drift From the Jersey City Total Energy Demonstration (Oak Ridge, Term.: Oak Ridge National Laboratory, ORNUHUD/MlUS-52, June 1980).

Domaracki, Alan J., and Sistla, Gopal, testimony

before the State Department of Public Service before the Commission, case No. 27574, July 1980.

Dryer, Frederick, Princeton University, private

communication to OTA, October 1981.

Dukakis, Michael S., Governor’s Commission on

Cogeneration, Cogeneration: Its Benefits to New

Eng/and (Governor of Massachusetts, October

1978).

Energy and Resource Consultants, Inc., Federal

and State Environmental Permitting and Safety

Regulations for Dispersed Electric Generation

Technologies, contractor report to OTA, 1980.

Environmental Defense Fund, An Alternative to

the Warner Va//ey Energy System (Berkeley, Calif.:

EDF, Jlliy 1980).

Environmental Research and Technology, Inc., Air

Quality Impact of Diesel Cogeneration in New

York City, Document P-A 302, November 1979.

Ferris, B. G. Jr., “Health Effects of Exposure to Low

Levels of Regulated Air Pollutants. A Critical Review,” 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, private

communication to OTA.

“General Discussion: Health Effects of Exposure

to Low Levels of Regulated Air Pollutants,” J. Air

Pollution Control Association 28:891, 1978).

Ghassemi, M. and Lyer, R., Environmental Aspects

of Synfue/ Utilization (EPA-600/7-81 -025, March

1981).

Griffin, H. E., et al., Health Eflects of Exposure to

Diesel Exhaust (Washington, D. C.: National Academy of Sciences, 1980).

Hoberg, George, Electricity, Decentralization, and

Society: The Soci~Political Aspects of Dispersed

Electric Generating Technologies, contractor report to OTA, January 1981.

ICF, Inc., A Technical and Economic Evaluation

of Dispersed Electric Generation Technologies,

contractor report to OTA, October 1980.

Jarvis, P. M., “Methanol as Gas Turbine Fuel,”

paper presented at the 1974 Engineering Foundation Conference, Methanol as an Alternate Fuel,

Henneker, N. H., July 1974.

Kahn, Edward, and Merritt, Michael, Dispersed

Electricity 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 Above

Coal,” Pub/ic Power, Sept. 10, 1981.

Lovings, Amory, Sofi Energy Paths: TowardA Durab/e Peace (Cambridge, Mass.: Ballinger Press,

1 977).

Messing, Marc, Friesema, H. Paul, and Morrell,

David, Centralized Power (Washington, D. C.: Environmental 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, April

1 979).

President Franklin D. Roosevelt, speech before the

World Power Conference, 1936, quoted in The

Energy Controversy: Soii Path Questions and Answens, Hugh Nash (cd.) (San Francisco: Friends of

the Earth, 1979).

Reese, R. E., and Nisenbaum, D., “Suggested Control Measure for the Control of Nitrogen Oxide

Emissions From Stationary Internal Combustion

Engines” (California Air Resources Board, May

1980).

Sheppard, D., et al., “Exercise Increases Sulfur

Dioxide–induced Bronchoconstriction in Asthmatic Subjects,” Am. Rev. Resp. Dis., May 1981.

Tugwell, Franklin, “Energy and Political Economy,” Comparative Po/itics, October 1980.

U.S. Environmental Protection Agency, Compilation of Air Pollutant Emission Factors (AP-42),

1978.

U.S. Environmental Protection Agency, Standards

Support and Environmental Impact Statement for

Stationary Internal Combustion Engines (EPA-4501

2-78-125a, draft, July 1979).

U.S. Environmental Protection Agency, Standards

Support and Environmental Impact Statement for

Stationary Gas Turbines (EPA-450/2 -77-Ol 7a, September 1977).

41. U.S. Department of Energy, Environmenta/Readiness Document- Cogeneration (DOE/ERD-0003,

1978).

42. U.S. General Accounting ~ce, /ndustria/ Cogeneration— What It Is, How It Works, Its Potential

(Washington, D.C.: U.S. Government Printing Office, EMD-80-7, Apr. 29, 1980).

43. Wilson, R. P., et al, “Single-Cylinder Tests of Emission Control Methods for Medium-Speed Diesel

Engines,” 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

Chapter 7 References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 280

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 Purchase

Rates: 1981-90 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 271
Chapter 7

Policy Analysis

A comprehensive Federal policy toward cogeneration was established in 1978. In general, the

elements of this policy, which are described in

detail in chapter 3, offer economic and regulatory

incentives for cogeneration applications that will

promote the efficient use of energy, economic,

and public utility resources. The major policy initiatives include title II of the Public Utility

Regulatory Policies Act of 1978 (PURPA), the

Powerplant and Industrial Fuel Use Act of 1978

(FUA), and the Energy Tax Act of 1978 (as

amended by the Windfall Profits Tax Act of 1980

and the Economic Recovery Tax Act of 1981), as

well as provisions of the Clean Air Act, general

aspects of utility regulation, and Government support for research and development (R&D) and for

demonstration projects.

Federal ratemaking, fuel use, R&D, and environmental policies are now shifting in focus; many

of the tax initiatives are too new for data on their

effects to be available; and court decisions are

pending on the validity of the ratemaking and interconnection provisions of PURPA. Despite

these uncertainties, some aspects of Federal cogeneration policy that may discourage the implementation of cogeneration projects, or that

may result in adverse impacts from such projects,

have been identified and are analyzed below.

These include the use of oil by cogenerators, economic incentives for cogeneration, utility ownership of cogeneration capacity, interconnection

requirements for cogeneration systems, the effects of cogeneration on air quality, and the focus

of R&D.

It is difficult to predict what long-term effects

these Federal policies will have on cogeneration.

COGENERATION AND OIL SAVINGS

One of the principal objectives of Federal policy toward cogeneration is to encourage the implementation of those projects that will reduce

net oil consumption, particularly by electric

utilities and industry. However, despite their inherent energy efficiency, not all cogenerators will

save oil. Rather, cogeneration will result in net

oil savings only if an alternate-fueled cogenerator

(e.g., one that burns coal, biomass, wastes), displaces either an electric generating plant or a

thermal energy system that uses oil, or if an oil

burning cogenerator replaces separate electric

and thermal energy systems that both use oil and

would continue to do so for most of the useful

life of the cogenerator. Thus, if an oil-fired cogenerator is substituted for either an electric or

thermal conversion technology that uses an alternate fuel, or that would have converted to an alternate fuel during the useful life of the cogenerator, then cogeneration actually could increase

net oil consumption.

In general, Federal policies under PURPA, FUA,

and the tax code are designed to discourage cogeneration applications that would not offer net

oil savings over the technology’s useful life. The

rates for utility purchases of cogenerated electricity (and other incentives) under PURPA are only

available to oil-fueled cogenerators if they meet

the efficiency and operating standards established

by the Federal Energy Regulatory Commission

(FERC) (see ch. 3). Moreover, the PURPA incentives are more economically advantageous to

cogenerators in regions where utilities depend

heavily on oil-fired generating capacity. In these

areas, the utilities’ purchase power rates are likely

to be based on the price of oil, and thus will be

higher than the rates of utilities with primarily

coal, nuclear, or hydroelectric capacity. Therefore, oil-fired cogenerators that do achieve net

oil savings usually will have higher purchase

power rates than those that do not. (Exceptions

include States where the utility regulatory com267
268 ● Industrial and Commercial Cogeneration

mission has set purchase power rates equal to the

price of oil while the purchasing utility actually

uses a mix of fuels, or has established explicit subsidy rates for purchases of cogenerated power.)

Similarly, oil burning cogenerators only can obtain an exemption from the FUA prohibitions on

oil and natural gas use in powerplants and industrial boilers if they can demonstrate net oil or

gas savings. Finally, the energy tax credits generally are available only for energy property that uses

fuels other than oil or gas.

When these policies were enacted, oil prices

were escalating rapidly. It was assumed that the

rising prices and uncertain availability of petroleum fuels, when combined with Federal policy,

would be sufficient to ensure that only those oilfired cogenerators that could achieve net oil savings would be worth the investment risk. However, oil prices have leveled off recently, and,

although most analysts project that prices will rise

slowly through the end of the decade, future

prices will not be so high as projected when the

National Energy Act was passed.

Thus, oil-fueled cogeneration that does not offer net oil savings may be attractive in spite of

supply and policy disincentives. For example,

some cogenerators may not need high purchase

power rates under PURPA to be economically

feasible (e.g., where retail electricity rates are exceptionally high), or may not wish to distribute

electricity to the utility grid (e.g., if onsite electricity needs are large and retail rates are very

high, or if reliability of electricity supply is essential). In addition, the FUA prohibitions only apply to cogenerators larger than about 10 megawatts (MW) (or a combined capacity of 25 MW

per site) and those that sell more than half of their

electric energy output. Furthermore, oil-fired cogenerators may be eligible for the energy tax

credit if they consist of a retrofit at an existing industrial or commercial facility that results in a

reduction in the amount of energy used onsite

(e.g., adding a heat exchanger to an existing

diesel generator). Where these special circumstances exist, oil-fired cogeneration could “slip

through the cracks” in existing policies and result

in increased oil use.

If net oil savings is the desired policy goal,

then a number of changes in Federal policy are

possible to close these gaps and further discourage oil-fired cogeneration that would not offer

such savings. First, the FERC regulations implementing PURPA could be revised to include

standards for fuel use in qualifying facilities (e.g.,

oil-fired cogenerators would not qualify for the

economic and regulatory incentives offered by

PURPA unless they could demonstrate a lifetime

oil savings). PURPA authorized the implementation of fuel use standards, but FERC chose not

to exercise its discretionary authority in this area

in the belief that other provisions of the act (i. e.,

the efficiency and operating standards and the

avoided cost rate structure) would, when combined with market forces, be sufficient to discourage oil-fired cogeneration. As stated in the introduction to the FERC rules implementing section 210 of PURPA:

Had Congress not intended that the benefits

of qualifying status be extended to oil- and natural gas-fired cogeneration facilities, the statute

or [Conference Report] would have contained a

restriction on fuel use similar to that which is provided for small power producers. The Congress

knew that cogeneration facilities typically use

natural gas and oil . . . the Congress enacted

[FUA] at the same time as PURPA, [FUA] provides authority to the Secretary of Energy to restrict the use of oil and gas in cogeneration facilities. Therefore, [FERC] does not believe it necessary or appropriate to require an additional layer

of fuel use regulation on technologies . . . for

which another agency has authority to restrict

fuel use. . . . To the extent that oil- and natural

gas-fired cogeneration facilities provide for more

efficient use of these resources, the Commission

believes that the benefits of qualifying status

should be extended to them (4).

FERC’S decision not to require cogenerators to

meet fuel use requirements in order to qualify

under PURPA was upheld in January 1982 by the

U.S. Court of Appeals. The court agreed with

FERC’S reasoning, and held that the regulations

promulgated by FERC were a reasoned and adequate response to the discretionary congressional

mandate.
Ch. 7—Policy Analysis ● 269

Adding fuel use restrictions to the PURPA regulations would not necessarily block those facilities

for which oil use may be economical even without the benefit of the PURPA incentives (i. e.,

those systems that do not need to be interconnected with the grid). To reach these cogenerators, Congress could amend FUA to prohibit the

use of oil in all cogenerators, regardless of size

or electricity sales, unless net oil savings are

demonstrated. The guidelines for such a demonstration already are included in the Economic

Regulatory Administration regulations on larger

cogenerators, but extending them to cover

smaller systems would require congressional

action.

Finally, Congress could amend the energy tax

credit (and other advantageous tax code provisions such as accelerated cost recovery) to deny

credits or deductions to oil-fired cogeneration

systems that cannot demonstrate net oil savings

(regardless of reductions in onsite energy use).

However, each of these provisions would impose additional layers of regulation on an already

complicated set of fuel use policies, and would

only affect a small portion of the cogeneration

market. Perhaps as little as one-third of the industrial cogeneration market potential is at sites that

would install less than 25 MW. As a result, even

if all the cogenerators that would be subject to

these regulations demonstrated net oil savings

and were installed, the resulting savings could be

as low as 60,000 to 90,000 barrels of oil equivalent per day (bee/day) in 1990 (2). Moreover, the

difficulty of demonstrating net oil savings and the

cumbersome paperwork involved in regulations

of this type could discourage even those oil burning cogenerators that would pose net savings.

One alternative to imposing additional regulation of oil use would be to tax oil consumption

(e.g., an oil import fee). This would be relatively

simple to administer, and would provide an additional Federal revenue stream. Although it has

been argued that such a tax would be inflationary, it also would be an effective conservation measure because it would reach all users of

oil. Therefore, larger savings could be expected

than if only cogeneration were targeted.

Another alternative to additional prohibitions

on oil-fired cogeneration is to amend existing

Federal laws and regulations to encourage the

near-term use of gas instead of oil. Natural gas

supplies currently are more abundant and less

expensive than oil, and over 90 percent of the

natural gas used in the United States is produced

domestically rather than imported. Where purchase power rates are set at or near the price of

oil-fired electricity and utilities have oil or gas

burning capacity, natural gas fueled cogeneration

will be economically attractive even if natural gas

prices approach those of distillate oil.

The use of natural gas in cogenerators also

would complement the policies established under PURPA that encourage the export of cogenerated electricity to the grid as an economical

alternative to building new central station

powerplants, or as a form of insurance against

unexpected changes in electricity demand. Currently available technologies that are likely to produce more electricity than is needed onsite (i.e.,

those with a high ratio of electricity-to-steam output–E/S ratio) cannot burn fuels other than oil

or gas directly, and providing incentives (or

removing disincentives) for the use of gas could

automatically discourage oil consumption.

The near-term use of natural gas in cogeneration systems also could be an integral part of an

evolutionary fuels strategy, because synthetic

gaseous fuels from coal, biomass, or wastes are

likely to be commercially feasible on a small or

medium scale (i.e., onsite gasification systems or

those with a limited distribution system) much

sooner than synthetic liquid fuels. Moreover,

gaseous synfuels with a low- or medium-Btu

value—which can be burned in cogenerators with

a high E/S ratio—are likely to be produced more

cheaply from alternate fuels (e.g., coal, biomass,

solid waste) than liquid synfuels. The most promising near-term liquid synthetic fuel that could be

produced on a relatively small scale is methanol

from wood, which also could be used in combustion turbines.

The policy options that provide incentives (or

remove disincentives) for the use of gas in cogen98-946 c1 - 93 - 19 : ,;1 !. 3
270 Industrial and Commercial Cogeneration

erators are similar to those described above for

discouraging oil use:

●

●

●

FERC could amend the PURPA regulations

(without further congressional action) to

deny qualifying facility status to oil-fired systems but specifically allow such status for gas

burning cogenerators.

Congress could amend FUA to extend the

prohibitions to all oil-fired cogenerators regardless of size or electricity sales, while specifically exempting natural gas-fired cogenerators (or exempting those that would convert to synthetic gas or other fuels by 1990

or 1995).

Congress could amend the energy tax credits

to allow credits for gas-fired energy property

but not oil-fired systems.

However, as noted above, each of these measures would prevent or discourage the implementation of those oil-fired systems that would pose

net oil savings.

Encouraging gas-fired cogeneration in order to

discourage or prevent oil burning systems is a

controversial option. From a national fuels policy

perspective, many analysts consider gas to be

equivalent to oil in terms of its value as a premium

fuel and its future supply. If onsite or modular

gasification systems do not become commercial

as soon as their developers project, or if the cost

of synthetic low- or medium-Btu gas remains significantly higher than the cost of natural gas, then

a strategy that encourages the near-term use of

natural gas and a switch to synthetic gas in the

long run could fail, and thus lock cogenerators

into natural gas use for 10 to 20 years. Moreover,

the potentially high cost of conversion to solid

fuels where these fuels can be burned directly

(e.g., fluidized bed), could cause cogenerators

to stay on natural gas even if the solid fuel is much

cheaper in the long run. Thus, making cogeneration with natural gas attractive eventually could

add to supply pressures if future production and

reserves are not so large as optimistic gas industry

analysts project.

Large established gas users (such as electric utilites) understandably are concerned about the future uncertainty of their fuel supplies, and argue

that neither oil- nor gas-fired cogenerators should

be eligible for Government incentives under

PURPA and the tax code. However, limiting access to, or otherwise discouraging the use of these

fuels could prevent cogenerators from taking advantage of those savings that might be available.

For example, a recent study that examined the

effects of an additional 10 percent investment tax

credit for cogeneration systems that used fuels

other than oil or natural gas found that such a

credit would actually reduce both net energy and

oil savings. The reduction occurred because the

additional credit would favor cogeneration technologies that use coal or other alternative fuels

and thus, in the near term, would have a low E/S

ratio and would not be able to displace utility oil

fueled capacity (2). Therefore, measures that limit

oil and gas use in cogeneration will not necessarily guarantee net oil/gas savings.

Some large established users also have argued

that future supplies of high-Btu synthetic gas (the

type that would be produced in large centralized

facilities and distributed in pipelines) should be

reserved for such users because synthetic gas with

a high energy content will be supply-limited for

at least 20 years. OTA did not analyze the issue

of allocating such gas to a particular class of users.

Rather, the gasification schemes appropriate to

cogeneration would produce low- or mediumBtu gas for onsite use or limited distribution, and

thus would not compete in the same markets with

potential users of high-Btu synthetic gas.

ECONOMIC INCENTIVES FOR COGENERATION

Both 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, tax

the amount of cogenerated electricity that may incentives, and other policy measures that reduce

be 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 potential for cogeneration development by 1990 in the

five top steam-using industries under three levels

of utility purchase rates found that the amount

of capacity that might be installed was almost six

times higher under the “high” purchase rates

(ranging from 2.5cents to 7.5cents/kWh depending on

the geographic region —see table 36) than under

the “low” rates (1.0cents to 4.5cents/kWh). Moreover,

under the higher assumed rates, a much greater

proportion of the installed capacity would be high

E/S ratio technologies such as combined cycles

and combustion turbines that would be more

likely to make electricity available to the grid (see

fig. 62). Under the lower assumed rates, the

amount of cogenerated steam was reduced 11

percent relative to the medium case, but the

amount of cogenerated electricity was reduced

by 50 percent (2). Analyses of tax provisions (e.g.,

investment tax credits and accelerated depreciation), and of subsidized financing (e.g., loan guarantees, low interest loans) show a similar but less

substantial sensitivity of cogeneration installation

and electric output to these economic incentives.

PURPA requires that purchase power rates be

just and reasonable to the electric utilities’ consumers and in the public interest, and that they

not exceed the incremental cost to the utility of

generating electricity itself or purchasing it from

the grid (the “avoided cost”). FERC originally set

rates for purchases of cogenerated power under

PURPA equal to the utilities’ incremental cost,

reasoning that only 100 percent avoided cost

rates would simultaneously encourage the fullest

possible development of the cogeneration market

and fuIfill the statutory requirements for just and

reasonable rates. However, the FERC rules on

purchase rates were vacated by the U.S. Court

of Appeals in January 1982 on the grounds that

FERC had not adequately justified its choice of

the “ceiling” rate established in the legislation,

when a rate less than 100 percent of the avoided

cost would share the economic benefits of cogeneration with the utilities’ noncogenerating

ratepayers (see ch, 3). The U.S. Supreme COUrt

will review the appeals court decision, but final

disposition of the case (either on appeal or

through revised regulations, if necessary) may not

occur 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 High

buyback 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 infeasible, but are shown to demonstrate the sensitivity of cogeneration development to buyback rates.

SOURCE: Resource Planning Associates, The Potential for Cogeneration Development by 1990 (Cambridge, Mass.: Resource Planning Associates, July 1981).

Although the full avoided cost rates remain in

effect pending a final decision, many potential

cogenerators (except where State legislatures or

regulatory commissions have instituted full

avoided cost pricing independently of PURPA)

have put their plans on hold as they wait to see

whether, in the long term, it will be economically

feasible for them to export power to the grid–

and, if so, how much—or for them to cogenerate

at all. Furthermore, the uncertainty about future

purchase power rates has chilled the interest of

potential financial backers, who may not be willing to invest in cogeneration projects without firm

long-term purchase contracts with a utility until
272 ● Industrial and Commercial Cogeneration

after a ruling by the Supreme Court, and—possibly–then only if the full avoided cost regulations

are upheld.

Whether purchase power rates based on 100

percent of the utility’s avoided cost are seen as

desirable depends on the policy goal. If the goal

is to maximize cogeneration’s market potential,

for whatever reason, then rates that reflect at least

the full avoided cost are necessary (some States

have instituted even higher subsidy rates to encourage cogeneration). In this case, cogeneration

would bean alternative (at least in the short term)

to building new central station powerplants.

However, if the goal is to provide the least cost

electricity supply to the ratepayer, then purchase

power rates based on less than 100 percent of

the avoided cost would share any economic savings from cogeneration with the utilities’ other

consumers.

As a compromise, the percentage of avoided

cost on which purchase power rates are based

could be determined regionally. In areas where

utilities are heavily dependent on oil and/or are

experiencing demand growth (e.g., the Northeast

and Pacific Coast), rates based on 100 percent

of the short-term marginal cost (usually equivalent

to the cost of oil—see ch. 3) could be instituted

to encourage the fullest development of cogeneration. These rates would share the benefits of

cogeneration’s potentially lower capital and interest costs with the ratepayers, but would not pass

on any of the cost benefits attributable to cogeneration’s oil savings. Alternatively, rates based on

the full longrun marginal cost (equivalent to the

cost of coal or nuclear capacity, or of advanced

technologies) could share more of the cost savings with noncogenerating customers. In regions

where the utilities’ full avoided cost is very low,

but cogeneration can provide insurance against

sudden changes in demand, full avoided cost

rates may be justified even though they would

not reduce rates for other customers. But where

utilities are dependent on alternate fuels and

already have substantial excess capacity, cogeneration 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 policies that provide economic incentives for cogeneration is the continued availability of tax provisions that reduce the capital cost of cogeneration. The special tax credit for investments in

alternative energy property expires at the end of

1982. A recent study of the economic incentives

for cogeneration found that extending the 10 percent tax credit to 1990 (and making it applicable

to oil- and natural gas-fired systems) could increase net oil savings attributable to cogeneration

from 185,000 bee/day in 1990 to 210,000 bee/

day. If all the fuel economically demanded by the

increased investment were natural gas, the direct

oil savings were estimated to increase from

280,000 to 310,000 bee/day. In addition, the

amount of cogeneration capacity was projected

to increase approximately 11 percent (from

12,800 MW of installed capacity to 14,400 MW)

in 1990. The resulting reduction in tax receipts

(discounted at a 10 percent rate) was estimated

at $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 will

not only reduce the available investment credit

by half, but also may encourage investment in

cogeneration technologies “before their time. ”

That is, advanced cogeneration technologies currently under development (including evolutionary improvements in existing technologies)

will have greater fuel flexibility, higher E/S ratios,

better operating efficiency, and improved environmental emissions. Many of these improvements will be ready by the mid-1980’s. Thus, the

continued availability of the energy tax credit

would enable potential cogenerators to wait until

they could select a technology that would maximize the oil savings and other benefits of cogeneration. In addition, extending the energy tax

credit to 1990 would enhance cogeneration’s role

in an evolutionary fuels strategy, in that a potential cogenerator could invest in the basic technology now and still receive the tax credit for a

later addition of fuel flexibility (e.g., a gasifier or

fluidized bed combustor). Finally, availability of

the energy credit after 1982 would allow innovative financing mechanisms to be developed more

fully.
Ch. 7—Policy Analysis 273

Similarly, the leasing provisions of the Economic Recovery Tax Act have been targeted for

repeal due to the loss in Federal revenues from

their widespread use by corporations seeking tax

shelters. These provisions provide the primary incentive for third-party investment in technologies

(e.g., cogeneration) that will contribute to energy

efficiency and increased productivity, and that

may be economically attractive for the user but

for which the capital cost is prohibitive given the

need to invest in process improvements or conservation measures. The uncertainty in their continued availability is chilling third-party investment, and thus the development of innovative

private financing arrangements, because potential

investors are chary of committing capital without

a guarantee that the needed tax incentives will

be available over the life of the investment. Additional analysis is needed to review the tradeoff

between the degree to which tax leasing contributes to investments in increased energy efficiency and productivity, and its effects on Federal

revenues.

Other policy measures that would provide an

economic incentive for cogeneration are options

for subsidized financing. High interest rates pose

a substantial disincentive to debt financing, while

recessionary business trends inhibit equity and

internal financing. Subsidized financing options

such as low interest loans or loan guarantees can

reduce the problems related to the cost and availability of capital. These options could be implemented through funding for existing programs.

However, Government subsidies for financing

would be difficult to implement given the current Federal budget situation. The most effective

way to enhance the investment climate is through

policies that promote general economic recovery,

and which lower interest rates by reducing

inflation.

As an alternative to Government financing subsidies, private subsidies could be offered. For example, Southern California Edison offers funding

assistance of up to $100,000 or 20 percent of the

capital cost (excluding installation labor) of their

customers’ cogeneration systems. Similar programs are offered by some utilities for solar or

conservation investments. The utility’s investment

might be included in the rate base, and the carrying costs shared by all the utility’s customers.

Utility involvement could encourage better integration between cogenerators and utility systems, and could increase the market potential

because utilities have a broader perspective on

the marginal costs of alternative energy supplies

and because’ subsidized financing could pose an

incentive to more potential cogenerators than tax

credits. However, utility financing is subject to

the same potential drawbacks as utility ownership (see below), and may increase the capital

cost if the utility relies on equity capital for its

financing program.

UTILITY OWNERSHIP OF COGENERATORS

The economic and regulatory incentives established under PURPA are granted only to “qualifying faciI it ies. ’ One of the statutory requirements

for qualification is that the owner of a facility not

be “primarily engaged in the generation or sale

of electric power” (other than electric power

solely from cogeneration or small power production facilities) (3). The FERC rules implementing

this requirement specify that if an electric utility, a utility holding company, or a subsidiary of

either holds more than a 50 percent interest in

a cogeneration facility, that facility will not qualify

for the PURPA incentives. It is important to note

that PURPA only limits the extent to which utilityowned systems can receive an unregulated rate

of return and can price cogenerated electricity

based on the cost of alternate power supplies.

It does not prohibit or restrict electric utility ownership or operation of cogenerators, and where

cogeneration is economically attractive relative

to conventional powerplants, utilities are, in some

cases, making the investment. Utility-owned cogenerators also are subject to less attractive treatment under the Energy Tax Act of 1978 because
274 ● Industrial and Commercial Cogeneration

public utility property (with the exception of

hydroelectric equipment) is not eligible for the

energy tax credit.

The ownership rule under PURPA and the unequal tax treatment of utilities have become controversial for several reasons. Electric utilities argue that the ownership rule discriminates against

them because it does not apply equally to other

types of utilities (e.g., gas utilities). When combined with the tax provisions, the 50 percent

ownership limitation also means that cogenerators owned by electric utilities may not be as economically competitive as facilities owned by other

parties. This is especially disturbing to the electric utilities, because electricity generation is their

primary business.

Furthermore, it is likely that cogeneration’s

market potential and electricity output would be

much greater if utilities were allowed 100 percent unregulated ownership. A study of the

cogeneration potential in five industries

(representing 75 percent of U.S. industrial steam

demand) found that, of a total technical potential of 12,800 MW by 1990, 4,000 MW would be

stimulated solely by full utility ownership (2).

Similarly, a study by Arkansas Power & Light

(AP&L) concluded that the industrial cogeneration

potential among 35 high steam load factor customers would be approximately 100 MW of electric capacity under industrial ownership, but up

to 1,700 MW under utility ownership (l). The

primary reasons for the differences in the amount

of cogenerated electricity with utility and nonutility ownership cited by these analyses are that

utilities would be more likely to choose technologies with high E/S ratios, and that utilities may

require a lower rate of return and often have better access to capital markets than other investors.

As a result of the higher electricity production

(and thus more power available to the grid) and

the better financial position, utilities could find

more projects economically attractive. However,

without the full PURPA benefits—especially an

unregulated rate of return on cogenerated electricity—utilities would not have so much of an

incentive to invest.

Finally, allowing 100 percent electric utility

ownership under PURPA would lessen utility concerns about competition from cogenerators and

the resulting possibility of reduced fixed cost coverage (see ch. 6). AP&L found that if the 35 likely cogeneration candidates in their service area

had cogenerated in 1981 under industrial or thirdparty ownership, AP&L’s revenue loss would

have been almost $40 million in that year (1). This

would mean that rates for their remaining customers would have increased as AP&L’s fixed

costs would be spread over a smaller number of

customers while their income dropped substantially. Utility ownership would protect against

such revenue losses and rate increases, and could

provide additional revenue streams from steam

sales while reducing the rate of increase in retail

electricity rates.

As noted above, utility ownership of cogenerators is possible without changes in PURPA or the

tax code. Thus, an electric utility could own regulated cogeneration capacity, or it could participate in a joint venture. In either case, some of

the advantages of 100 percent unregulated utility ownership would be available, including the

potential for greater amounts of installed cogeneration capacity and greater electricity output

from cogenerators than under industrial or other

private ownership arrangements, and protection

from the adverse effects of competition. However, joint ventures may be difficult to arrange,

while regulated ownership presents limited financial incentives for investments in cogeneration

capacity. The regulated rate of return would, in

most States, be the same for cogeneration as for

other types of new powerplants (e.g., coal or nuclear) despite the potentially higher administrative

costs and investment risks. Allowing utilities to

compete for unregulated cogeneration capacity

on the same basis as other potential investors

would provide utilities with stronger incentives

and ensure that the full range of benefits of utility ownership would be available. These incentives would be even greater if the tax treatment

were equalized as well.

However, 100 percent utility ownership of cogenerators under PURPA also could have disadvantages. The PURPA ownership rule was enacted in part out of concern that full utility ownership might have anticompetitive effects on the
Ch. 7—Policy Analysis ● 275

development of and market for cogeneration

technologies. That is, it has been suggested that

utilities could “capture” the cogeneration market

by favoring their own (or their subsidiaries’) projects through more favorable contract terms, priority in contracting (and thus potentially higher energy and/or capacity credits), and less stringent

interconnection requirements. Moreover, due to

the potential for cross-subsidization, utilities’ required rate of return–even if unregulated–could

be sufficiently lower than other investors’ and

thus allow the utilities a competitive advantage.

In addition, some opponents of unregulated utility ownership have argued that utilities might tend

to favor a limited number of large vendors and

manufacturers, with potentially adverse effects on

small businesses and the development of advanced technologies.

However, the implementation of cogeneration

technologies by utilities can be protected from

such anticompetitive effects through carefully

drafted legislation and regulations (e.g., similar

to the parts of the Energy Security Act that

amended the utility provisions of the National Energy Conservation Policy Act), and through traditional administrative and legal remedies. Alternatively, the question of whether utilities should be

allowed to own cogenerators under PURPA couId

be left to the States, with requirements for caseby-case review of ownership schemes by the State

regulatory commission prior to their implementation. With carefully drafted legislation and/or

State review programs, it is likely that the economic and other benefits of utility ownership

would outweigh the potential for anticompetitive

effects.

INTERCONNECTION REQUIREMENTS

The interconnection requirements for cogeneration have become an issue for two reasons:

1 ) because of the procedures that may be necessary to obtain interconnection, and 2) because

of the uncertainty about the amount and type of

equipment that will be necessary to protect utility

lineworkers and the utility system in general.

As discussed in chapter 3, the original FERC regulations implementing PURPA required utilities

to interconnect with cogenerators as part of the

general obligation to purchase power from and

sell it to cogeneration facilities. This requirement

was overturned by the U.S. Court of Appeals on

the grounds that PURPA also included provisions

amending the Federal Power Act to establish procedures for obtaining an interconnection order,

and that PURPA did not exempt cogeneration systems from this process. Thus, absent a legislative

amendment to PURPA, a cogenerator whose utility is unwilling to interconnect (or a utility who

wants to interconnect with an unwilling cogenerator) must apply for a FERC order.

FERC may not issue an interconnection order

under the Federal Power Act unless the commission determines that the order:

(1)

(2)

(3)

(4

(5

(6)

is in the public interest, and

would (a) encourage the overall conservation of energy or capital, or (b) optimize the

efficiency of use of facilities or resources,

or (c) improve the reliability of any electric

utility system or Federal power marketing

agency to which the order applies, and

is not likely to result in a reasonably ascertainable uncompensated economic loss for

any electric utility or qualifying cogenerator

affected by the order, and

will not place an undue burden on an electric utility or qualifying cogenerator affected

by the order, and

will not unreasonably impair the reliability

of any electric utility affected by the order,

and

will not impair the ability of any electric utility affected by the order-to render adequate

service to its customers.

Finally, in issuing an interconnection order, FERC

must issue notice to each affected party and afford an opportunity for a full evidentiary hearing

under the Administrative Procedure Act.

The requirements under the Federal Power Act

will be extremely difficult and expensive for a
276 ● Industrial and Commercial Cogeneration

cogenerator to meet. Even in well-understood situations, full evidentiary administrative hearings

entail expenses and delays that can pose a substantial disincentive to applying for an order. But

most of the showings listed above are couched

in new, broad language that will have to be construed, first, by FERC and then, in all likelihood,

by the courts. Moreover, in some cases, a cogenerator will not have access to the data needed

to make a particular showing, or only will be able

to acquire and analyze the data at great expense.

Thus, these provisions of the Federal Power Act

(as amended by PURPA) pose a substantial deterrent to cogenerators that cannot get an electric

utility to interconnect voluntarily—one of the

primary obstacles to cogeneration that PURPA

was intended to remedy.

in adopting revised regulations to implement

the interconnection provisions of the Federal

Power Act, FERC can adopt streamlined procedures that minimize the administrative burden on

the cogenerator or shift that burden to the utility; the act only specifies that the necessary determinations “shall be based upon a showing of the

parties.” However, full relief from the Federal

Power Act procedures can only come through

legislative amendment of the act to specify that

interconnection is required in order to make purchases of power from, and sales of power to, cogenerators, or through independent action by

each of the State legislatures.

The second area of controversy related to interconnection is the amount and type of equipment

required. As discussed in chapter 4, special

equipment may be necessary in order to regulate

power quality, meter cogenerators’ power production and consumption properly, control utility

system operations, maintain system stability, and

protect utility lineworkers. Given the lack of experience with power flows from cogenerators to

the grid, utilities are understandably concerned

about proper interconnection. But, with the possible exception of maintaining system stability,

the interconnection requirements are relatively

well understood, and OTA found no technical

obstacles to proper interconnection. However,

the amount and type of equipment required by

the utility (or the State regulatory commission)

can be a major economic issue, because such

equipment can add substantially to the capital

cost of a cogeneration system. Few guidelines for

interconnection are available (other than those

set by utilities), but research is underway to provide the needed information, and several groups

are working on interconnection standards (including the Institute of Electrical and Electronics

Engineers’ Power System Relaying Committee,

the Electric Power Research Institute, the Jet Propulsion Laboratory, the Department of Energy’s

Electrical Energy Systems Division, and the National Electrical Code). Research to date points

out the need for performance-based standards

that will allow cogenerators to meet functional

criteria rather than requiring them to install particular types of equipment that might later be found

u necessary.

Better data and additional analysis also are

needed to determine the actual costs of proper

interconnection. Cost estimates obtained through

simulation and other techniques must be verified

on actual systems. The State regulatory commissions should encourage those utilities that have

not done so to prepare guidelines for interconnection, and to update those guidelines as new

data are made available. However, until better

data are available, it is likely that both utilities and

State regulatory commissions will have to review

interconnections on a case-by-case basis to ensure that both the potential hazards to the utility

system and the costs to the cogenerator are minimized.

AIR QUALITY IMPACTS

Advocates of cogeneration argue that special by many potential cogenerators as a major imtreatment for cogeneration under the Clean Air pediment. Suggested changes that would remove

Act would enhance its market potential, because this impediment include, first, setting emissions

compliance with air quality regulations is cited standards that account for cogenerators’ effi-
Ch. 7—Policy Analysis ● 277

ciency—either by tying the standards to energy

output rather than fuel input or by having separate and more lenient standards for cogenerators;

and second, revising new source review procedures under the prevention of significant deterioration and nonattainment area provisions of the

Clean Air Act to automatically credit cogenerators

for reductions in emissions from the separate thermal and electric energy systems they would replace. The costs of complying with current air

quality regulations and the potential impacts of

these proposed changes are discussed in detail

in chapter 6 and reviewed briefly here.

Both of these policy changes would significantly

reduce the costs of pollution control for cogenerators and thus would increase their economic attractiveness. However, cogeneration’s fuel efficiency does not always lead to reduced emissions, nor does its substitution for two separate

energy systems always produce a net air quality

benefit.

In general, improved fuel efficiency will lead

to reduced emissions from electricity generation

only when a cogenerator replaces an electric generator of the same size and type. Thus, if the cogenerator involves new technology or fuel substitutions, or a change in scale, the net result may

be an emissions increase. Even if emissions are

reduced, that reduction may occur at a different

location and the cogenerator could still have a

negative impact on local air quality (e.g., reduced

emissions at a rural powerplant but higher ambient concentrations around an urban cogenerator). Finally, cogenerators may involve a change

in the type of emissions (e.g., reduced sulfur

RESEARCH AND

Federal R&D support for energy technologies

is in a state of flux and OTA was not able to analyze the direction of current research and development (R&D) efforts for cogeneration and related combustion systems. Based on OTA’s assessment of cogeneration technologies and opportunities, however, it is believed that high

priority should be given to funding or encouraging the development of systems with a low capital

cost and a high E/S ratio that can burn fuels other

oxide emissions from a coal burning facility but

increased emissions of potentially toxic diesel

particulate).

Moreover, those technologies that are most

likely to contribute to air quality problems–small

steam and combustion turbines and diesel and

spark-ignition engines—are the least likely to be

controlled. At present, Federal New Source Performance Standards only apply to steam turbines

larger than about 25 MW and gas turbines larger

than around 10 MW. Standards for diesel nitrogen oxide emissions were proposed, but withdrawn. The emissions characteristics of unregulated technologies vary widely among different

engine models, and cogeneration systems must

be carefully designed, sited, and controlled to

avoid adverse air quality impacts. Control technologies do exist for smaller steam and gas turbines and for diesels, but their effectiveness and

costs also vary widely, and their use currently is

not mandated by Federal law.

As a result of these considerations, there appears to be little public health or environmental

justification for automatically granting cogenerators relief from air quality regulations. Rather,

such relief might be afforded on a case-by-case

basis to those cogenerators that can demonstrate

air quality benefits. Moreover, the special air pollution problems posed by cogenerators that are

not regulated under the Clean Air Act (either because of their size or the type of technology) may

require more stringent review by State or local

agencies—a task those agencies may be ill-

-equipped to handle.

than oil and natural gas cleanly. The promising

applications identified in chapter 4 include the

gasification of coal, biomass, or wastes for use

in combustion turbines or combined cycles; fluidized bed combustion systems that can be used

in conjunction with steam or combustion turbines; direct-fired combustion turbines using solid

fuels (pulverized coal or wood); and advanced

technologies such as fuel cells, organic Rankine

bottoming cycles, and Stirling engines.
278 Industrial and Commercial Cogeneration

Additional R&D also is needed on the effects ment of low-cost effective emission controls for

of a large number of dispersed generating sources smaller cogeneration systems.

on utility system stability, and for

Federal policy on cogeneration

the developSUMMARY

generally encourages grid-connected applications that can

save oil or natural gas while promoting the efficient use of economic and electric utility resources and protecting public health and the environment. In most cases, these policies will have

the intended effects. However, special circumstances may mean that some cogeneration applications could increase oil use, or have adverse

economic impacts on already financially troubled

electric utilities, or lead to local air quality problems. options for closing these gaps in current

Federal policy initiatives are summarized in table

70. Although some of these options would require congressional action, most are relatively

easy to implement (i.e., low administrative costs,

few additional regulations).

Cogeneration can make an important contribution to the Nation’s transition to the efficient use

of fuels other than oil and gas while providing

important economic benefits. But achieving the

maximum benefits from cogeneration—and

avoiding its potential drawbacks—will require innovation in technologies, financial markets, and

utility management. And, until more experience

is gained with cogeneration under the current

energy, economic, and environmental context,

it will require careful planning. This includes careful selection of cogeneration technologies as well

as careful design and siting to ensure that the

needs of both the thermal energy user and the

local utility are met at an attractive cost and with

minimum environmental impacts. In most cases,

such planning can be achieved easily if early cooperation among all concerned parties-potential

cogenerators, utilities, and Government agencies

—is secured. Some utilities and State and local

agencies already have initiated cooperative planning programs designed to maximize cogeneration’s market potential and energy and economic

benefits. Others are bound to follow as soon as

they recognize that such planning is in their interests.
Ch. 7–Policy Analysis ● 279

Table 70.—Summary of Policy Considerations Related to Cogeneration

Government action required

Options to implement options Potential impact of options Administrative cost

Policy Issue 1: Posslbillty that oil-fired cogeneration would increase Oil use

A.

B.

c.

D.

E.

Require oil-fired cogenerators Amend FERC regulations Would not block all of the

to demonstrate net oil

savings in order to qualify

for PURPA benefits

Prohibit the use of oil in all

cogenerators unless net oil

savings are demonstrated

Deny energy tax credits for

oil-fired cogenerators

Encourage use of natural

gas instead of oil

Oil tax (e.g., import tax

or user fee)

implementing PURPA

Congressional action to

amend FUA, plus agency

implementation

Congressional action to

amend tax code plus IRS

implementation

Same as 1A-C, but in each

case specifically allowing

natural gas-fired

cogeneration

Congressional action

amend tax code

oil-fired cogenerators

that could increase oil

use; may discourage

some that would save oil

Would block all cogenerators

that could increase oil use;

may discourage some that

would save oil

Would provide further

economic disincentive to

oil-fired cogeneration,

even when it would save

oil

Would effectively block

oil-fired cogeneration

while providing market

incentives to gas-fired;

would complement

existing policies that

encourage conversion to

alternate fuels; could

lock cogenerators into

natural gas use,

increasing supply

pressure over time

to Would encourage oil

conservation in, all

markets, provide

additional Federal

revenues

Policy issue 2 Denial of equal benefits for utiiity-owned cogenerators under PURPA and the

A. Allow 100 percent utility- Congressional action to Could: increase cogeneration

owned cogenerators to amend PURPA plus market penetration and

qualify for PURPA benefits FERC implementation electricity production;

reduce rate of growth in

electric rates; improve

financial health of

electric utilities; provide

insurance against

unexpected changes in

demand growth. Also

could have anticompetitive

effects on the

cogeneration market and

on technology

development and

implementation, unless

legislation were drafted

carefully and/or State

review programs were

mandated

B. Allow energy tax credit for Congressional action to Could stimulate utility

utility-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 1932

A. 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 become

commercial

Potentially high for both

FERC and oil-fired

cogenerators

Potentially low for

implementing agency and

high for oil-fired

cogenerators

Low for both IRS and

cogenerators

Agency costs same as

1A-C, oil-fired

cogenerator costs high;

gas-fired low

Relatively low

tax code

Low for implementation.

Possibly high for

monitoring potential

anticompetitive effects

No greater than for existing

energy tax credit

Continuation of workload

under present tax credit
280 ● Industrial and Commercial Cogeneration

Table 70.—Summary of Policy Considerations Related to Cogeneration—Continued

Government action required

Options to implement options Potential impact of options Administrative cost

Policy issue 4- Compliance with air quality regulations is a major impediment to cogeneration development

A. Set emissions standards

that account for

cogenerators’ greater fuel

efficiency

B. Revise new source review

procedures to automatically

credit cogenerators for

reductions in emissions

from the separate

technologies they would

displace

Congressional action to

amend Clean Air Act plus

EPA and State

implementation

Congressional action to

amend Clean Air Act plus

EPA and State

implementation

Would reduce costs-of Possibly lower than under

emissions control. Could

result in net emissions

increase, especially in

urban areas

Would reduce costs to

cogenerator of performing

air quality modeling and

securing offsets. Could

result in net emissions

increase at cogeneration

site

Policy issue 5: Rates for purchases of cogenerated power are uncertain

A. Amend PURPA to set rates Congressional action to Would provide major

at 100 percent of utilities’ amend PURPA economic incentive to

avoided cost cogeneration without

reducing rates to other

utility customers

B. Revise FERC regulations to FERC implementation In some areas would

set rates according to provide less economic

regional opportunities for incentive than 5A, but

oil/gas and cost savings would share economic

benefits with ratepayers

Policy Issue 6: Interconnection procedures can pose substantial disincentive

A. Redraft FERC regulations FERC implementation Would minimize procedural

to shift evidentiary burden burden on cogenerators

to utilities to obtain interconnection

B. Amend Federal Power Act Congressional action to Would eliminate procedural

to require interconnection amend Federal Power Act burden

existing regulations

Would shift costs previously

borne by cogenerators to

already understaffed

State agencies

Same as under present

regulations

Initially slightly higher than

present regulations

Costly for FERC,

cogenerators, and utilities

Minimal

Policy issue 7: Interconnection requirements can substantially increase cogeneration capital costs

A. Accelerate research and More aggressive FERC Will reduce uncertainty for Minimal

encourage utilities and implementation cogenerator

State regulatory

commissions to establish

performance-based

standards

SOURCE: Office of Technology Assessment.

CHAPTER 7 REFERENCES

1. 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 Cogeneration Development by 1990 (RPA Reference

No: RA-81 -1455; July 31, 1981).
Appendixes
Appendix A

Dispersed Electricity Technology

Assessment (DELTA) Model

The DELTA model is a linear programing mathematical model used to calculate the costs of satisfying electric, heating, and cooling demands of a particular electric utility, given the capital equipment in operation

in 1980. The model computes a capacity expansion

plan that minimizes the time-discounted sum of capital, operating, and fuel costs.

This appendix is divided into three sections: first,

a description of the major assumptions used in the formulation of the model; second, a list of all the variables and notations used in the model equation set;

and third, the equation-by-equation description.

Major Assumptions and Model

Formulation

All of the major assumptions used in the DELTA

model are described in chapter 5. They are summarized below:

First, the model uses the linear programing type of

mathematical programing in its representation of the

utility system. Second, the model only simulates cogeneration that is connected to the grid. Third, the

model divides the entire commercial sector into three

subsectors corresponding to three types of demand

patterns: multifamily, hospitals/hotels, and 9-to-5 office

buildings. Fourth, the model uses the eight different

types of daily load cycles in its representation of electrical, heating, and cooling demands, Fifth, the model

has two different types of fuel price paths. Sixth, three

different sample utility systems were used. Seventh,

different assumptions were made to represent the various technologies, the way they operate, and the financial structure of the utility region.

As mentioned in chapter 5, the model uses three

types of energy demands—electrical, thermal heating,

and cooling—that must be met by a combination of

electrical and thermal generation. A schematic for the

general structure of the model (for a particular subsector) is given in figure A-1.

Notation And Variables Used

Each variable (representing particular activities of a

utility) may have up to five subscripts for its mathematical shorthand. The subscripts are:

n— for each centralized technology type [e.g., n = 1

(baseload), n=2 (intermediate), n=3 (peaking)];

Figure A-1 .—DELTA Model Structure

Supply Demand

.

I

*

THG

Thermal

storage

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); and

h– for the hour of the day represented.

For each individual dispersed type of technology

represented and each subsectors and year, day, and

hour y, d, h, we represent the various activities with

the following mathematical shorthand. Power output

is measured in megawatt hours, while capacity is

measured in megawatts. One thermal megawatt is

equal to 3.412 million Btu/hr.

COGsydh

cocsy

T H Gsydh

T H Csy

E C Dsydh

is the cogeneration electrical power output in subsector s at time y, d, h.

is the cogeneration power capacity in subsector s at year y.

is the electrical heating power generation

in subsector s at time y, d, h.

is the electrical heating power capacity in

subsector s at year y.

is the electric air conditioning output in

subsector s at time y, d, h.

283
284 ● Industrial and Commercial Cogeneration

ECCsy is the electric air conditioning capacity in

subsector s at year y.

TCDsydh is the thermal (absorptive) air conditioning output in subsector s at time y, d, h.

TCCsy is the thermal (absorptive) air conditioning capacity in subsector s at year y.

SPHsydh is the thermal heating output in subsector s in time y, d, h.

There are also the electrical generation variables,

that are represented for the different types of centralized technologies n and time y, d, h:

ELGnydh is the central electric power generation for

technology n and time y, d, h (measured

in MWh).

ELCnY is the central electric power capacity for

technology n and year y (measured in

MW).

Finally, there are three variables that represent the

thermal storage activities for each subsectors and time

y, d, h:

TOTsydh

TINsydh

TECsy

is the dispersed thermal storage output for

subsectors and time y, d, h (measured in

MWh).

is the dispersed thermal storage input for

subsectors and time y,d, h (measured in

MWh).

is the dispersed thermal storage energy

capacity for subsectors and year y (measured in MW).

The input and output variables are measured in

megawatts, while the capacity is measured in

megawatt-hours.

The various technological characteristics are abbreviated mathematically with the following shorthand:

An is the availability of equipment of technology type n to provide power.

MANnYd is the amount of time that technology type

n is out of service for maintenance in year

y and day d.

C(.) is the annual capital cost or operating cost

for each capacity activity variable (.)

DISCY is the real discount factor for both capital

and 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 subsector s in time y, d, h.

HTDsydh is the thermal heating demand for subsector 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 day

type d.

Equation Description

As in standard with linear programing-type of formulations, we divide our description of the equations

into two parts: first a description of the objective function and then the constraints.

Objective Function

The objective function is to minimize the sum of discounted (over the time period of the model back to

1980 dollars) the annual costs of operation and capacity of electric generation, cooling, heating, and the

costs of thermal storage. The mathematical description

min
Appendix A—Dispersed Electricity Technology Assessment (DELTA) Model ● 285
Appendix B

Emissions Changes

A number of analyses of emissions changes caused

by cogeneration have been conducted. All of these

analyses, however, are site-specific and do not illustrate the effects of changing critical assumptions, or

they have extrapolated to regional or national emissions changes by using simplifying assumptions about

critical parameters (e.g., the type of fuels “backed

out” of the utilities’ centralized systems) that may be

significantly in error.

The following tables display the emissions attributable to each component in a possible switch from a

system using central station-generated electricity and

a 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 range

of circumstances to be evaluated. Because of the significant 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 0

d 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 0.15 m 0.05 m O.0l m 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

Coal

0.89 q0.30q NEG 0.03 2.38q oil

0.59q

0.03 NEG 0.12 0.21 Gas

ND - No data found

NS - No standard

NEG - Negligible

aUnless the cogeneratlng system has heat storage capability and/or very careful balancing of heat production and actual need, less heat than this will be usefully

captured, 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/spersedElectric 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 gee

turbines 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 its

fuel 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.

SOURCE: Office of Technology Assessment.
Appendix B—Emission Charges “ 287

from a gas turbine or diesel can vary over a fairly wide tions of cogenerator, central power facility, and local

range), 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 kiloWatthours. Emission “balances” for particular combina-

– (central station power emissions, table B-2) – (hot water and

steam 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)

Emissionsa, 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 sulfur

IO% 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 0.80

Older oii-fired plant, 1 % sulfur. . . . . . 1,000,000 0.70 0.05 0.04 0.01 1.05

Older natural gas-fired plant . . . . . . . . 1,000,000 0.67 0.01 0.02 0.04 NEG.

Existing gas turbine peaking plants . l,lOO,OOOd 0.43 (.66)e 0.01 0.12 NEG. NEG. Gas

Existing gas turbine peaking plants . l,lOO,OOO d 0.53 (.99)e 0.04 0.12 0.04 0.03 Oii

NSPS gas turbine . . . . . . . . . . . . . . . . . 0.3

aErnissiOns 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 Fossilfuelad 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 Impacts

Statement 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 ap

pear to emit nitrogen oxides at a lower unit rate than smaller industrial turbines. The larger emissions value is used to construct the emission balances.

SOURCE: Office of Technology Assessment.

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. Gas

0.16 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 Coal

0.37 0.13 0.04 0.01 1.00 Oil

0.25 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.

SOURCE: Office of Technology Assessment.
Appendix C

Acronyms, Abbreviations, and Glossary

AC

ACRS

AEP

AFB

AFUDC

AGA

APCD

AP&L

APPA

bbl

boe

Btu

CAQCA

CARB

CEC

CEQA

CFC

c o

ConEd

CPUC

CWE

CWIP

DC

DELTA

DOE

EIA

EIR

EIS

EPA

EPRI

ERTA

E/S ratio

FERC

FFB

FGD

FUA

g

G W

GWh

HC

hph

IEEE

I o u

1P

IRS

ITC

288

alternating current

accelerated cost recovery system

American Electric Power Service Corp.

atmospheric fluidized bed

allowance for funds used during

construction

American Gas Association

air pollution control district

Arkansas Power & Light Co,

American public Power Association

barrel

barrels of oil equivalent

British thermal unit

Colorado Air Quality Control Act

California Air Resources Board

California Energy Commission

California Environmental Quality Act

National Rural Utilities Cooperative

Finance Corp.

carbon monoxide

Consolidated Edison Co. of New York

California Public Utilities Commission

Commonwealth Edison Co,

construction work in progress

direct current

Dispersed Electricity Technology

Assessment model

Department of Energy

Energy Information Administration

environmental impact report (required

under CEQA)

environmental impact statement

Environmental Protection Agency

Electric Power Research Institute

Economic Recovery Tax Act of 1981

electricity-to-steam ratio

Federal Energy Regulatory Commission

Federal Financing Bank

flue gas desulfurization

Powerplant and Industrial Fuel Use Act

of 1978

gram

gigawatt

gigawatthour

hydrocarbon

horsepowerhour

Institute of Electrical and Electronics

Engineers

investor-owned utility

Illinois Power Co.

Internal Revenue Service

investment tax credit

JPL

kv

kVAR

kwf

kwh

LAER

lb

LRMC

; C F

MFBI

MMBD

MMBtu

MSW

M W

MWh

NAAQS

NECPA

NEES

NEPA

NEPOOL

NERC

NGPA

N O

N 02

N OX

NPDES

NSPS

O&M

OSHA

PFB

PG&E

ppm

Psc

PSD

psi

psia

psig

Puc

PUHCA

PURPA

QF

REA

rpm

Jet Propulsion Laboratory

kilovolt

kilovolt-amperes-reactive

killowatt

kilowatthour

lowest achievable emission rate

pound

Iongrun marginal cost

meter

million cubic feet

major fuel burning installation

million barrels per day

million Btu

municipal solid waste

megawatt

megawatthour

national ambient air quality standards

National Energy Conservation Policy

Act of 1978

New England Electric System

National Environmental Policy Act

of 1969

New England Power Pool

North American Electric Reliability

Council

Natural Gas Policy Act of 1978

nitrous oxide

nitrogen dioxide

nitrogen oxides

National Pollutant Discharge

Elimination System

new source performance standard

operation and maintenance

Occupational Safety and Health

Administration

pressurized fluidized bed

Pacific Gas & Electric Co,

parts per million

public service commission

prevention of significant deterioration

(of air quality)

pounds per square inch

psi absolute

psi gauge

public utilities commission

Public Utility Holding Company Act

of 1935

Public Utility Regulatory Policies Act

of 1978

qualifying facility

Rural Electrification Administration

revolutions per minute
App. C—Acronymns, Abbreviations, and Glossary 289

SCF

SEC

SERI

so,

Sox

SRMC

SRP

TCF

tpy

TSP

TVA

g

standard cubic foot

Securities and Exchange Commission

Solar Energy Research Institute

sulfur dioxide

sulfur oxides

shortrun marginal cost

Salt River Project

trillion cubic feet

tons per year

total suspended particulate

Tennessee Valley Authority

microgram

Glossary

Availability: A measure of the frequency of scheduled

outages for generating unit (e.g., for maintenance).

Avoided Cost: The incremental cost to an electric utility of electric energy or capacity or both which,

but for the purchase from a cogenerator or small

power producer, the utility would generate itself

or purchase from another source.

Back-Up Power: Electricity sold to a cogenerator by

a utility during unscheduled outages of the cogenerator (e.g., during equipment failure).

Balance of System: The equipment required for a cogeneration system excluding the prime mover

(e.g., combustion chamber, environmental controls, fuel handling equipment).

Blowdown: The effluent from boilers and wet cooling systems.

Bottoming Cycle: A cogeneration system in which

high-temperature thermal energy is produced first,

and then the waste heat is recovered and used

to generate electricity or mechanical power plus

additional, lower temperature thermal energy,

Capacity Factor: The percent of a year that a generator

actually supplies power.

Cooling Tower Drift: The discharge and dispersal of

small droplets of water from wet cooling towers.

Dispatching: Control by a utility from a central location of the amount of electricity generated by a

powerplant and of its distribution to the point of

use.

Diversity: The difference in electricity usage patterns

among customers.

Downwash: An aerodynamic wind action that causes

stack plumes to be caught around the stack or

around neighboring buildings.

Dry Controls: Technological air pollution controls that

use a nonliquid control medium.

Dual Fuel System: An engine or boiler that can switch

back and forth from one fuel (e.g., coal) to another

(e.g., oil) with no technological modification and

minimal downtime.

Efficiency: A measure of the amount of energy which

is converted to useful work versus how much is

wasted.

Fuel Use Efficiency for a cogenerator credits the

thermal as well as electric output and is expressed as the ratio of electric output plus

heat recovered in Btu to fuel input in Btu.

First Law Efficiency reflects the simple percentage

of fuel input energy that is actually used to

produce useful thermal and electric energy,

but does not distinguish the relative value of

the two outputs.

Second Law Efficiency recognizes that electricity

is a much higher quality form of energy than

heat or steam.

Full-Load Electric Etliciency is measured when the

maximum possible amount of electricity is

being produced.

Part-Load Electric Eiliciency is measured when less

than the maximum possible amount of electricity is being produced.

Electricity-to-Steam Ratio: The proportions of electric and thermal energy produced by a cogenerator, measured in kilowatthours per million Btu of

useful thermal energy.

Fumigation: When plumes from either tall or short

stacks are forced to ground level by meteorological conditions.

Harmonic Distortion: The production in a power system of one or several frequencies that are multiples of the basic power frequency of 60 cycles per

second.

Heat Exchanger: A mechanical device that transfers

waste heat from one part of a system (e.g., the

turbine) to another medium (e.g., water) for process use.

Heat Rate: A measure of the amount of fuel used to

produce electric and/or thermal energy.

Total Heat Rate refers to the total amount of fuel

(in Btu) required to produce 1 kilowatthour

of electricity with no credit given for waste

heat use,

Incremental Heat Rate is calculated as the additional (or saved) Btu to produce (or not produce) the next kilowatthour of electricity.

Net F/eat Rate (also measured in Btu/kWh) credits

the thermal output and denotes the energy

required to produce electricity, beyond what

would be needed to produce a given quanti-
290 ● Industrial and Commercial Cogeneration

ty of thermal energy in a separate facility (e.g.,

a boiler).

induction Generator: A rotating machine in which

current supplied by an external alternating current source such as the electric power grid, induces a voltage and current in the rotating part

of the machine.

Interest Coverage Ratio: The ratio of a firm’s earnings

to its current interest obligations.

Interruptible Power: Energy or capacity supplied by

a utility to a cogenerator that is subject to interruption by the utility under specified conditions

and is normally provided at a lower rate than noninterruptible service if it enables the utility to reduce peakloads.

Inverter: A device for converting direct current to alternating current.

Load: The demand for electric or thermal energy at

any particular time.

Base Load is the normal, relatively constant demand 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 and

peak.

Load Factor is the ratio of the average load over

a designated time period to the peak load occurring during that period.

Load Cycle Pattern is the variation in demand over

a specified period of time.

Maintenance Power: Energy or capacity supplied by

a utility during scheduled outages of a cogenerator or small power producer–presumably scheduled when the utility’s other load is low.

Market Potential: The number of instances in which

a technology will be sufficiently attractive-all

things considered—that the investment is likely to

be made.

Market-to-Book Ratio: The ratio of the market price

of a firm’s stock to its book value,

Negative Load: A technique by which utility system

controllers subtract the power supplied to the grid

by customer-operated generating equipment from

the overall system demand and dispatch the utility’s generating units to meet the remainder of the

demand, rather than dispatching customers’

equipment.

Parallel Operation: The automatic export to the utility

grid of customer-generated electricity not consumed by the customer’s load, such that the same

circuits can be served simultaneously by customer—and utility-generated electricity.

Payout Ratio: The ratio of a firm’s earnings to its dividends.

Power Factor: A measure of the phase difference between the voltage and current maximums on an

electrical circuit.

Prime Mover: The turbine, engine, or other source

of mechanical power that is used to turn the rotor

of a generator.

Purchase Power: Customer-generated electricity supplied to the grid and purchased by a utility.

Quad: One quadrillion British thermal units (Btu) (approximately 500,000 barrels of oil per day for 1

year, or 50,000,000 tons of coal).

Qualifying Facility: A cogenerator or small power producer that meets the requirements specified in the

Public Utility Regulatory Policies Act of 1978–in

the case of a cogenerator, one that produces electricity and useful thermal energy for industrial,

commercial, heating, or cooling purposes; that

meets the operating requirements specified by the

Federal Energy Regulatory Commission with respect to such factors as size, fuel use, and fuel efficiency); and that is owned by a person not primarily engaged in the generation or sale of electric

power (other than cogenerated power).

Rankine Cycle: The thermodynamic cycle which describes the operating cycle of an actual steam

engine.

Rate Base: The net valuation of utility property in service, consisting of the gross valuation minus accrued depreciation.

Regenerator: A device used in a turbine or engine to

preheat incoming air or gas by exposing it to the

heat of exhaust gases.

Relays: Devices by means of which a change of current or a variation in conditions of an electric circuit causes a change in conditions of or operates

another circuit.

Over/Under Relays are used to disconnect a generator if its voltage falls outside of a certain

range.

Reliability: A measure of the frequency of scheduled

and unscheduled outages of a generating unit

(e.g., due to equipment failure).

Self-Excitation: The continued operation of induction

generators when disconnected from the outside

power source.

Simultaneous Purchase and Sale: When a utility purchases all of the electricity generated by a customer at avoided cost rates and sells power to the

customer at retail rates; in practice, no actual

transmission of power to or from the customer

may take place and the amounts “purchased”
App. C—Acronymns, Abbreviations, and Glossary . 291

and “sold” are calculated from the customer’s

meter.

Supplementary Power: Capacity required by a cogenerator or small power producer in addition to its

own.

Switchgear: All of the necessary relays, wiring, and

switches that are used in interconnection equipment.

Synchronous Generator: A prime mover (e.g., turbine, engine) in which the rotor current comes

from a separate direct current source on the generator.

Synthesis Gas: A synthetic gas created from a solid

or liquid fuel with an energy content of 300 to 400

Btu/SCF.

System Stability: The ability of all generators supplying power to a utility system to stay synchronized

after a disturbance (e.g., a fault on part of the

power system).

Technical Potential: The number of instances in

which a technology is technically suitable or appropriate.

Telemetry Equipment: Used in dispatching to transmit

signals from a control center to electrical equipment (e.g. a generator) in the field in order to remotely operate that equipment.

Topping Cycle: A cogenerator in which the electric

or mechanical power is produced first, and then

the thermal energy exhausted from power production is captured and used.

Transformer: A device for increasing or decreasing

the voltage of an alternating electric current.

Dedicated Distribution Transformers: These units

connect a single large utility customer directly to

a higher voltage distribution line, substation, or

transmission network in order to confine voltage

flicker problems to the customer’s own system.

Urban Meteorology: The conditions surrounding urban buildings that alter normal dispersion of emissions.

Voltage Flicker: Very brief (less than 1 minute)

changes power system voltages.

Waste Heat: Thermal energy that is exhausted rather

than being captured and used.

Wet Controls: Technological air pollution controls

that operate through the injection of water or

some other liquid.

Index

Aerospace Research Corp., 145, 207

air-conditioning demand, 54

air pollution control districts (APCDs), 102, 103, 104,

243, 244, 245

Air Pollution Emission Notice (APEN), 101, 102, 244, 245

Alabama, 41, 86, 177, 182

Alaska, 57, 182

Alaska Power Administration, 57

American Electric Power Service Corp. (AEP), 80, 83,

84, 85, 178

American Gas Association (AGA), 189, 190, 196

American Public Power Association (APPA), 150, 159

anaerobic digestion, 13, 215

Arizona, 41, 182

Arkansas, 40, 41, 57, 86, 177, 182

Arkansas Power & Light Co. (AP&L), 109, 183, 258, 274

avoided cost, 39, 40, 41, 79, 80, 81, 82, 98, 99

Babcock & Wilcox, Ltd., 178

Bonneville Power Administration, 56

Bureau of Land Management (BLM), 243, 244

Bureau 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, 244

California Energy Commission (CEC), 90, 91, 104

California Office of Permit Assistance, 102, 104

California Public Utilities Commission (CPUC, 90, 91,

92, 93, 94, 104, 154, 156, 256

California State Clearing House, 103

California Water Resources Control Board, 102

capital requirements, 33, 42, 65, 106

carbon monoxide (CO), 223, 224, 230, 237

Celanese Chemical Co., Pampa, Tex., 172, 173

coal, 144

cogeneration 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, 175

capacity, 199

capital requirements, 33, 42, 65, 106

centralization and decentralization, 261

choice of equipment, considerations of, 8

classification, 6

closed-cycle gas turbine, 6, 8, 9, 30, 120, 121, 122,

127-129, 239

combined gas turbine/steam turbine, 8, 9, 28, 120,

121, 122, 129-131, 235

competition with alternate systems, 31-32, 35

construction labor requirements, 42

definition, 25

diesel, 8, 9, 28, 44, 77, 120, 121, 122, 131-133, 225,

230, 237, 238,

digesters, 13, 215

economic considerations, 19, 27, 38, 40, 67, 181,

246-259, 270-273

efficiency and operating standards, 77

electric storage, 161-163

electricity-to-steam (E/S) ratio, 8, 11, 21, 28, 117,

120, 124

environmental considerations, 16-17, 21, 35, 43-44,

70, 77, 100, 101, 102, 103, 221, 222-246

environmental permit enforcement, 242-246

equipment needed, consideration of, 8

Federal and State regulation, 76-104

final environmental impact statement (FEIS), 78

financing and ownership, 104-112, 182-183

fluidized bed combustion, 31, 32, 35, 142-143, 177, 239

four general questions, 5

fuel cell, 6, 8, 9, 30, 120, 121, 122, 137-139

fuel 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, 258

grain drying, 211

impacts of, 15-18, 40-42, 43-44

incentives, 10, 19, 20, 35, 38, 39, 40, 41, 67, 107

in commercial buildings, 12, 32, 34, 189-210

industrial applications, 171-178

industrial opportunities, 32-34, 171-188

investment competition, 10

joint ventures, 39

labor requirements, 17, 42, 251, 253

market potential, 10, 38, 184-188, 248, 272

municipal solar utility (MSU), 111

municipal solid waste (MSW), 110, 144, 241, 257

obligation to purchase power, 78

oil savings, 18-19, 25, 267-270

old and proven technology, 3

open-cycle gas turbine, 8, 9, 28, 30, 120, 121, 122,

124, 125, 145

operation 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, 198-208

policy considerations, summary of, 18, 279

potential for, 10, 29-31, 178-184, 211

previous studies, 189-190

principal technical advantage, 6

qualifying facilities, 78-85

Rankine cycle, 6, 8, 9, 28, 29, 30, 32, 117, 120, 121,

122, 133-137

regulation of fuel use, 99

relative efficiencies (fig. 2), 7

research and development (R&D), 21, 29, 31, 277

resurgence of interest, 3, 25

retrofits, 33, 202-205

rural opportunities, 13, 210-216

steam turbine, 8, 9, 10, 27, 28, 32, 120, 121, 122,

123, 124, 171, 174

Stirling engine, 6, 8, 9, 30, 31, 120, 121, 139-142

summary of, 8, 120

tax credit and incentives, 19, 20, 34, 38, 67, 68, 69,

105, 106, 109, 183, 272

295
296 Industrial and Commercial @generation

thermal storage, 159-161

thermodynamic efficiency of, 118-119

topping cycles, 6, 9, 25, 26, 29, 30, 31, 77, 122

use of thermal energy, 25, 31, 32, 33

Colorado, 41, 101, 102, 103, 104, 182, 242, 243, 244, 245

Colorado Department of Health, 242, 243

Columbia River Basin, 56

Commonwealth Edison (CWE), 94-95, 256, 257

comparison of energy demand projections (table 8), 50

ConEd (see Consolidated Edison Co.)

Congress

House of Representatives

Banking, Finance, and Urban Affairs Committee, 5

Energy and Commerce Committee, 5

Science and Technology Committee, 5

Senate

Energy and Natural Resources Committee, 5

Connecticut, 40, 41, 86, 98, 182

conservation, 33, 35, 50, 70

considerations in determining avoided costs under

PURPA, by State (table 4), 41

Consolidated Edison Co, (ConEd), 93, 94, 189, 190,

231, 232, 233, 256

Curtiss-Wright Corp., 178

Delaware, 40, 41, 182

DELTA (see Dispersed Electricity Technology Assessment

model)

Department of Commerce, 188

Department of Energy (DOE), 99, 159, 178, 185, 187

Secretary of, 71

Electrical 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, 163-165

District of Columbia, 41, 182

Dow Chemical Co., 185, 186

economic impact, 40-42

Economic Regulatory Administration, 269

Edison Electric Institute, 50

effects on fuel use, 15

electricity

baseload, 60

costs, 63, 73, 79, 80, 81, 82, 83, 85, 96, 97, 98, 214

distribution system (fig. 11), 62

generating, historical overview, 4

harmonic distortion, 150

peakloads, 60

power demand, 52, 53, 54

power factor correction, 147

power quality, 146

power system statistics (table 10), 55

rates, 62

rates for power purchased from QFs by Stateregulated utilities (table 19), 86-89

storage, 161-163

system reliability, 61

U.S. generating capacity, 60, 61

voltage regulation, 148

Electric Power Research Institute (EPRI), 150, 154, 156,

159, 177, 276

electric reliability councils, 57

Electric Reliability Council of Texas, 198

electric utility systems, 55, 56, 59, 61

accelerated cost recovery system (ACRS), 67, 68

capital recovery factor, 106

cooperative utilities, 56, 66, 69, 111

current status, 72-74

economic and regulatory aspects, 62-66

State regulations, 62, 66, 70

Federal regulations, 63, 67, 70

Federal jurisdiction, 67

financing, 64-69, 104

future options, 74-75

generation and transmission co-ops (G&Ts), 56, 64, 66

industrial development bonds (IDBs), 110

investment tax credit (ITC), 67, 68, 69, 109

investor-owned utilities (IOUS), 55, 56, 57, 61, 62, 64,

65, 67, 69, 73, 74, 104, 106, 108, 111

joint action agency, 57

municipal, 61, 64, 65, 67, 109

planning and regulation of, 254-257

power pools, 57

private utilities, 55, 65, 106

public health and welfare regulations, 70

publicly owned utilities, 56, 57, 61, 65, 69

PURPA requirements, 39-40

rate schedule, 63

regulation of fuel use, 71

revenue requirement, 63

rural co-ops, 56, 61, 111

service regulation, 69

taxation, 67, 106

Energy Information Administration (EIA), 50,51,53,54, 196

environmental impact report (EIR), 103

Environmental Protection Agency (EPA), 100, 225, 230,

233, 236, 238, 242

ERTA (see legislation, Economic Recovery Tax Act of 1981)

ethanol, 211

Exxon, 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, 112

Federal new source performance standards (NSPSS), 225

Federal Power Commission (FPC), 57, 64, 69

Federal power marketing agencies, 56, 57

FERC (see Federal Energy Regulatory Commission)

Fish and Wildlife Service, Department of the Interior, 71

Florida, 40, 41, 182

General Public Utilities, 74

Georgetown University, Washington, D. C., 239

Georgia, 41, 182
Index . 297

Georgia Power, 151

German Babcock Co., 178

Governor’s Task Force on Cogeneration, State of

California, 104

Great Britain, 143, 145, 178

gross national product (GNP), 49, 50

Gulf States Utility Co., Baton Rouge, La., 173 174, 188

Holly Sugar Corp., Brawley, Calif., 174, 175

Idaho, 41, 86, 172, 182

Illinois, 41, 86, 90, 94-95, 182

Illinois Commerce Commission (ICC), 94, 95

Illinois Power (1P), 94, 95

implementation of section 210 of PURPA, 86-98

California, 90

Colorado, 101

Illinois, 94-95

Massachusetts, 97

New England, 96-98

New Hampshire, 96, 97

Vermont, 97

Indiana, 41, 87, 182

installed industrial capacity

chemical industry, 11, 172, 174, 179

food processing industry, 12, 33, 174

petroleum refining, 11, 12, 173, 179

pulp and paper industry, 11, 13, 172, 178

steel 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, 158

generation dispatch, 152

guidelines, 155

liability, 154

metering, 151

power factor correction, 147

power quality, 146

power regulation problems, 151

quality of equipment, 154

regulation, 76

safety of workers, 14, 36, 153

system stability, 152

technical aspects, 36

voltage regulations, 148

Iowa, 41, 182

Jersey City Total Energy Demonstration Project, 241

Jet Propulsion Laboratory (JPL), 156, 276

Journal of the Air Pollution Control Association (JAPCA),

236, 237

Kansas, 41, 87, 182

Kentucky, 41, 182

Kern County, Calif., 91, 180

legislation

Administrative Procedure Act, 84, 85, 275

Atomic Energy Act, 70

California Environmental Quality Act (CEQA),

103, 104

Clean Air Act, 18, 21, 70, 100, 101, 102, 225, 239,

240, 242, 244, 245, 267, 276, 277

Clean Water Act, 70, 101, 102, 103, 244

Coastal Zone Management Act, 71

Colorado Air Quality Control Act (CAQCA), 101

Economic Recovery Tax Act of 1981 (ERTA), 68, 104,

105, 106, 107, 188, 259, 267, 273

Endangered Species Act of 1973, 70

Energy Security Act of 1980, 104, 105, 275

Energy Supply and Environmental Coordination Act

of 1974, 71

Energy Tax Act of 1978, 68, 267, 273

Federal Power Act, 20, 37, 63, 64, 67, 69, 76, 84, 85,

97, 146, 275, 276

Fish and Wildlife Coordination Act of 1970, 71

FUA (see Powerplant and Industrial Fuel Use Act

of 1978)

Internal Revenue Code, 68, 105, 109

National Ambient Air Quality Standards (NAAQS),

100, 101, 225, 236, 237

National Electrical Code, 156

National Energy Act of 1978, 5, 71, 76, 104, 268

National Energy Conservation Policy Act of 1978

(NECPA), 104, 105, 275

National Environmental Policy Act of 1969 (NEPA),

70, 103, 104

National Historic Preservation Act of 1970, 70

National Gas Policy Act (NGPA), 34, 71, 72, 78, 85,

99, 100

New Hampshire Limited Electrical Energy Producers

Act, 97

Occupational Safety and Health Act (OSHA), 70,

101, 153

Powerplant 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, 56

Resource Conservation and Recovery Act of 1976, 70

Securities and Exchange Commission Act of 1935, 67

Windfall Profits Tax Act, 104, 110, 267

Louisiana, 40, 41, 171, 173, 182

Lovins, Amory, 260

lowest achievable emission rate (LAER), 101, 103, 240

latent-heat storage, 159
298 . Industrial and Commercial Cogeneration

Maine, 41, 182

Maryland, 41, 182

Massachusetts, 40, 41, 87, 96, 97, 182

Massachusetts Department of Public Utilities (DPU), 97

methanol, 239

Michigan, 41, 87, 182

Michigan State University, 152

Mid-America Interpool Network, 198

Minnesota, 41, 57, 182

Mississippi, 40, 41, 171, 182

Missouri, 41, 57, 96, 182

Missouri Basin Municipal Power Agency, 57

Montana, 41, 88, 182

Municipal Electric Authority of Georgia, 57

National Academy of Sciences, 237

national energy context, 49-54

National Energy Policy Plan, projection, 50

National Pollutant Discharge Elimination System

(NPDES), 101, 102, 103, 243

National Register, 71

National Rural Electric Cooperative Association, 151

National Rural Utilities Cooperative Finance Corp.

(CFC), 66

Natural Resources Defense Council, 90

Nebraska, 41, 56, 62, 88, 182

NEPA (see legislation, National Environmental Act

of 1969)

Netherlands, Rotterdam, 178

Nevada, 41, 88, 182

New England Electric System (NEES), 97

New England Power, 97, 98

New England Power Pool (NEPOOL), 96, 97, 98

New Hampshire, 40, 41, 88, 96, 97, 98, 182

New Jersey, 40, 41, 88, 178, 179, 182, 187, 189

New Mexico, 41, 182

new source performance standards (NSPSs), 100

New York, 40, 41, 56, 88, 93, 101, 179, 182, 187,

189, 231

New York Public Service Commission (NYPSC), 94, 154,

231, 256

NGPA (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, 238

North American Electric Reliability Council (NERC), 52,

57, 58, 59, 198

North Carolina, 41, 57, 88, 182

North Dakota, 41, 88, 182

Northeast 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, 182

Oklahoma, 41, 57, 89, 182

Oregon, 41, 89, 182

ownership of cogenerators, 16, 38-39, 77, 106-112

Pacific Gas & Electric (PG&E), 90, 91, 95, 96, 256, 257

Pennsylvania, 41, 171, 182, 189

Philips, N. V., Einhoven, Netherlands, 178

platinum, 138

Potlatch Corp., Lewiston, Idaho, 172, 173

public service commissions (PSCs), 62, 63, 64, 66,

69, 85

public utility commissions (PUCs), 86, 96, 97

PURPA (see legislation, Public Utility Regulatory Policies

Act of 1978)

qualifying facilities, 78-98

Radian Corp., 233

references, 21, 44-45, 112-114, 165-167, 216-217,

263-264, 278

Resource Planning Associates, 185

Rhode island, 40, 41, 89, 182

Riverside Cement Co., Oro Grande, Calif., 175

Roosevelt, Franklin, 262

Ruhr Chimie, Oberhausen, Germany, 177

Rural Electrification Administration (REA), 66, 111,

112, 150

Salt River Project (SRP), 148, 149, 150, 151

Seabrook 1, 97

Security and Exchange Commission (SEC), 67

Shell Oil Co., ,178

socioeconomic impacts, 17-18

Solar Energy and Energy Conservation Bank, 105

Solar Energy Research Institute (SERI), 52, 53, 54,

186, 187

South Carolina, 41, 89, 182

South Dakota, 41, 182

Southeastern Power Administration, 57

Southern California Edison, 148, 151, 153, 154, 155,

156, 177, 207, 273

Southern California Gas Co., 108

Southwestern Power Administration, 56

Southwestern Public Service Co., 173

SRI International, 186

Stal-Laval Turbin AB, Sweden, 178

Standard and Poor’s, 94

sulfur dioxide (SO2), 101, 102, 103, 223, 224, 225, 230,

231, 237, 238

Sweden, 178

Tennessee, 41, 182

Tennessee Valley Authority (TVA), 56, 143, 177

Texaco, 177

Texas, 40, 41, 57, 172, 174, 182

Thermo Electron Corp., 178, 185, 186

Three Mile Island (TMl), 74
Index . 299

Union Carbide Corp., Texas City, Tex., 174

U.S. Army Corps of Engineers, 56, 57, 71, 243

U.S. Court of Appeals, 20, 37, 76, 78, 81, 82, 83, 84,

85, 90, 93, 105, 268, 271, 275

U.S. energy demand, 1980, 49-54

electricity, 52, 53

natural gas, 51, 52

oil, 51, 52

thermal, 53, 54

U.S. Forest Service, 243, 244

U.S. Supreme Court, 76, 82, 85, 105, 271, 272

Urban Development Action Grant (UDAG), 110

urban meteorology, 44, 228

Utah, 41, 89, 182

utility obligations to qualifying facilities

to interconnect, 84

to operate in parallel, 84

to purchase, 78-82

to sell, 83

simultaneous 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, 182

Vermont Public Service Board, 97

Virginia, 41, 145, 182

Washington, 41, 182

Water quality, 17, 241

Western Area Power Administration, 57

West Virginia, 41, 182

Williams, Robert H., 185, 186, 187

Wisconsin, 41, 89, 182

Wood, 144, 171, 213

Wyoming, 41, 89, 172, 182