CONGRESS OF THE UNITED STATES

CONGRESSIONAL BUDGET OFFICE

A

CBO

PAPER

SEPTEMBER 2003

Prospects for

Distributed

Electricity

Generation

JupiterImages
CBO
CBO

Prospects for Distributed 

Electricity Generation

September 2003

The Congress of the United States # Congressional Budget Office 

A

P A P E R

Preface

In the aftermath of the recent electricity blackout that affected major portions of the

Midwest and Northeast, many commentators have argued that distributed generation—the

smallscale production of electricity at or near customers’ homes and businesses—could im

prove electricity reliability and ease the strain on the nation’s electricity transmission system.

This Congressional Budget Office (CBO) paper examines the current state of and prospects

for distributed generation, its benefits and risks, and barriers to the wider adoption of small

scale, customerowned technologies. The paper also discusses what types of policy changes

could help reduce barriers while limiting the downside risks of greater reliance on distributed

generation. The analysis was prepared at the request of the Ranking Member of the Senate

Committee on Energy and Natural Resources. 

Andrew Goett of CBO’s Microeconomic and Financial Studies Division wrote the paper, with

contributions from Richard Farmer, under the supervision of David Moore and Roger

Hitchner. Robert Shackleton and Dennis Zimmerman of CBO and Henry Lee of the John

F. Kennedy School of Government at Harvard University provided useful comments. 

Christine Bogusz edited the paper, with assistance from Leah Mazade and Joseph Foote.

Angela Z. McCollough prepared drafts of the manuscript, and Sharon CorbinJallow prepared

the paper for publication. Annette Kalicki produced the electronic versions for CBO’s Web

site (www.cbo.gov).

Douglas HoltzEakin

Director

September 2003

1

2

3

4

CONTENTS

Summary ix

Introduction 1

The Current Status of and Prospects

for Distributed Generation 5

How Distributed Generation Contributes

to the Nation’s Power Supply 6

A Description of Selected Electricity Generation

Technologies 7

The Cost Structure of Distributed Generation 9

Other Economic Considerations in

Installing Distributed Generators 14

The Benefits and Risks of Distributed

Generation 15

Potential Savings in the Production

and Delivery of Electricity 16

Additional Savings from Incentives for

Adjusting Demand 17

Potential Benefits for the Environment and

National Security 19

Uncertainties and Risks 19

Barriers That Impede Widespread Adoption

of Distributed Generation 23

Protecting the Grid: Interconnection Requirements

and Costs 23
vi PROSPECTS FOR DISTRIBUTED ELECTRICITY GENERATION

5

Utility Surcharges: Paying for Stranded Costs

and Standby Service 24

Compensating for Avoided Costs: Prices for

Power Sold to Utilities 26

Environmental Concerns: Siting Restrictions and

Permitting Requirements 27

Future Competitiveness: Uncertainty Surrounding

Costs 28

Policy Options 29

Access to the Grid: Reducing Technical,

Contractual, and Cost Barriers 29

RealTime Prices Based on Wholesale Costs:

Reducing Pricing Barriers 31

Local Government Permits: Reducing

Siting and Environmental Barriers 34

Appendix

Electricity Market Restructuring and Distributed

Generation 35
CONTENTS vii

Tables

1. Installed and Potential Combined Heat and Power

Generation 8

2. Comparison of Selected Electricity Generation Technologies 11

Figures

S1. Levelized Cost of Selected Technologies Suitable for

Distributed Generation xi

1. Levelized Cost of Selected Technologies Suitable for

Distributed Generation 12

2. Levelized Cost of Solar Photovoltaic Electricity, 1980 to 2020 13

3. Volatility in the Spot Price of Electricity 18

Box

1. Electricity Basics 2

Summary

Distributed generation, the smallscale production

of electricity at or near customers’ homes and businesses,

has the potential to improve the reliability of the power

supply, reduce the cost of electricity, and lower emissions

of air pollutants. The recent disruption in electricity ser

vice throughout major portions of the upper Midwest

and the Northeast has reminded policymakers of the

importance of a very reliable supply of power. The high

price of electricity in certain regions and problems with

emissions from older power plants have stimulated inter

est in alternatives to traditional utilitysupplied power.

Distributed generation could provide benefits in all of

those areas. Energy legislation under consideration in this

session of Congress includes provisions that will en

courage wider use of distributed generation. This paper

explores the context in which policymakers may be ad

dressing distributed generation issues in the near future.

Distributed generation can come from conventional

technologies, such as motors powered by natural gas or

diesel fuel, or from renewable technologies, such as solar

photovoltaic cells. Over the past two decades, declines in

the costs of smallscale electricity generation, increases in

the reliability needs of many customers, and the partial

deregulation of electricity markets have made distributed

generation more attractive to businesses and households

as a supplement to utilitysupplied power. Some policy

makers believe, however, that various rules, restrictions,

and prices set by utilities, regulators, or administrative

bodies do not reflect the net economic benefits of dis

tributed generation and act as barriers to its costeffective

adoption and operation. Those barriers could be lowered

significantly by clarifying and standardizing the rules for

connecting distributed generators to the electricity supply

network (the grid) and by setting prices for basic elec

tricity services (access to the grid, the electric power itself,

and the transportation of that power) that reflect their

costs.

If the new rules and prices are well designed, the cost of

providing highly reliable electricity service to customers

who desire it and the total cost of serving all customers

will probably fall as distributed generation becomes more

widely used. But initiatives to reduce barriers to wide

spread adoption have costs and risks, which will pose a

challenge to electric utilities, regulatory bodies, and other

public agencies that must develop and enforce the rules

governing interconnection and establish prices for elec

tricity from those new sources of power. If customers are

allowed to connect their distributed generators to the

grid without adequate safeguards, the overall perfor

mance of the electric system can be impaired. Changes

that can promote costeffective distributed generation,

such as the adoption of economically sound pricing, may

increase rates for customers who currently pay prices that

are below the utilities’ costs for providing service. If the

new rules and prices are poorly designed, the changes

that benefit distributed generators will raise the overall

cost of electricity and increase rates to most other cus

tomers. Aside from those risks, separate technological

and regulatory changes that would significantly lower the

future cost of utilitysupplied electricity (for example,

additional cost reductions in largegeneration technolo

gies and extensive competition in wholesale markets)

could lessen the attractiveness of some new investments

in distributed generation.
x PROSPECTS FOR DISTRIBUTED ELECTRICITY GENERATION

To investigate those issues, this paper addresses four

questions. What are the current status of and prospects

for distributed generation technologies, particularly in

terms of their costs as compared with those of utility

supplied power? What are the benefits and risks of a

wider adoption of distributed generation in restructured

electricity markets? What specific utility practices, local

government regulations, and electricity pricing methods

may be acting as barriers to adoption? And what types

of policy changes could help reduce those barriers while

limiting the downside risks of greater reliance on dis

tributed generation? Although many of those policy

changes could be the concern of state and local au

thorities, this paper highlights the federal role—par

ticularly those aspects that might receive legislative

attention. 

The Current Status of and Prospects

for Distributed Generation

Distributed generation is an important, although small,

component of the nation’s electricity supply. The prin

cipal source of electricity today continues to be large cen

tral facilities that generate electricity from steam plants

(fueled by coal, natural gas, or nuclear power) and hydro

electric power. Historically, most steam plants were oper

ated by large investorowned utilities that were respon

sible for generating electricity, transmitting it from the

central generating facilities to communities, and, in

many regions, distributing it to retail customers within

those communities. The federal government has had an

important role in producing most of the nation’s hydro

electric power, and local governments own many of the

distribution systems that deliver the power supplied by

the investorowned utilities and the federal government.

Among distributed generation technologies, the most

important in terms of their capacity to generate elec

tricity are customerowned generators that produce both

electricity and steam for onsite use (called combined

heat and power, or cogeneration) and emergency backup

generators. Together, those two sources account for more

than 95 percent of the customerowned generation

capacity in the United States. For the most part, the

cogeneration plants that have been built to date are large

facilities that sell the majority of their output to utilities.

Natural gas fuels most of those plants, but coal and

biomass also power a significant percentage of the total

capacity. Most backup generators are internal combus

tion engines fueled by diesel oil or gasoline. Dieselfired

backup generators are commonly used in highrise

buildings for safety reasons (as required by local building

codes), in hospitals, and in manufacturing facilities that

depend on a highly reliable supply of power. 

Renewable technologies that are currently used to gener

ate electricity at homes and businesses include wind tur

bines and solar photovoltaic systems. Those technologies

produce electricity intermittently and generally are not

available to operate continuously. Fuel cells and small

turbines (called microturbines) are frequently mentioned,

newly emerging highefficiency technologies. Although

they account for very little of the nation’s existing elec

tricity supply, proponents believe they will contribute

significantly in the future.

Four developments over the past decade have spurred

interest in moving distributed power beyond the limited

markets that it now serves and integrating it more fully

into the nation’s electricity supply. First, the costs of re

newable technologies and highefficiency technologies

that are suitable for operation by households and small

businesses have fallen. Typical costs of electricity from

certain distributed generation systems are now within

range of those of electricity from large generators, and

they are below the average prices of electricity in some

regions of the United States (see Summary Figure 1).

Second, the introduction of competition to wholesale

electricity markets has increased the possibilities for sales

of customerowned distributed power. Those newly com

petitive markets feature prices that vary hourly and that

are high during periods of peak demand (times at which

distributed generators would be most profitable to op

erate). Third, many commercial and industrial customers

place increasing importance on highly reliable electricity

service, which can be provided by onsite generation.

Fourth, building new transmission lines to meet growing

demand has been a contentious issue for local, state, and

federal regulators and among power producers. Wider

adoption of distributed generation can in some cases

obviate the need for new transmission capacity.
SUMMARY xi

Summary Figure 1.

Levelized Cost of Selected Technologies Suitable for Distributed Generation

Source: Congressional Budget Office using data on electricity prices from Department of Energy, Energy Information Administration, Electric Power Annual 2000

(August 2001), Table 21.

Notes: CHP = combined heat and power (also known as cogeneration); ICE = internal combustion engine; N.E. = New England.

The levelized cost is the average cost of electricity (cents per kilowatt-hour) over the operating life of the generation equipment. Future costs and output

flows are based on data in Table 2 and are discounted at 7 percent from their present values. The cost estimates assume that the systems powered by fossil

fuels will be operated 90 percent of the time and that the wind and solar photovoltaic systems will run 40 percent and 27 percent of the time, respectively.

Levelized cost comparisons do not include the effects of tax credits or other direct subsidies for specific technologies.

“Large wind turbine” is not included in the figure (as it is in Table 2) because it is not generally considered to be well-suited to distributed generation

applications (typically, it is not located near customers).

a. In a combined-cycle system, a combustion turbine is operated in tandem with a steam turbine. The system is included here as a benchmark for the cost of power

from new large-scale generators. Transmission and distribution expenses would add an estimated 2.4 cents per kilowatt-hour, on average, to the marginal cost

of delivered power.

Those developments have prompted discussions about

using distributed generation differently from how it is

typically used today. Rather than just serving as emergency

backup or exploiting large commercial cogeneration op

portunities, small generation systems could operate reg

ularly. Customers could use distributed generation to meet

most of their onsite requirements while relying on the

grid as a source of additional power and as an outlet for

excess power that they might generate. Utilities that dis

tributed power to retail customers could use distributed

generators to meet local peak loads (consumption) or to

provide highly reliable electricity service to customers that

required it.

Conventional fossil fuels, such as natural gas and diesel

oil, power the most common distributed generation tech

nologies, and they are likely to account for most of any

growth in distributed generation that operates regularly

and is connected to the grid. Renewable sources that pro

duce electricity intermittently, especially wind and solar,

N.E. Average

U.S. Average

Combined-Cycle Systema

Combustion Turbine--CHP

Combustion Turbine--Power Only

Small Wind Turbine

Solar Photovoltaic

Fuel Cell--CHP

Gas ICE--CHP

Gas ICE--Power Only

Microturbine--CHP

Microturbine--Power Only

0 5 10 15 20 25 30

Cents per Kilowatt-Hour (In 2000 cents)

Price of Electricity
xii PROSPECTS FOR DISTRIBUTED ELECTRICITY GENERATION

will be used more if customers can rely on the traditional

utility system to eliminate deficits and to absorb excesses

from onsite power production.

The Benefits and Risks of

Distributed Generation

Nonutility owners of distributed generation units could

individually benefit from structural changes that allowed

their power generation activities to be integrated with

those of utilities. By spreading their capital costs (the costs

of acquiring and installing the generating unit) over an

increased number of operating hours, they could lower

their average generation costs. They could also earn re

venues from their sales of electricity to utilities or other

customers, further improving the returns on their invest

ments in distributed generation. But the economy at large

might also benefit from a more widespread adoption of

distributed generation technologies. Such adoption would

lower the overall cost of electricity for all customers, en

hance the reliability of the power supply, reduce the need

for transmission and distribution investments to serve

growing demand, and improve environmental quality

through the increased use of renewable energy sources and

fuelefficient technologies.

If distributed generators are operated in situations in

which their costs are lower than those of centrally supplied

power, the overall cost of supplying electricity will fall.

Those situations often occur during periods of peak elec

tricity use (at certain times of the day or seasons of the

year). At those times, relatively small reductions in de

mand for utilitysupplied power (if the owners of dis

tributed generators produce additional electricity for their

own use) or increases in the utilities’ supply (if the owners

produce additional electricity for sale to the utilities) will

reduce wholesale prices considerably. The availability of

additional electricity during peak periods may help en

hance the reliability of the power supply. A further benefit

of increased supply and flexibility in demand on the part

of owners of distributed generators would be a reduction

in electricity price volatility (because extreme price spikes

would be eliminated).

Distributed generation could also encourage efficient

investments in electricity reliability by offering a cost

effective alternative in many situations to constructing

new transmission and distribution power lines and trans

formers. Those investments might make the electric sys

tem more secure and less vulnerable to widespread service

disruptions. In addition, a healthy distributed generation

industry could put competitive pressure on transmission

utilities to expand service and reduce congestion. 

Changes that generally facilitate the integration of cus

tomerowned distributed generation with the grid could

also encourage the adoption of specific renewable energy

and highefficiency technologies, including solar photo

voltaic systems, fuel cells, and microturbines. Shifting to

sources of electricity that made greater use of nonfossil

fuels or lesspolluting forms of fossil fuels or that made

more efficient use of conventional fuels might produce

regional and global environmental benefits.

The widespread adoption of distributed generation tech

nologies poses risks, however. The reliability of power to

all customers might be diminished rather than bolstered

if the operators of electric systems found it difficult to

manage a much greater number of power sources— sup

pliers that were adding electricity to or drawing electricity

from the grid at will. Equivalently, the retail price of

electricity could rise if ratepayerfunded investments were

necessary to maintain power quality. And operation of

large numbers of small customerowned generators

—especially those fueled by diesel oil—could be detri

mental to local air quality. Finally, poorly designed poli

cies to encourage distributed generation might bring

unexpected costs. In particular, liberalizing the rules that

govern the connection of distributed generators to the

grid under traditional regulatory methods of electricity

pricing (whereby utilities set power rates to recover past

costs and earn an allowed return on capital investments)

could encourage some customers to invest in distributed

generators whose power was more expensive than new,

centrally supplied power. That outcome could increase

the overall cost of electricity to the utilities’ remaining

customers (ones who did not operate distributed genera

tors).

Increased competition in wholesale electricity markets and

reforms in retail electricity pricing could significantly

reduce the number of situations in which distributed

generation was profitable to owners. Competition in
SUMMARY xiii

wholesale markets could lower electricity prices to the point

at which many investments in distributed generation

would no longer be attractive. Widespread application of

realtime pricing, which could provide incentives for the

operation of distributed generators, could also end up

making many of them unprofitable. Realtime pricing

and other tariffs (rate schedules) that encouraged retail

customers to vary their demand for electricity in response

to price changes could significantly lessen price volatility

as well as average prices. That result would reduce the

number of hours per year that many distributed generators

could operate profitably.

Barriers That Impede Widespread

Adoption of Distributed Generation

Proponents of distributed generation argue that significant

barriers impede the widespread adoption of distributed

generation technologies. Most, if not all, of those barriers

are related to the risks cited earlier. They include utilities’

pricing and operational practices and local governments’

rules about reliability and safety, cost, or environmental

quality. A common theme of the complaints against those

practices or rules is that they result in restricted access to

the grid and protect the utilities’ current investment in

central generation capacity and transmission lines.

Four types of barriers are frequently cited. The first type

is contractual and technical interconnection requirements

for the installation of protective equipment and safety

devices to protect the grid and ensure power quality;

distributed generation proponents argue that those re

quirements are often duplicative, excessive, and time

consuming. The second type is surcharges imposed by

utilities on operators of distributed generators (who are

still utility customers) for standby service; proponents

contend that those surcharges often do not reflect the

actual cost of the service and do not give credit for the ways

in which distributed generation benefits the grid. The third

type is pricing of electricity that is based on the utilities’

average cost rather than their marginal cost (the cost of

supplying an additional unit of electricity). Proponents

contend that averagecost pricing does not give owners

an incentive to operate their distributed generators during

periods when doing so will lower the overall cost of elec

tricity. The fourth type is environmental and permitting

requirements of local governments, which, in the pro

ponents’ view, broadly restrict the installation and opera

tion of electricitygenerating equipment or impose burden

some approval processes on applicants.

Achieving the potential cost and reliability benefits from

widespread adoption of distributed generation technologies

may depend on retail competition and unrestricted

customer choice. The competitive positions of many util

ities are already weakening with the restructuring of whole

sale electricity markets and increased use of the most wide

spread form of distributed generation (cogeneration for

customers’ own use and for sale to the utilities). Broader

adoption of distributed generation by customers could

be an important part of what many analysts believe will

be the next level of market restructuring—the introduction

of retail competition. Such competition would give cus

tomers the ability not only to choose their electricity sup

pliers but also to elect to generate electricity on their own.

Policy Options

The barriers that certain industry practices and govern

mental rules present to customers’ potential investments

in distributed generation could be lowered in two general

ways. One would be to standardize and clarify the rules

and procedures governing the installation and operation

of distributed generators and their interconnection with

the grid. That approach could streamline the approval

process and help to reduce uncertainty about the require

ments and costs of compliance. The second would be to

set the prices that operators of distributed generators pay

and receive for electric power, connection to the grid, and

transmission and distribution services at levels consistent

with the actual costs borne by utilities to provide those

services. That change could give customers incentives to

install and operate distributed generators at a level that

would help to ensure the lowest cost of electricity for all

customers. Specific changes would require utilities and

government agencies to: 

# Grant nondiscriminatory access to the grid under a

system of welldefined, uniform technical and con

tractual terms and costbased interconnection fees—so

that operators would know in advance what was re

quired to run their distributed generators at the same
xiv PROSPECTS FOR DISTRIBUTED ELECTRICITY GENERATION

time they were taking power from or supplying power

to the grid;

# Establish clear, explicit rates for standby electricity

service that are based on the cost of the equipment

utilities require to meet infrequent demand—so that

operators of distributed generators would know those

surcharges in advance and receive rate treatment com

parable to that of regular customers; 

# Purchase excess power from operators of distributed

generators at prices consistent with utilities’ wholesale

cost of power in real time in circumstances in which

no competitive markets for distributed generation

power exist—so that operators could sell their power

at prices consistent with the savings to the utilities;

# Establish realtime pricing for utilities’ sales to retail

customers based on the wholesale price of electricity

as it varies over time and across delivery locations—so

that operators of distributed generators could decide

on the basis of market signals whether to purchase

or generate power; and

# Develop uniform national environmental standards

for distributed generation that would allow precerti

fication of equipment—so that manufacturers could

design units to national specifications and distributed

generators would not need to qualify on a casebycase

permitting basis.

It is not clear where any initiative to require those types

of changes might best originate—whether in the Congress,

the Federal Energy Regulatory Commission (under existing

authorities), or state governments. The 108th Congress

has shown interest in fostering distributed generation

through various legislative proposals that contain provisions

for nondiscriminatory access to the grid and realtime

pricing. Under existing legislative authority, the design

of any policy initiative affecting distributed generation

is complicated by the division of regulatory responsibilities

among the federal, state, and local governments. Under

the original framework established by the Federal Power

Act of 1935, the federal government has responsibility

for the regulation of pricing and access in the wholesale

power markets, and the states have responsibility for the

retail markets served by investorowned utilities. The state

owned, municipal, and cooperative utilities that also serve

retail customers set their own rules for pricing and service.

Decisions about the siting of power plants—in con

sideration of safety, air quality, noise, and local con

gestion—are generally in the domain of state and local

governments, subject to certain federal regulations. The

issue of promoting distributed generation, whether by small

independent suppliers of cogeneration electricity or house

holds with solar panels, cuts across all those jurisdictions.

In terms of economic efficiency, it does not matter which

level of government is responsible for making those

changes. But it is important that broad changes to pricing

and to operational practices occur together. Unless fun

damental changes in access, pricing, and siting are ad

dressed concurrently, the goals of promoting the use of

and gaining the benefits of distributed generation may

not advance noticeably. An argument for the Congress

to take a lead in this area could be based on the value of

standardizing the approach across regions of the country

and of possibly enhancing the ability of the federal gov

ernment to achieve balance among the many vested in

terests that stand to gain or lose from those changes.
1

Introduction

The electric power industry in the United States is

undergoing fundamental changes—from being an in

dustry dominated by regulated monopolies that own entire

electricity systems (vertical integration) to one featuring

a mix of competitive electricity generation companies,

commoncarrier transmission organizations, and regulated

distribution companies. Spurred by technological advances

and a public policy strategy at the federal and state levels,

those changes are transforming both wholesale and retail

power markets. At the wholesale level, independent power

producers now generate more than 14 percent of the

nation’s electricity for sale at marketbased rates to utility

distribution companies.1

 At the retail level, 23 states and

the District of Columbia have already passed legislation

or issued regulatory orders supporting the ability of

customers to choose their electricity suppliers.2

 (See the

appendix for a brief summary of the history of electricity

market organization in the United States.) 

One of the powerful forces driving that transition in

market structure has been advances in electricity gener

ation technologies that have reduced the costs of smaller

capacity systems—generally those under 2 megawatts. (See

Box 1 for an explanation of the characteristics of electric

power.) Technologies such as microturbines are available

in capacities under 100 kilowatts (roughly the size of an

automobile engine). Largescale power plants (100 mega

watts or greater), which are typically used by vertically

integrated utilities, no longer have significantly lower costs

than smaller plants do. That change has weakened one

of the main rationales for maintaining electric power pro

duction as a regulated monopoly—namely, that the exclu

sive franchise was necessary to fully exploit the savings

in generation and transmission costs from largescale, cen

trally located power plants. 

The first entities to take advantage of those cost reductions

in a significant way have been certain independent power

producers, or businesses that generate electricity primarily

to sell to the utilities. Most of those producers use gen

eration units with capacities in excess of 1 megawatt. But

the cost reductions extend to even smaller generation units

(less than 1 megawatt), many of which are suitable for

producing power to serve small businesses, commercial

buildings, and homes. That development has added one

more dimension to the effort to capture the benefits of

competitive markets in the electric power industry—the

prospect that local smallscale generation could compete

with electric power from large, central power plants.

In contrast to the power supplied by utilities and many

of the large independent producers, which is often gen

erated away from population centers and moved over

extensive transmission and distribution networks, small

customerowned generators are sited at or near the

locations where the electricity is used. Those small gen

erators are often not fully integrated with the utilities’

1. Department of Energy, Energy Information Administration,

Electric Power Annual 2000 (August 2001), Table 1, available at

www.eia.doe.gov/cneaf/electricity/epav1/intro.html#tab1. 

2. Department of Energy, Energy Information Administration, Status

of State Electricity Industry Restructuring Activity—as of February

2003, available at www.eia.doe.gov/cneaf/electricity/chg_str/

regmap.html. According to Energy Information Administration

statistics, retail choice is available to some or all of the customers

(or will soon be available) in 17 states and the District of Columbia.

In the remaining six states, retail competition has been delayed

or suspended. 

CHAPTER
2 PROSPECTS FOR DISTRIBUTED ELECTRICITY GENERATION

Box 1.

Electricity Basics

The basic unit of electric power is a watt, which is a

rate of producing or consuming energy. A typical

lightbulb, for example, consumes electricity at the rate

of 75 watts, or 75 watthours of electricity in one hour

of operation. One kilowatt is 1,000 watts. The average

household in the United States uses almost 12,000

kilowatthours (12 million watthours) per year. A

power plant with a 1megawatt capacity (1,000 kilo

watts), operating continuously (8,760 hours) for a year

would generate enough electricity to supply approxi

mately 750 households. (A different way to understand

what those units of electricity represent is to relate

them to horsepower, another measure of power. A

kilowatt is roughly equivalent to 1.3 horsepower; a 1

megawatt plant is equal in power to approximately 10

mediumsized automobile engines.)

Another characteristic of electric power is voltage,

which is a measure of electromotive force. Electricity

is usually generated and transported at very high vol

tages (more than 100,000 volts). Electric voltage is

lowered, by a series of transformers in the substations

and on feeder lines close to where it is consumed, until

it reaches 120 volts (in the United States) at electrical

outlets in a typical household.

In the United States, the electric power system gener

ates a form of electricity, termed alternating current,

in which voltage oscillates in a regular cycle. The

frequency of that cycle is 60 times per second, referred

to as 60 hertz. Electric motors and other devices in the

United States are designed to use 60hertz alternating

current. If the electric current deviates significantly

from that designed frequency, it can seriously damage

motors and appliances.

At any time, the amount of electric power (the number

of watts) that is being consumed on a utility network

(the system of generation and consumption points

connected by wires and other transmission equipment)

must be nearly equal to the amount of power that is

being generated. The voltage and frequency of the cur

rent will adjust according to physical laws to maintain

a balance. If a sudden change in consumption occurs

without an adjustment in generation (or vice versa),

An Electric Power System

Source: Congressional Budget Office based on a figure from EPRI PEAC

Corporation.

the voltage will change, possibly damaging equipment

throughout the network. Certain types of generators

have controls that automatically adjust output to

match consumption. Utility networks also have many

protective devices that minimize any damage from a

rapid change in voltage. For example, electric fuses or

circuit breakers automatically cut off electricity when

they detect a large voltage change caused by, say, a

lightning strike or short circuit that could damage

equipment.

Electricity consumption at any point in time is referred

to as the load. On a typical utility network, the load

fluctuates continuously as customers start and stop

their equipment. Network operators continually adjust
CHAPTER ONE INTRODUCTION 3

Box 1.

Continued

production to match those fluctuations. When con

sumption is low, they use plants that are designed to

run continuously at a low operating cost. As consump

tion rises, they add production from other plants—

whose operating costs are higher—that are designed to

start and stop and adjust output quickly. In periods of

extremely high consumption, they use older plants that

are less efficient and even more expensive to operate.

As a result, the cost of supplying an additional unit of

electricity (the marginal cost) typically rises as con

sumption increases. That cost depends on many fac

tors, including the characteristics of available power

plants, the price of fuel, and the location of plants rela

tive to the places where electricity is consumed.

An electric power system has two major functions—

generation and transportation (see the figure at left).

The United States today has approximately 750,000

megawatts of generating capacity, most of which

comes from large commercial power plants with

capacities of more than 100 megawatts. Those plants

are powered largely by coal or other fossil fuels, al

though nuclear and hydroelectric power also account

for a significant portion of capacity and annual output.

In 2000, those plants produced a combined total of

3.8 trillion kilowatthours of electricity.

The transportation of electricity is typically broken

down into transmission, which is the highvoltage

transport of electricity over long distances, and distri

bution, which is the transport at lower voltages over

the last few miles to the point of consumption. No

clear line divides the two components, but transmis

sion networks in the United States typically have at

least two electric paths between any two points (a loop

configuration), whereas the distribution system has a

single path between the substation and the consumer

(a hubandspokes configuration). 

electricity networks, which produce power around the clock

or on demand from central dispatching stations—although

the prospects for fuller integration of such distributed

generation with the grid may be desirable.3

Policymakers have an interest in the future of distributed

generation, not only for the cost savings it can provide

to the homes and businesses that produce it but also for

the cost savings and additional reliability that it may be

able to offer to the entire electricity market. Distributed

generation may play a larger role, along with demand

management techniques and further innovations in wholesale

and retail markets, in reducing the cost of electricity when

traditional supply is tight or market demand is strong.

For example, distributed generation may offer retail

customers greater flexibility to alter their demand for

electricity in response to hourly changes in prices (realtime

pricing), thereby promoting the efficient operation and

stability of energy markets as they become increasingly

competitive. Some observers expect distributed generation

to play a role in the commercial development of renewable

energy and highefficiency technologies, adding the associated

environmental and safety benefits. 

The prospects for distributed generation will be strongly

influenced by the outcomes of several policy initiatives.

Specifically, the wider adoption of distributed generation

and its associated benefits may depend significantly on

the structure of deregulated electricity markets, in which

the federal government plays a central legislative and

regulatory role. Recent legislative proposals considered

in the Congress have contained provisions—for example,

requirements for nondiscriminatory interconnection with

the grid and realtime pricing of electricity—that would

directly affect the viability of distributed generation. Also,

the federal government has taken an active role in developing

and commercializing renewable energy technologies, some

of which are wellsuited to distributed generation. 

This paper analyzes distributed generation by answering

four general questions:

# What are the current state of and prospects for

distributed generation technologies, particularly in

3. The grid refers generally to a selfcontained local or regional

network of electric power plants and the high and lowvoltage

power lines and transformer stations that deliver the power

generated by those plants to customers.
4 PROSPECTS FOR DISTRIBUTED ELECTRICITY GENERATION

comparison with the conventional supply of electricity?

(Chapter 2 addresses that topic.)

# What are the benefits and risks of a wider adoption

of distributed generation in a restructured electricity

market? (See Chapter 3.)

# What are the barriers to adoption and efficient use

of distributed generation technologies? (See Chapter 4.)

# What legislative, regulatory, and administrative ini

tiatives can help lower those barriers while avoiding

or limiting the downside risks of greater reliance on

distributed generation? (See Chapter 5.)
2

The Current Status of and

Prospects for Distributed Generation

Distributed generation refers to the production of

electricity at or near the place of consumption.1

 Exam

ples of distributed generation include backup generators

at hospitals, solar photovoltaic systems on residential

rooftops, and combined heat and power (CHP) systems

(also known as cogeneration) in industrial plants and on

university campuses. Those applications differ from the

infrastructure for supplying electricity that utilities in the

United States have built over the past five decades. Un

der that infrastructure, utilities typically have built power

plants away from centers of consumption, on the basis

of such factors as fuel transportation costs and environ

mental regulations, and then moved that electricity long

distances over highvoltage transmission lines to local

distribution systems, which then reduce the voltage and

deliver the power to retail consumers. 

Although some types of distributed generators have been

around for a long time (the earliest generators were

largely “distributed” in the sense that they were located

near the points of consumption), total customerowned

generation as a percentage of all output is small. The

Energy Information Administration (EIA), an agency

within the U.S. Department of Energy (DOE), estimates

that in 2000 (the latest year for which data are available),

only 0.5 percent of total U.S. electricity generation (21

billion of 3,800 billion kilowatthours) was from “non

utility generation for [customers’] own use.” In addition,

cogeneration systems in the commercial and industrial

sectors produced 135 billion kilowatthours (3.6 percent

of U.S. generation) for their own use.2

 

Three basic characteristics differentiate most distributed

generation from traditional electricity supply: location,

capacity, and grid connection. Distributed generators are

located at or near the point at which the power is used.

They are typically onsite generators, owned and operated

by retail customers, that are used to meet a portion of the

customers’ demand or to provide backup service for

customers that need highly reliable power. Applications

of distributed generation could include combined heat

and power operations—for example, a university could

use CHP to generate electricity on campus and then use

waste steam from the boiler to heat buildings.

Electric utilities can also install their own small generators

near customers. Such installations relieve congestion in

power lines during periods of peak demand, helping to

defer investments in additional transmission and dis

tribution capacity. They may also be used to boost the

1. Although there is no universally accepted definition of distributed

generation, most of the policy issues surrounding distributed

generation concern small customerowned units that are connected

to the grid at the distribution level and that primarily serve onsite

needs. In this report, that is how the term is used, except when

utilityowned applications are being discussed. 

2. Department of Energy, Energy Information Administration,

Annual Energy Outlook 2003, with Projections to 2025, DOE/EIA

0383(2003) (December 2002), Table A8. “Combined heat and

power plants whose primary purpose is to sell electricity, or

electricity and heat, to the public (NAICS [North American

Industrial Classification System] code 22)” produced an additional

4.2 percent.

CHAPTER
6 PROSPECTS FOR DISTRIBUTED ELECTRICITY GENERATION

quality and reliability of local electricity service by pro

viding voltage control and backup power to customers

who require such “premium” service. 

The second defining characteristic of most distributed

generation is its size. Generation capacities of customer

owned units, used primarily to meet onsite requirements,

typically range from a few kilowatts to several hundred

kilowatts. Generators in that range are typically best suited

to applications that meet the energy demands of individual

homes and businesses or of small groups of customers.

Very few customers require generators larger than

1 megawatt to serve only their onsite needs.3

The level of their connection with the local or regional

electric grid is the third characteristic that distinguishes

distributed generators from traditional suppliers. Tradi

tional suppliers are connected to the grid at the trans

mission level (the highvoltage portion of the delivery net

work). If distributed generation came into widespread use,

most distributed generators would be connected to the

grid at the distribution level, which is the portion of the

delivery network, built with limited capacity, that trans

ports electricity at low voltages for the final few miles to

the customer. (That is also the portion of the network that

is owned and operated by local retail utilities, most of

which are regulated by state agencies.) 

Most of the policy debate surrounding distributed gener

ation concerns small (less than 2 megawatts) customer

owned systems that primarily serve onsite loads and are

connected to the utility network at the distribution level.

The debate has arisen in part because of technical issues

surrounding distributionlevel connections to the grid and

possible conflicts between local utilities and generators

that are both producers of electricity and retail utility cus

tomers. Both of those matters are discussed in Chapter 4.

How Distributed Generation Contributes to the Nation’s Power Supply

The applications that account for the largest portion of

the customerowned power production by distributed

generation in the United States are cogenerators used in

industrial or commercial operations or primarily to gener

ate electricity for sale. Those cogenerators typically range

in size from 1 to 500 megawatts, and they are capable of

producing enough electricity to serve 500 to 25,000

households. According to the EIA, slightly more than

27,000 megawatts of cogeneration capacity existed in the

commercial and industrial sectors in 2000.4

 That is 3.4

percent of the total regularly operated generating capacity

in the country. Most cogeneration is accounted for by

systems of more than 50 megawatts, concentrated in such

industries as paper products, chemicals, and petroleum

refining.5

 

After cogeneration, backup units that are operated only

in emergencies account for the most distributed generation

capacity. Backup generators used by such businesses as

hospitals and large commercial buildings typically range

in size from a few to several hundred kilowatts. According

to a 1995 survey by the EIA, nearly onefourth of the

commercial floor space in the country had some capacity

to generate electricity onsite.6

 But less than 1 percent of

that capacity was ever used to generate electricity to meet

peak demand or to operate continuously; in essence, it

constitutes a large reservoir of capacity that is virtually

untapped as a regular source of power. The Gas Research

Institute has estimated that up to 40,000 megawatts of

backup generation capacity exist in the United States,

compared with a total of 808,000 megawatts of regularly

3. Most cogeneration (combined heat and power) applications are

considered distributed generation because they typically are located

on a customer’s premises and serve onsite electricity and thermal

needs. On the basis of those criteria, cogenerators account for

almost all existing distributed generation production. But those

plants are mostly large generators (at least 50 megawatts), often

owned by third parties, that earn significant revenues by selling

most of their output to utilities. 

4. Department of Energy, Energy Information Administration,

Annual Energy Outlook 2003, Table A9. There are another 27,400

megawatts of cogeneration capacity in the utility sector.

5. Department of Energy, Energy Information Administration, The

Market and Technical Potential for Combined Heat and Power in

the Industrial Sector (prepared by Onsite Sycom Energy Corpora

tion, January 2000), p. 17.

6. Department of Energy, Energy Information Administration,

Modeling Distributed Electricity Generation in the NEMS Buildings

Models (August 2000), which is available at www.eia.doe.gov/oiaf/

analysispaper/electricity_generation.html.
CHAPTER TWO THE CURRENT STATUS OF AND PROSPECTS FOR DISTRIBUTED GENERATION 7

operated electricity generating capacity.7 Available state

level data show a similar relationship. The California En

ergy Commission (CEC) has compiled an inventory of

backup generators that individually have at least 300 kilo

watts of capacity.8

 It found more than 4,000 such genera

tors in the state in 2001, with a total capacity of 3,200

megawatts. Those generators could, if available, boost the

state’s total installed capacity of 54,000 megawatts by

more than 5 percent, the CEC estimated. Those data

suggest that gross available capacity in the United States

could be increased by 5 percent to 10 percent if all emer

gency backup generators were adapted to operate regularly.

Looking to the future, the EIA projects that additions of

electricity generating capacity between 2000 and 2025

will total almost 450,000 megawatts.9

 According to the

EIA’s Reference Case MidTerm Energy Forecast, more

than 11 percent of that capacity will come from dis

tributed generation (defined here as the additions of

cumulative capacity in the nonutility sectors plus electric

power sector cogeneration and natural gas distributed

generation).10 The electric power sector will add another

3 percent of the total in the form of renewable energy

sources (biomass, municipal solid waste, and solar photo

voltaic), most of which would be distributed generation.

The EIA reference case forecast implicitly assumes no

major changes in legislation or regulations that would

encourage increased reliance on distributed generation.

But there are reasons to expect that distributed generation

could meet a significantly greater portion of future elec

tricity demand in the United States, at costs that could

compete with those of generation from new central power

plants. The first reason is the existence of the considerable

amount of backup generation capacity (discussed above)

that is not included in the EIA’s estimates of existing or

projected capacity. Backup capacity represents a sunk cost

to its owners, who have typically installed the generators

to meet reliability needs or building code requirements.

In the absence of environmental prohibitions or other re

strictions, many of those generators could be adapted to

operate regularly, at the cost of modest investments in im

proved electronic power controls and pollution control

equipment. 

Studies commissioned by DOE on the market and tech

nical potential for combined heat and power in the

commercial and industrial sectors identify another rea

son.11 The studies found 163,000 megawatts of remaining

CHP potential in the commercial and industrial sectors

combined, in addition to more than 49,000 megawatts

of currently installed CHP (see Table 1). That potential

is spread across all major commercial building types and

industrial activities, with concentrations in paper products,

schools, and office buildings. The EIA reference case fore

cast projects that only 20 percent of that potential will be

realized in the next two decades. Policy changes that en

couraged distributed generation could increase that per

centage significantly.

A Description of Selected Electricity

Generation Technologies

Several technologies are frequently mentioned as well

suited to small and mediumsized distributed generation

applications. Among the technologies fueled by fossil

energy are conventional steam turbines, combustion tur

bines, internal combustion engine generators, micro

7. AnneMarie Borbely and Jan F. Kreider, eds., Distributed Gener turbines, and fuel cells. The renewable technologies are

ation: The Power Paradigm for the New Millennium (Boca Raton,

Fla.: CRC Press, 2001), p. 65.

8. California Energy Commission, Database of Public BackUp

Generators (BUGS) in California, available at www.energy.ca.gov/

database.

9. Department of Energy, Energy Information Administration,

Annual Energy Outlook 2003.

10. EIA’s forecast breaks out distributed generation in the electric

power sector as a separate technology. It defines distributed gener

ation as “primarily peak load capacity fueled by natural gas.”

11. Department of Energy, Energy Information Administration, The

Market and Technical Potential for Combined Heat and Power in

the Commercial/Institutional Sector and The Market and Technical

Potential for Combined Heat and Power in the Industrial Sector

(both prepared by Onsite Sycom Energy Corporation, January

2000). Those studies defined the technical market potential as “an

estimation of the market size constrained only by technological

limits—the ability of combined heat and power technologies to

fit existing customer energy needs.” (See p. 9 of the commer

cial/institutional sector report.)
8 PROSPECTS FOR DISTRIBUTED ELECTRICITY GENERATION

Table 1.

Installed and Potential Combined Heat and Power Generation

(In megawatts)

Installed Remaining Potential Total

Industrial 44,242 88,341 132,583

Commercial 4,926 74,638 79,564

Total 49,168 162,979 212,147

Source: Congressional Budget Office based on Department of Energy, Energy Information Administration, The Market and Technical Potential for Combined Heat

and Power in the Commercial/Institutional Sector and The Market and Technical Potential for Combined Heat and Power in the Industrial Sector

(both prepared by Onsite Sycom Energy Corporation, January 2000). 

photovoltaic cells, windpowered generators, and biomass

fueled generators.

Conventional steam turbines and combustion turbines

are welldeveloped technologies that are widely used for

mediumsized and large power systems (more than 500

kilowatts). In very large systems, typically built by com

mercial generators, combustion turbines are often operated

in tandem with steam turbines that use waste heat from

the combustion turbine to fire a boiler (that combination

is referred to as a combinedcycle system). Conventional

combustion turbines produce low emissions, given stan

dard control equipment, and they have low maintenance

and operating costs relative to those of most other

generating technologies. Those characteristics, along with

the short lead times needed to build units, make them

the preferred technology for most conventional generation

applications requiring more than several megawatts of

power. Such large units are used by industrial plants in

combined heat and power configurations that generate

excess power for sale to utilities.

Internal combustion engine generators, including diesel

cycle and spark ignition motors, are the most commonly

used technology providing backup power for reliability

or emergencysupply purposes. Units range in size from

5 kilowatts to 7 megawatts. They can burn refined petro

leum products (diesel and gasoline) or natural gas. Models

that burn natural gas have very low emissions because of

improved design of the combustion process and their use

of catalytic converters. The costs per installed kilowatt for

units with capacities suitable for distributed generation

are among the lowest of all the mature technologies.

Microturbines are small combustionturbine generators

that were developed on the basis of the turbocharger tech

nology used in trucks and airplanes. The capacity range

of microturbines (30 kilowatts to 400 kilowatts) covers

the average load requirements (consumption needs) of

most commercial and light industrial customers. Micro

turbines have low emissions of pollutants, especially nitro

gen oxides, which would permit their installation in urban

areas with restrictive emissions standards. Microturbine

electricity generators are in the early stages of commercial

development; studies commissioned by DOE predict that

their installed equipment costs (costs of equipment plus

installation) will fall significantly in the future.12

Fuel cells use an advanced electrochemical process to

generate electricity. The process is comparable to that used

in conventional batteries, except that the reactant material

in fuel cells can be replenished so that the units will not

run down. Fuel cells produce virtually no emissions of air

pollutants or greenhouse gases. Because their costs per

installed kilowatt are still high relative to those of conven

tional technologies, commercially available fuel cells cur

rently suit only very specialized applications. But some

companies have developed new fuel cell technologies that

they project will lower costs significantly.13

12. See, for example, Department of Energy, National Renewable

Energy Laboratory, Gas Fired Distributed Generation Technology

Characterizations: Microturbines (prepared by Energy and Environ

mental Analysis, November 30, 2002), which projects declines

of 50 percent or more in installed capital costs by 2030.

13. For example, the California Distributed Energy Resource Guide

(a Web site on distributed energy run by the California Energy
CHAPTER TWO THE CURRENT STATUS OF AND PROSPECTS FOR DISTRIBUTED GENERATION 9

Photovoltaic cells convert sunlight directly into an electric

current. A panel of semiconductor material sandwiched

between two conducting layers absorbs solar energy and

releases electrons to produce the current. Photovoltaic

systems can be small, which is why they are widely used

in residential settings, particularly in the Southwest and

California. Because photovoltaic systems, by their nature,

produce electricity intermittently, they require battery stor

age or a supplemental power source to provide continuous

electricity service. Photovoltaic cells produce no direct

emissions, and they have low maintenance requirements.

Improvements in manufacturing processes have reduced

the costs of photovoltaic systems significantly in the past

decade. But their acquisition and installation costs, per

kilowatt, are still almost an order of magnitude (10 times)

greater than those of conventional systems, and their costs

per kilowatthour of delivered electricity are three to four

times the current average price of electricity in the United

States.

Wind generators are turbines powered by windmills. A

mature technology, wind turbines have been widely used

in California and Europe by utilities and independent

power producers to generate electricity to be sold over the

grid. In California, wind farms have total generating ca

pacities ranging from 15 megawatts to more than 600

megawatts (individual turbines at those sites have capac

ities of more than 1 megawatt). Most analysts would not

consider large wind turbines to be a type of distributed

generation because they are not typically located near cus

tomers. (Advocates of commercial wind power share many

of the same policy concerns as advocates of distributed

generation, however.) As with photovoltaic cells, the

potential of wind generators is limited by available wind

resources and by issues related to the siting of these large

towers with their rotating wind blades (including noise

and threats to migrating birds). 

Small wind turbines designed for residential and rural

applications to date account for only a limited share of

the market. For residential and small commercial dis

tributed generation applications, suitable wind turbine

capacities are 5 kilowatts to 50 kilowatts. The installed

costs per kilowatt for those smaller systems are much

higher than for the large systems. Because of the large

amount of space they require, small wind generators are

generally appropriate for applications in rural areas with

good wind resources.

Biomass refers to a renewable fuel rather than to a par

ticular technology. The EIA defines biomass as “organic

nonfossil material of biological origin constituting a

renewable energy source.” Wood products, animal and

plant agricultural waste, and municipal solid waste are

all examples of biomass. Electric generators use biomass

as fuel, often mixed with other fossil fuels. The most com

mon use of biomass is to heat a conventional boiler di

rectly. Another possible application is biomass gasification,

in which the product would be used in place of natural

gas. Although biomass may provide environmental bene

fits by displacing coalfired generation, the burning of

biomass and the production of animal wastes (as two

examples) can create air and water quality problems of

their own. The financial attractiveness of biomass depends

on such factors as the availability and cost of the organic

material, the avoided cost of alternative disposal of the

material, and the need for residual heat to warrant co

generation.14 

The Cost Structure of

Distributed Generation

The direct costs of distributed generation to customers

include the installed cost of the equipment, fuel costs,

nonfuel operation and maintenance (O&M) expenses,

and certain costs that the customers’ utility imposes. The

cost estimates that follow have been compiled from

authoritative sources, but they must be considered as in

dicative of the relative magnitudes of costs across tech

nologies rather than as point estimates. The values of each

Commission) states that most manufacturers, once the cells can

be produced in volume, are aiming for fuel cell capital costs below

$1,500 per kilowatt; see www.energy.ca.gov/distgen for more

information.

14. Because of the wide range of ways in which biomass fuels could

be used in distributed generation, this paper omits cost estimates

for “typical” biomass applications. Most of the barriers and policy

issues that apply to other distributed generation technologies,

however, especially those relating to environmental and siting re

quirements, also apply to biomass.
10 PROSPECTS FOR DISTRIBUTED ELECTRICITY GENERATION

cost’s components may vary substantially from one appli

cation to another, on the basis of several factors, some of

which are discussed below. The contribution of utility

charges to the total costs of generation are not included

in the estimates (they are discussed in Chapter 4, which

describes barriers to adoption).

To make this comparison of costs most useful, the Con

gressional Budget Office (CBO) assumed for each tech

nology an installed capacity, a rate of utilization, and (in

some cases) a geographic location that would be suitable

for serving the electricity needs of individual customers.

For example, the costs for the wind turbine discussed here

are for a size that might be used in a small rural business

(such as a farm) in a location with favorable wind re

sources. On that basis, data compiled from various indus

try and government sources describe the current costs of

the most common types of electricity generation tech

nologies (see Table 2). Data for a combinedcycle unit are

presented as well; as the largest source of additional elec

tricity from utilities and independent power producers,

combinedcycle systems provide a representative bench

mark against which the costs of other technologies can

be measured.

Capital Costs 

The costs of acquiring and installing a generating unit

vary widely, depending on technology, capacity, and other

factors. The Department of Energy estimates that the

typical installed capital costs for distributed generators

range from under $1,000 per kilowatt for a combustion

turbine to almost $7,000 per kilowatt for a solar photo

voltaic system.15 Among smallcapacity technologies, inter

nal combustion engines (fueled by diesel and gasoline)

have the lowest capital costs and highest operating costs.

Renewable technologies (using wind and solar power) have

the highest capital costs and lowest operating costs. New

highefficiency technologies (microturbines and fuel cells)

fall in between.

For customers who maintain emergency backup gen

eration onsite, the relevant capital cost for choosing the

least expensive source of electricity is not the total cost but

rather the additional investment needed to operate an on

site generator at the same time they are connected to the

utility network (termed parallel operation). (Currently, many

institutions and office buildings that are required to have

backup generators are permitted to operate those gener

ators only when they are disconnected from their utility

network.) That extra investment may include such costs

as equipment upgrades to meet environmental require

ments for regular operation and additions of power con

trols and metering to permit parallel operation. Those

additional costs would typically be small relative to the

basic investment costs—especially for installations in new

buildings, as opposed to retrofit upgrades. 

Long-Run Costs of Production

Although consideration of a technology’s capital costs can

be important when choosing to invest in distributed

generation, estimates of what economists refer to as long

run average costs—costs per unit of output that reflect

capital and operating expenses—are generally the more

important for investment decisions. Perhaps more relevant

for comparing distributed generation technologies with

one another and with utility costs and residential prices

is a commonly used index of longrun costs known as the

“levelized” cost. Levelized cost is a summary measure of

the average cost of electricity per kilowatthour, expressed

in current dollars. It is defined as the net present value

of all direct costs (for capital, fuel, and O&M) over the

expected lifetime of the system, divided by the system’s

total lifetime output of electricity.16 

A key input to those calculations is the assumption about

capacity utilization (the percentage of time that the unit

typically operates) for each technology. For purposes of

these comparisons, CBO’s estimates assume that all fossil

fueled systems will be operated 90 percent of the time

15. Department of Energy, Office of Energy Efficiency and Renewable

Energy, and Electric Power Research Institute, Renewable Energy

Technology Characterizations, EPRITR109496 (December 1997);

and Department of Energy, Energy Information Administration,

The Market and Technical Potential for Combined Heat and Power

in the Commercial/Institutional Sector.

16. The output stream is discounted at the same rate as the costs, to

keep the two comparable. The present value is a single number

that expresses a flow of current and future income (or payments)

in terms of an equivalent lump sum received (or paid) today.
CHAPTER TWO THE CURRENT STATUS OF AND PROSPECTS FOR DISTRIBUTED GENERATION 11

Table 2.

Comparison of Selected Electricity Generation Technologies

Capacity

(kW)

Capital Costa

($/kW)

Fuel Cost

($/kWh)

O&M Cost

($/kWh)

Service Life

(Years)

Heat Rateb

(Btu/kWh)

Microturbine—Power Only 100 1,485 0.075 0.015 12.5 13,127

Microturbine—CHP 100 1,765 0.035 0.015 12.5 6,166

Gas ICE—Power Only 100 1,030 0.067 0.018 12.5 11,780

Gas ICE—CHP 100 1,491 0.027 0.018 12.5 4,717

Fuel Cell—CHP 200 3,674 0.029 0.010 12.5 5,106

Solar Photovoltaic 100 6,675 0 0.005 20 n.a.

Small Wind Turbine 10 3,866 0 0.005 20 n.a.

Large Wind Turbine 1,000 1,500 0 0.005 20 n.a.

Combustion Turbine—Power Only 10,000 715 0.067 0.006 20 11,765

Combustion Turbine—CHP 10,000 921 0.032 0.006 20 5,562

Combined-Cycle Systemc 100,000 690 0.032 0.006 20 5,642

Source: Congressional Budget Office based on data from the Department of Energy’s National Renewable Energy Laboratory and Energy Information Administration;

Bergey Windpower Company; and the California Energy Commission.

Notes: kW = kilowatt; kWh = kilowatt-hour; O&M = operation and maintenance; Btu = British thermal unit; CHP = combined heat and power (also known as

cogeneration); ICE = internal combustion engine; n.a. = not applicable.

 All costs are in 2000 dollars. Fuel costs were calculated on the basis of national average prices for natural gas delivered to commercial customers in 2000.

a. The cost of acquiring and installing the generating unit. It does not include effects of tax credits or other direct subsidies for specific technologies.

b. High heat value.

c. In a combined-cycle system, a combustion turbine is operated in tandem with a steam turbine.

(termed “base load” operation), whereas wind and photo

voltaic systems will run 40 percent and 27 percent of the

time, respectively. The rates for wind and solar power are

consistent with conditions favorable for their use.17 No

tax credits or other subsidies are included in the

calculations for any technology or fuel source.

The costs per kilowatthour of power for most electricity

generation technologies are at least 70 percent greater than

those for a combinedcycle plant (see Figure 1). The single

exception to that comparison is the combustionturbine

technology in a CHP configuration (its costs are only

5 percent greater), which would be used only by large

customers with significant steam or hot water require

ments. Although the comparisons do not take into

account transmission and distribution costs for utility

supplied power, those would typically add 25 percent to

50 percent. The costs of power from distributed gener

ation would be higher still.

The most costcompetitive distributed generation tech

nologies are fossilfuel engines—diesel motors (internal

combustion engines) and microturbines—in combined

heat and power configurations. The fuel costs of pro

ducing the electricity for those systems, as for all CHP

technologies, are net of the fuel costs of producing the

steam or hot water alone. That calculation implicitly as

sumes that the customer can use the steam or hot water

productively and will incur the cost of producing it even

without the combined heat and power system.

Aside from the CHP systems and both kinds of large

combustion turbines, other distributed generation tech

17. For the wind technology, a usage rate of 40 percent is the high

end of the range of capacity factors cited by the California Energy

Commission in its California Distributed Energy Resource Guide,

which is available at www.energy.ca.gov/distgen/equipment/wind/

performance.html. For the solar photovoltaic technology, a usage

rate of 27 percent corresponds to locations where a onekilowatt

array can produce 6.5 kilowatthours per day, on average. In the

United States, these are places with the highest levels of sun expo

sure, such as Phoenix, Arizona, and Albuquerque, New Mexico.
12 PROSPECTS FOR DISTRIBUTED ELECTRICITY GENERATION

Figure 1.

Levelized Cost of Selected Technologies Suitable for Distributed Generation

Source: Congressional Budget Office using data on electricity prices from Department of Energy, Energy Information Administration, Electric Power Annual 2000

(August 2001), Table 21.

Notes: CHP = combined heat and power (also known as cogeneration); ICE = internal combustion engine; N.E. = New England.

The levelized cost is the average cost of electricity (cents per kilowatt-hour) over the operating life of the generation equipment. Future costs and output

flows are based on data in Table 2 and are discounted at 7 percent from their present values. The cost estimates assume that the systems powered by fossil

fuels will be operated 90 percent of the time and that the wind and solar photovoltaic systems will run 40 percent and 27 percent of the time, respectively.

Levelized cost comparisons do not include the effects of tax credits or other direct subsidies for specific technologies.

“Large wind turbine” is not included in the figure (as it is in Table 2) because it is not generally considered to be well-suited to distributed generation applications

(typically, it is not located near customers).

a. In a combined-cycle system, a combustion turbine is operated in tandem with a steam turbine. The system is included here as a benchmark for the cost of power

from new large-scale generators. Transmission and distribution expenses would add an estimated 2.4 cents per kilowatt-hour, on average, to the marginal cost

of delivered power.

nologies have electricity costs that are more than twice

those of the combinedcycle technology. The combustion

turbines, which utilities themselves often use to meet

certain new consumption needs (loads), would be suitable

only for large commercial or industrial customers. Among

the remaining technologies, conventional engines (those

marked “power only” in Figure 1) are the closest in cost

to the combinedcycle technology. But they are still at least

120 percent more expensive than power from new utility

plants. Advanced highefficiency technologies (micro

turbines and fuel cells) and renewable technologies (small

wind and solar photovoltaic) are even more expensive.

Nonetheless, the costs of some distributed generation

technologies, especially those in combined heat and power

systems, are below the retail price of utilitysupplied elec

tricity in many parts of the United States. For example,

the average price of electricity for all sectors in New

England in 2000 was 9.8 cents per kilowatthour. In the

same year, the average price of electricity in the com

mercial sector in the United States was 7.2 cents per

kilowatthour. The estimated cost per kilowatthour for

a CHP internal combustion engine system (7.1 cents) was

lower than both prices.

 

N.E. Average

U.S. Average

Combined-Cycle Systema

Combustion Turbine--CHP

Combustion Turbine--Power Only

Small Wind Turbine

Solar Photovoltaic

Fuel Cell--CHP

Gas ICE--CHP

Gas ICE--Power Only

Microturbine--CHP

Microturbine--Power Only

0 5 10 15 20 25 30

Cents per Kilowatt-Hour (In 2000 cents)

Price of Electricity
CHAPTER TWO THE CURRENT STATUS OF AND PROSPECTS FOR DISTRIBUTED GENERATION 13

The average price of electricity in the United States greatly

exceeds the cost of power from new generation for at least

two reasons. First, the average price includes the costs of

transmission and distribution, which add approximately

25 percent to 50 percent to the delivered cost of power.

Second, the prices charged by most regulated utilities are

set to recover their past investments, whose costs—espe

cially those for generation—exceed the current costs of

new plants. 

That comparison may explain much about the contrasting

incentives of utilities and customers to invest in distributed

generation. Regulated utilities are concerned about re

taining their sales base in order to recover the costs of past

investments. Customers are concerned about lowering

their electricity costs without sacrificing the reliability of

their utility service connection.

Trends in Costs 

The capital and operating costs of certain distributed

generation technologies have fallen significantly in recent

years and can be expected to continue to do so. In the case

of one technology, photovoltaic systems, the cost per

delivered kilowatthour in suitable applications has plum

meted by almost 70 percent since 1980, and it is projected

to decline by another 70 percent from current levels by

2020 (see Figure 2).18

Similarly, developers forecast that fuel cells will improve

in performance and decline in cost over the next several

years to the point that they will soon be suitable for

widespread use in distributed generation. A recent study

by Lawrence Berkeley National Laboratory projected that

the installed cost per kilowatt for a 200kilowatt fuel cell

would drop from $3,500 in 2000 to $1,300 (in 2000

dollars) by 2010.19 That projection, and similar ones from

other sources, are based on “target forecasts for installed

Figure 2.

Levelized Cost of Solar Photovoltaic

Electricity, 1980 to 2020

(Cents per kilowatt-hour)

Source: Congressional Budget Office based on data from Department of

Energy, Office of Energy Efficiency and Renewable Energy, and Electric

Power Research Institute, Renewable Energy Technology Characterizations, EPRI-TR-109496 (December 1997).

costs from developers of [advanced technology] solid oxide

and molten carbonate fuel cell systems.”20

Whether the direct costs of distributed generation will

continue to fall relative to the costs of utilitysupplied

power is another matter. Electricity prices have generally

dropped as a result of competition—although California’s

experience of high prices and rolling blackouts in 2000

and 2001 is a notable exception—and are likely to benefit

from further market restructuring in coming years. Tech

nical improvements in largecapacity generation technol

ogies used by utilities are also likely to lower the costs of

supplying power. The EIA projects in its reference case

forecast, however, that the average price of electricity in

the United States will remain virtually constant over the

next two decades, indicating at least in that case that

neither competition nor costsaving technical change is

18. Department of Energy, Office of Energy Efficiency and Renewable

Energy, and Electric Power Research Institute, Renewable Energy

Technology Characterizations.

19. Consortium for Electric Reliability Technology Solutions,

Modeling of Customer Adoption of Distributed Energy Resources,

LBNL49582 (August 2001), Tables 1 and 2.

20. Department of Energy, Energy Information Administration, The

Market and Technical Potential for Combined Heat and Power in

the Commercial/Institutional Sector, p. 24.

1980 1985 1990 2000 2007 2010 2015 2020

0

20

40

60

80

100

Actual Projected
14 PROSPECTS FOR DISTRIBUTED ELECTRICITY GENERATION

likely to have much effect on the economics of utility

supplied power.

Other Economic Considerations in

Installing Distributed Generators

Although a comparison of typical costs for various dis

tributed generation technologies can be useful, it tends

to obscure several important facts. Distributed power can

differ qualitatively from central power or can save money

in other ways, and that value may outweigh any direct

cost difference. Moreover, certain distributed generation

technologies or energy sources can benefit from existing

federal and state incentives (including investment tax

credits or mandates on utilities to purchase power gener

ated from renewable sources).

The significance of those quality and cost advantages is

demonstrated by the fact that distributed generation

applications are already widely available in several niche

markets. Commercial and small industrial customers

with significant hotwater needs can use microturbines

in combined heat and power configurations. Customers

who have onsite emergency backup generators may be

able to run them regularly during periods of peak de

mand, when wholesale prices are high. Customers in en

vironmentally sensitive areas can use fuel cells that

produce extremely low emissions and no noise. Photo

voltaic systems and wind turbines can be used in rural ap

plications, reducing the need for capital spending to ex

tend power lines to remote sites.

Distributed generation can also protect against service

interruptions or variations in voltage or frequency that

can harm equipment. The majority of those interruptions

are due to equipment failures or power line breaks close

to customers’ premises. The value of improved reliability

is difficult to quantify; it depends largely on the reliability

of the regular electricity supply.21 Local building ordi

nances and safety concerns dictate most of the backup

power needs in the nation—for example, for hospitals

and highrise buildings. But the value of backup capabil

ity would also be great wherever a manufacturing process

depended on the continuous operation of powersensitive

equipment, such as in the production of computer chips.

Generally, those backup units would be available to oper

ate whenever interruptions occurred in utilitysupplied

power. During California’s recent electricity crisis, many

businesses in that state purchased (or rented) diesel units

just to ensure continuity of operations.

Besides possibly saving on their own electricity costs (as

output from distributed generators displaced utility

supplied power provided at retail rates), some owners of

distributed generators might be able to earn money by

selling their excess power to the utilities. Federal law re

quires utilities to purchase power from cogeneration

facilities and generators powered by renewable fuels at

prices reflecting the utility’s own longrun marginal costs

of supply. And many states require utilities to give credit

at retail rates for excess power from certain small dis

tributed generators (termed net metering). But those

requirements are often limited to generators that use

renewable fuels or highefficiency technologies. Initiatives

to broaden the sale of excess power by operators of dis

tributed generators to regional wholesale spot markets at

prices that varied hourly (realtime pricing) could benefit

the operators while increasing the available power supply.

Businesses and households that are considering investing

in distributed power may also benefit from other pro

grams that the federal government and many states have

developed. At the federal level, the Energy Policy Act of

1992 provides tax credits for certain investments in solar,

wind, and biomassfueled electricity generation. At the

state level, renewable portfolio standards mandate that a

certain percentage of electricity generation come from

renewable energy sources. Several states, including New

York and California, have adopted such renewable port

folio requirements. Many states also offer tax credits for

investment in certain renewable technologies. For exam

ple, the 10 percent corporate tax credit for investment in

solar, wind, and biomass technologies that is offered in

Texas is typical.22

21. Service quality refers to the stability of the voltage and frequency

at which electricity is delivered. Reliability refers to the frequency

and duration of service interruptions.

22. See the Database of State Incentives for Renewable Energy’s Web

site (www.dsireusa.org/dsire/), funded by DOE’s Office of Power

Technologies, for a complete summary of federal, state, local, and

utility programs that promote renewable energy. 
3

The Benefits and Risks of

Distributed Generation

In combination, falling costs, concerns about the reli

ability of utilitysupplied power, and opportunities asso

ciated with electricity market restructuring have stimulated

interest in using distributed generation technologies

differently in the future from how they are typically used

today. Rather than supplying emergency backup or ex

ploiting only the largestscale combined heat and power

projects, small customerowned generators could run

regularly as a complement to utilitysupplied power. 

That new role could be filled in a number of ways, de

pending on the utility tariff, the technology used to gen

erate electricity, and customers’ power needs.1

 For exam

ple, with a utility tariff under which retail prices varied

between onpeak and offpeak periods of demand (called

a timeofuse tariff), operators of distributed generators

could provide power during periods of peak demand

when prices were high but rely on electricity from the

grid to meet their “base load” (basic power) needs. Al

ternatively, under a nontimeofuse tariff, operators

could run their distributed generators continuously to

supply base loads and rely on gridsupplied power to

meet peak needs. Or, in a third configuration, wind or

solarpowered systems could generate power intermit

tently, with operators buying supplemental power from

the grid when onsite production was low and selling ex

cess power over the grid when production exceeded on

site loads. Each of those new ways of integrating distrib

uted generation and utility operations shares the features

that the generator would operate regularly and would pri

marily serve the customer’s own load, running in parallel

(that is, while interconnected) with regular service to and

from the grid. 

Distributed generation, operated as a complement to tra

ditionally supplied power, may offer significant benefits.

It could lower the nation’s overall costs of producing and

delivering power. It could also promote the development

and use of renewable energy sources and fuelefficient

technologies, which could improve the quality of the air

and the security of the nation’s energy supply.

Initiatives to realize those broader benefits entail risks,

however. If rules and incentives intended to encourage

the costeffective installation and operation of distributed

generation are poorly designed, they may raise the total

costs of producing and delivering power. Depending on

the outcome of the ongoing restructuring of electricity

markets and other developments, such as the course of

technological innovation, the potential economic benefits

of distributed generation may diminish. There is also a

significant likelihood that, among the several distributed

generation technologies, systems fueled by fossil energy

will dominate because they cost less than renewable tech

nologies in most situations. In that case, the environmen

tal benefits that some proponents of distributed power

expect may not be realized.

1. A utility tariff is a schedule of prices for electricity, which may

include such components as a minimum or fixed monthly fee for

service, different prices per kilowatthour for electricity consumed

in defined periods and quantity ranges, and a price per kilowatt

for the maximum consumption (termed a demand charge) during

a short (for example, 15minute) interval per billing period. 

CHAPTER
16 PROSPECTS FOR DISTRIBUTED ELECTRICITY GENERATION

Potential Savings in the Production

and Delivery of Electricity

Systemwide cost savings may be possible if the ability to

generate their own electricity leads retail customers to

reduce their demand for utilitysupplied power when

wholesale electricity costs are high. The savings could

result from the substitution of lowcost generating tech

nologies for highercost ones and the avoidance of some

costs associated with transmission and distribution.

Lower Costs of Generation

Whenever homes and businesses produce electricity on

their own, utilities avoid the costs of purchasing or directly

producing that electricity for those customers but lose the

revenues from those sales. Under current costofservice

regulations, any net savings or losses are typically passed

on to all the utilities’ customers through lower or higher

retail prices. Thus, if customers can be induced to install

and run distributed generators when their operating costs

are lower than the utilities’ wholesale costs, the retail price

of electricity will fall for all customers. 

Systemwide savings may be enhanced if the generation

of electricity for customers’ own use is flexible—the gen

erator can increase output at certain times of the day or

in certain seasons, when the demand from all customers

for utilitysupplied power is greatest. Additional savings

will result because utilities generally operate their most

expensive power plants during those peak periods. The

unit costs of electricity production increase as utilities

successively call on baseload generators, “peaking” gen

erators, and older units, as well as push the utilization of

all units to high levels. Because they can be switched on

and off easily, distributed generators powered by internal

combustion engines are most likely to help “shave” the

peak and allow utilities to avoid using generators with very

high marginal costs (the costs of supplying an additional

unit of electricity). 

Avoided Investment and Operating Losses in

Transmission and Distribution

Distributed generation can reduce the need for sometimes

significant investment in transmission and distribution

lines and equipment to meet growing loads or to relieve

congestion at certain points in the electric system. The

costs of those investments can add significantly to the

price of power delivered by utilities to retail customers.

For example, in regions where transportation charges are

broken out from the charges for the electric power itself,

the average charge for transmitting and distributing the

electricity (2.4 cents per kilowatthour) is more than 30

percent of the average price of delivered electricity (7.9

cents per kilowatthour).2

 

Retail electric utilities as well as their customers could use

distributed generators to avoid or defer investments at the

local level. For example, to meet seasonally high demand,

a utility could install a smallcapacity generator at a site

on the distribution portion of its network instead of

investing in increased capacity of “upstream” power lines

and transformers. Utilities have recognized that small gen

erators can be used to relieve periodic local congestion in

the subtransmission and distribution portions of the

electricity network. Such use can be a costeffective alter

native to investment in additional transformer capacity

and other distribution infrastructure—often delaying the

need for such upgrades. 

In other cases, local utilities may want to install and op

erate distributed generators because building new trans

mission capacity raises environmental concerns. That use

of distributed generation could prove especially valuable

in places where opposition from environmental groups

was constraining or delaying the construction of additional

transmission capacity. 

Wider adoption of distributed generation also would

reduce power losses from the transmission and distribution

of electricity between central power plants and customers.

Those losses result from electrical resistance in the trans

mission and distribution system and from changes in

voltage as the power approaches the point of consumption.

The Energy Information Administration estimates that

transmission and distribution losses in the United States

averaged almost 7 percent of gross production (in gen

2. Department of Energy, Energy Information Administration,

Electric Sales and Revenue 2000, DOE/EIA0540(00) (January

2002), Table C1, p. 256.
CHAPTER THREE THE BENEFITS AND RISKS OF DISTRIBUTED GENERATION 17

erated kilowatthours) in 1999.3 During hot weather

(which is typical of summer peak periods), power lines

stretch and conductivity diminishes, causing losses that

can exceed 15 percent.

Additional Savings from Incentives 

for Adjusting Demand

Distributed generation gives customers an alternative to

traditional utilitysupplied electricity. Customers could

use that onsite power source to increase the reliability of

their electricity supply. That use could bolster economic

efficiency because only customers who required increased

reliability would have to pay for it. Customers could also

generate their own power to help offset the impact of high

electricity prices. More generally, that approach would

provide a means by which retail customers and utilities

could curtail their demand for power in regional electricity

markets and possibly avert disruptions and price spikes.

Even moderate changes in demand and supply, net of cus

tomerowned generation, could significantly lower elec

tricity prices in regional spot markets during periods of

peak demand.

Improved Reliability of Service

Under the current supply system for electric power, utility

distribution companies largely determine the basic level

of service reliability for all customers in a given area. Util

ity planners typically establish a reliability target for their

power generation and distribution network. They design

and build the network with capacity margins and redun

dancies to meet that target, given estimated probabilities

of failures and of capacity deficits for each component of

the system. As a result, most customers receive electricity

service with a similar reliability level, and the cost of that

reliability is typically borne by all customers through their

general charges. A customer not wanting that level of reli

ability cannot avoid its cost. If a customer needs a higher

level of reliability, the utility can provide it only at a cost

that is imposed on all customers.

Distributed generation offers an alternative solution.

Customers who need highly reliable power can install dis

tributed generators, allowing them to obtain unin

terrupted service without imposing their requirements

and associated costs on other customers. In California,

for example, where customers have historically had an

average of fewer than two significant outages per year

(defined as outages of at least five minutes’ duration, as

measured by the system average interruption frequency

index), there are more than 4,000 backup generators larger

than 300 kilowatts (approximately equivalent to a 450

horsepower motor).4

 That 300kilowatt capacity is large

enough to supply most large commercial and medium

sized industrial customers.

The potential for using distributed generation to meet

reliability needs could be enhanced through measures that

permitted nonemergency operation of the units. Such an

approach would allow owners to operate their generators

when it was costeffective and to reduce the net cost of

reliable service.

Reductions in the Volatility of Wholesale Prices

The limited incentive for retail electricity customers to

reduce consumption when wholesale prices rise contributes

to the volatility of wholesale electricity prices. If retail cus

tomers had the capability to adjust their net demand for

utilitysupplied power through distributed generation and

had the necessary incentives to do so through timevarying

tariffs, such as realtime pricing or timeofuse tariffs, then

wholesale prices would be less volatile and lower, on

average.5

 In particular, wider use of distributed generation

would tend to reduce the size and frequency of extreme

shortterm price spikes.

Several benefits would flow from the type of diminished

price volatility that distributed generators would provide.

In the short run, less price volatility would reduce the risk

of increases in retail utilities’ power costs that could

jeopardize their financial viability. That situation arose

3. Department of Energy, Energy Information Administration, An

nual Energy Review 2000 (August 2001), Table 8.1.

4. Those numbers do not include mobile generators. See California

Energy Commission, Database of Public BackUp Generators

(BUGS) in California, available at www.energy.ca.gov/database.

5. Distributed generation is only one means by which customers

could adjust their demand for utilitysupplied power. Another is

a demandmanagement program that provides incentives to cus

tomers to reduce consumption during critical periods.
18 PROSPECTS FOR DISTRIBUTED ELECTRICITY GENERATION

in the California electricity crisis of 2000 to 2001, when

large wholesale price increases forced one utility into bank

ruptcy.6

 In the long run, reduced volatility would encour

age independent (nonutility) generators to accept lower

prices in longterm contracts by eliminating opportunities

for them to gain “windfall” profits by selling electricity

in the shortterm spot market.

Spot market prices in wholesale electricity markets are

highly volatile. During a typical summer week, the av

erage hourly price of electricity in the PJM spot market

may vary from as little as zero to more than $100 per

megawatthour.7

 For example, the zoneweighted average

hourly spot price for the week of August 5, 2002, ranged

from zero to $96 per megawatthour, with an average

price of $27.30 per megawatthour (see Figure 3).

Even those hourly prices understate the volatility of

wholesale electricity prices because they are averages of

values at different delivery points on the transmission

system. Prices at individual delivery points deviate from

the system average because of congestion in specific por

tions of the system during periods of heavy transmission.

Such congestion forces the system operator to run more

expensive generators in other locations. The differences

in the costs of the generation with and without the trans

mission constraint are captured in the price differentials

across delivery points. For example, on Monday, Aug

ust 5, 2002, when the peak average price was $96 per

megawatthour, the price at several delivery points was

$650 per megawatthour.8

Figure 3.

Volatility in the Spot Price 

of Electricity

(Dollars per megawatt-hour)

Source: Congressional Budget Office based on data from the PJM Independent

System Operator.

Notes: The figure shows the PJM zone-weighted hourly spot price of electricity

over the week of August 5, 2002. PJM is the organization responsible

for wholesale power sales and transmission in major portions of five

mid-Atlantic states and the District of Columbia. The data are available

at www.pjm.com.

 Hourly prices can fall as low as zero because some generators that must

run continuously, such as nuclear plants, offer to supply electricity regardless of the price. During some hours, those generators’ output may

exceed the total demand, resulting in a clearing price of zero.

During periods of peak demand, even modest changes

in the demand for and supply of wholesale power could

significantly reduce electricity prices in regional spot

markets. For example, one study estimated that a 5 per

cent reduction in peak demand in California during

2000 would have lowered wholesale spot prices by more

than 50 percent.9

 Another study of emergency demand

6. See Congressional Budget Office, Causes and Lessons of the

California Electricity Crisis (September 2001), for a detailed dis

cussion of that state’s experience.

7. The PJM Independent System Operator is responsible for

wholesale power sales and transmission in major portions of five

midAtlantic states and the District of Columbia.

8. The delivery points that experience extreme prices tend to have

deficient transmission capacity, which creates chronic congestion.

The high prices provide incentives for investment in additional

generation and transmission infrastructure sited in locations that

might relieve the congestion. 

9. Eric Hirst and Brendan Kirby, RetailLoad Participation in Com

petitive Wholesale Electricity Markets (report prepared for Edison

Electric Institute and Project for Sustainable FERC [Federal Ener

gy Regulatory Commission] Energy Policy, January 2001), p. 5.

1 24 47 70 93 116 139 162

0

20

40

60

80

100

Hour
CHAPTER THREE THE BENEFITS AND RISKS OF DISTRIBUTED GENERATION 19

response in New York during critical periods in 2001

found that a demand reduction of as little as 400 mega

watts (1.3 percent of annual peak demand) lowered

wholesale prices by 28 percent in certain areas.10

 The

widespread adoption of distributed generation could pro

vide an important means for realizing those types of

reductions.

Any diminishment in price volatility of the type that dis

tributed generators are likely to produce can yield savings

for customers as a group. The reason is that the beneficial

operation of distributed generators will tend to reduce

prices in longterm contracts for electricity. By operating

during periods of extreme price increases, distributed

generators would tend to reduce the frequency and du

ration of those price spikes. Investors in new independent

power plants would be more inclined to enter into long

term contracts at lower prices because their opportunity

to earn large profits in the spot market would be dimin

ished significantly. Any savings on longterm prices would,

under costofservice regulations or with retail compe

tition, be passed on to retail customers.

Potential Benefits for the Environment and National Security

Many environmental and energyconservation advocates

believe that distributed generation could offer significant

benefits—ones that are not fully reflected in the value of

that electricity to the market. Benefits for environmental

quality may come from distributed generation’s role in

promoting renewable energy sources, lesspolluting forms

of fossil energy, and highefficiency technologies. Security

benefits may come from increasing the geographic dis

persion of the nation’s electricity infrastructure and from

reducing its vulnerability to terrorist attacks that could

interrupt electricity service over large areas.

Distributed generation technologies that relied on re

newable energy sources could yield environmental benefits

in the form of reduced emissions of pollutants and green

house gases if those technologies displaced utilitysupplied

power, much of which is generated from coal. Tech

nologies that relied on conventional fuels would yield

environmental benefits if they resulted in a shift to less

polluting energy sources—for example, natural gas rather

than coal. Highefficiency technologies could yield benefits

by reducing the amount of energy required to produce

a unit of electricity.

Security benefits of distributed generation relate to the

current vulnerability of the nation’s electricity infra

structure to terrorist attacks. Most of the nation’s elec

tricity comes from large central generation plants and

moves over an extensive network of transmission lines,

which would be difficult to defend against a physical

attack. The operation of that system relies on telecommu

nications and computers to relay instructions to dispatch

generating units and route power supplies. Those controls

are increasingly tied to the online operation of regional

wholesale markets that balance supply and demand and

set prices. If more of the nation’s electricity supply orig

inated in the homes and businesses where it was con

sumed, the adverse consequences of any attack that dis

rupted the network would be diminished.

Uncertainties and Risks

The prospects for widespread adoption of distributed

generation technologies are not at all certain. Nor is it

clear that those technologies will be used in ways that

achieve their full potential economic benefits. Moreover,

this new source of electricity poses a distinct risk of neg

ative impacts that may be difficult to anticipate or ex

pensive to avoid. Those effects include potential degrada

tion in the performance of the electricity distribution

network, inequitable and possibly inefficient redistribu

tion of the costs of electricity service among customers,

and a decline in environmental quality. Measures to mit

igate those adverse impacts could significantly limit the

adoption of distributed generation or increase costs to the

point at which most applications would no longer be

financially viable. In fact, many such restrictions on the

use of distributed generators have been imposed and are

discussed in the next chapter.

Uncertainty Related to Market Restructuring

The likelihood of achieving the potential benefits from

widespread adoption and efficient use of distributed gen

10. Neenan Associates, “Executive Summary,” NYISO [New York

Independent System Operator] PriceResponsive Load Program

Evaluation Final Report (January 2002).
20 PROSPECTS FOR DISTRIBUTED ELECTRICITY GENERATION

eration technologies is closely related to the continued re

structuring of the electric power industry. If competitive

wholesale markets for electricity develop with nondis

criminatory access and hourly prices determined by sup

ply and demand, those markets will give operators of dis

tributed generators an incentive to run their units when

such operation will reduce the overall cost of supplying

electricity. But if wholesale markets do not develop effi

ciently—for example, because of restricted access or reg

ulated prices—the benefits of distributed generation may

not be fully realized. 

The restructuring of retail electricity markets could also

affect the prospects for distributed generation. If state

regulators “unbundled” electricity generation from other

services (such as transmission and distribution) and

introduced competition in the generation portion of the

market, then suppliers would be pressured to make their

pricing consistent with the pricing in wholesale markets.

That development would accelerate the introduction of

realtime pricing and other electricity rate offerings that

promoted flexible demand, providing additional incen

tives to operators of distributed generators to run their

units efficiently. But if regulators constrained retail com

petition by restricting price flexibility or by imposing

surcharges on customers who adopted distributed gener

ation, then the technology might not achieve its full mar

ket potential and operational benefits. 

Finally, the restructuring of wholesale and retail markets

could reduce the attractiveness of distributed generation

to many customers. (See the appendix for a discussion

of restructuring and its effect on prices.) If electricity

prices fell because of greater competition and initiatives

to increase demand flexibility at the retail level, that

decline could diminish the value of existing distributed

generator systems and reduce the profitability of new

ones.

Uncertainty About Market Potential

Besides uncertainty related to market restructuring, other

types of uncertainty will affect the potential growth of

distributed generation applications. Such uncertainty in

cludes the actual costs of installing and operating distrib

uted generation technologies relative to central power

technologies, the actual value to individual customers of

improvements in reliability of service, and variations in

the financial benefits for individual customers, which are

difficult to capture in an overall analysis such as this one.

The costs of the various distributed technologies them

selves are uncertain. The two most widely mentioned

highefficiency technologies—microturbines and fuel

cells—either are not yet commercially available or are in

the early stages of commercialization.11 Although their

proponents predict that installed equipment costs will

decline substantially in the future as commercial produc

tion increases, such an outcome cannot be known in ad

vance. Other technologies—such as photovoltaic systems

—have been in commercial production for some time,

but proponents still forecast that their costs will fall con

siderably as manufacturing processes continue to im

prove and production increases. 

A second uncertainty surrounding the market potential

of distributed generation concerns the benefits from

improved reliability of service, which are often difficult

to value. The main appeal of distributed generation for

many customers in the current regulatory environment

is that its use can avoid or minimize the effects of elec

tricity service interruptions. Onsite generation is often

used in hospitals, where interruptions in electric service

could endanger patients, and in hightechnology compa

nies, where power interruptions could damage sensitive

equipment, cause losses of important computer data, or

spoil manufacturing processes. Many of those costs are

hard to quantify. 

Finally, the financial benefits that customers will weigh

to decide whether to invest in and operate distributed

generators are much more diverse that those summarized

here. Conditions will vary widely from customer to cus

tomer—depending on such factors as the customer’s

economic activity, size, location, and load profile—and

many technologies will not prove suitable. For example,

a large commercial customer with significant air condi

tioning needs and hotwater requirements, facing a time

ofday tariff with high rates during peak periods, might

find it economically beneficial to install a distributed

generator to serve part of those needs at peak times while

11. The fuel cell technologies with the greatest potential to reduce costs

are not yet commercially available.
CHAPTER THREE THE BENEFITS AND RISKS OF DISTRIBUTED GENERATION 21

producing hot water as a byproduct. In contrast, for

smaller customers with a flatrate tariff, the cost to install

and operate distributed generation equipment would

make it economically unattractive.

Threats to the Performance of Electric Systems

Without adequate upgrades to the electricity supply net

work, widespread adoption of distributed generation

could adversely affect regional electricity distribution sys

tems. For example, with many customers switching their

generators on and off, the quality of the power and the

reliability of the systems could be degraded. Moreover,

because utilities could have difficulty pinpointing the

sources of the degradation, they might not be able to al

locate to the owners of distributed generators the costs

of preventive actions. 

It may be difficult to develop economically sound poli

cies on how to pay for any required upgrades in the util

ity infrastructure to protect against those risks. Experts

generally agree that the current risks to the distribution

system from the parallel operation of small generators,

representing only a small fraction of a local distribution

network’s capacity, are usually manageable.12

 But the cu

mulative effects of many generators would be another

matter. The utility network might require significant up

grades and additional protective devices to manage dis

tributed generators that could use a large fraction of the

local distribution network’s capacity. 

Traditionally, many utility commissions have adopted

a “userpays” policy under which the interconnection ap

plicant bears the costs of any network upgrades to pre

vent potential problems. That policy favors early connec

tors, who can take advantage of excess network capacity;

later connectors are at a disadvantage because they must

pay for necessary upgrades. Advocates argue that credits

for interconnection charges should be given for distrib

uted generation because its use defers investment in

transmission and distribution networks. But the deferrals

are difficult to quantify and extremely variable from case

to case, so it would be hard to craft a set of clear rules for

such credits. A policy under which costs were recovered

through higher transmission and distribution rates for

all customers would conflict with the userpays policy,

which many regulators have adopted on the basis of

equity considerations. Moreover, independent generators

would have no incentive to locate plants where they

would minimize the need for infrastructure upgrades,

because the generators would not bear the costs of the

upgrades.

Difficulties in Recovering Utility Costs and

Paying for Public Benefit Programs

Distributed generation effectively allows customers to by

pass utilitysupplied power, avoiding various surcharges

that are not related to the current cost of production—

for example, charges to recover past utility investments

(socalled embedded costs) that have proven uneconomic

and charges to fund energyefficiency programs or subsi

dies to small or lowincome users. Increased adoption of

distributed generation would limit the ability of regula

tors to use their ratemaking authority to distribute those

costs according to equity considerations. It would also

impose the burden of paying for embedded costs on cus

tomers who depended most on utilitysupplied power.

Historically, state regulators have allowed utilities to set

retail prices to recover the actual costs of investments that

were deemed prudent and necessary to the provision of

electricity, even when subsequent developments made

some of those investments uneconomic. For example, in

the 1980s, when wholesale electricity prices plummeted,

utilities set rates that allowed them to recover the costs

of their existing highpriced longterm contracts to se

cure electricity. State regulators have also frequently used

the ratemaking process to achieve certain equity objec

tives. For example, “baseline” rates are intended to pro

vide a basic level of electricity service at a belowaverage

cost. Regulators often include charges in general tariffs

12. For example, FERC’s recent “Advance Notice of Proposed Rule

making on Standardization of Small Generator Interconnection

Agreements and Procedures” (Docket No. RM0212000, Aug

ust 16, 2002) stated that “[a] presumption of ‘no impact’ will nor

mally be made if the following conditions are met: (1) the project’s

export of electricity (net of onsite load) would not exceed, cumu

latively with all prior small resources on the system, (a) 15 percent

of the peak load on a radial feeder or (b) 25 percent of the mini

mum load on a network link, and (2) the project’s capability does

not exceed 25 percent of the maximum short circuit potential.”
22 PROSPECTS FOR DISTRIBUTED ELECTRICITY GENERATION

to cover the costs of energyconservation or lowincome

assistance programs.13

Distributed generation could provide customers with a

means to circumvent part of those costs. For example,

under tariffs that increase as consumption rises (boosting

the cost per kilowatthour), a customer could use distrib

uted generation to avoid buying electricity at the higher

prices. The financial attractiveness of investment in dis

tributed generators would probably diminish if utilities

were allowed to assess distributed generation customers

for such costs.

Risks to Air Quality and National Security

The distributed generation technologies with the greatest

market potential are probably those fueled by fossil

energy (backup generators powered by diesel fuel and

cogenerators powered by natural gas), not renewable

energy. The potential for customerowned wind and solar

power will probably continue to be realized only in

limited circumstances, unless the capital costs of those

technologies fall considerably. Highefficiency micro

turbine and fuel cell technologies are still at the earliest

stages of commercialization, so their potential is largely

unknown. Thus, the immediate promise of improved air

quality from wider adoption of distributed generation

may be limited, and improvements would probably

come primarily from substituting natural gas and diesel

fired generators for coalfired generators. On the down

side, those new generators might end up displacing

power from units that were already fired by natural gas.

And if some generators switched from relatively clean

burning natural gas to diesel, local air quality could

worsen.

Another risk is that widespread adoption of gasfired

distributed generators could necessitate construction of

additional pipeline capacity. The EIA’s Reference Case

MidTerm Energy Forecast projects that electricity gen

erated from natural gas will climb from 17 percent in

2001 to 29 percent in 2025. If that increase largely takes

the form of distributed generation near growing popula

tion centers, additional pipeline capacity will be needed

to supply those generators. Any savings in investments

in electricity transmission and distribution networks

would be partially offset by the need for investments in

new natural gas pipelines.

Other adverse (or at least costly to control) effects also

could result. They might include damage from uncon

ventional forms of pollution such as waste heat and noise

—problems that have been associated with dieselpow

ered backup generators and cogeneration plants sited in

urban settings. Even windmills have environmental

drawbacks, including detracting from the aesthetics of

the landscape. Such impacts might not be easy to antici

pate or be readily apparent for a small number of units,

but the cumulative effect of many dispersed generators

could be significant. In geographic areas with strict emis

sions standards, it would be necessary to inspect distrib

uted generators regularly to monitor their compliance

with those standards. Under the scenario of widespread

use of smallscale generators envisioned by proponents,

the cost of that monitoring could be steep.

13. For example, Pacific Gas and Electric Company’s residential tariff

includes a charge for “Public Purpose Programs” of 0.4 cents per

kilowatthour.
4

Barriers That Impede Widespread

Adoption of Distributed Generation

A dvocates of distributed generation contend that

many industry practices and government restrictions dis

courage investment in and beneficial operation of cus

tomerowned generators that could, without adverse ef

fects, lower the costs of electricity for all customers. Op

ponents argue that such practices and restrictions are

necessary to protect utilities and general ratepayers from

increased costs, to maintain the reliability of the electric

system, and to protect the environment. Four areas of

contention are frequently mentioned:

# Requirements and charges for the installation of pro

tective equipment as a precondition to interconnec

tion with the grid;

# Surcharges on the electricity bills of operators of dis

tributed generators (those who remain utility cus

tomers);

# Prices established for the distributed power that util

ities purchase; and

# Environmental siting restrictions and permitting re

quirements.

Proponents of wider adoption say that wellcrafted re

forms in those areas would benefit not only customers

who adopted distributed generation but also electricity

customers as a group. Critics argue that such reforms

would shift the burden of paying for the fixed costs of

the electricity supply network from owners of distributed

generation to other ratepayers. Distributed generators

would continue to benefit from the network—as a source

of supplemental power, for example—without paying

their fair share of those fixed costs. 

Protecting the Grid: Interconnection

Requirements and Costs

The most commonly cited category of industry practices

that proponents of distributed generation claim presents

a barrier to adoption comprises the technical restrictions,

contractual requirements, and associated costs for con

necting customerowned generators to the grid. Pro

ponents claim that, for many types of distributed gen

eration, the requirements are often excessive and time

consuming, resulting in additional unwarranted costs

and significant project delays.

The stated purpose of the technical interconnection re

strictions and requirements is to ensure the safety and

quality of the electric power system and to avoid possible

damage to equipment. Those restrictions often prohibit

small generators from connecting to the grid at the dis

tribution level of the network. For example, under

existing rules in some utilities’ service territories, custom

ers with onsite generation must disconnect completely

from the grid before starting their generators, to protect

against accidental transmission of power onto the grid or

possible voltage and frequency disturbances from the new

power. 

In the absence of outright prohibitions, however, opera

tors of distributed generation units may want to remain

CHAPTER
24 PROSPECTS FOR DISTRIBUTED ELECTRICITY GENERATION

connected to the grid while producing power (termed

parallel operation)—whether to draw supplemental pow

er from the grid or to transmit excess power onto it. In

that case, utilities generally require operators to install

additional controls and equipment in order to protect the

network from feedbacks or disturbances. That additional

sitespecific equipment may include voltage regulators,

frequency synchronizers, isolation devices, monitoring

devices, and network protectors. Because the number and

types of devices that utilities require vary widely and de

pend on many factors, utilities often demand specialized

studies—typically paid for by the operator—to determine

the equipment necessary in each case. Utilities may also

require upgrades to the distribution system itself to sup

port the power supplied by the distributed generators and

to protect neighboring customers from disruptions or

variations in power quality. Operators typically bear the

cost of such sitespecific equipment and any system up

grades, too.

In general, utilities require that operators of distributed

generators execute contracts governing the interconnec

tion of their equipment with the distribution and trans

mission network. Distributed generation proponents

complain that provisions in those contracts are often one

sided or overly burdensome. They include insurance re

quirements that may boost operators’ costs significantly

and indemnification and disputeresolution provisions

that proponents say unfairly favor the utilities.

Many observers argue that those technical and contrac

tual interconnection requirements are often excessive. For

example, the electronic control equipment built into

most small generators effectively protects against electric

ity feedbacks and other technical problems, so industry

requirements for additional equipment are often redun

dant. A recent study from the National Renewable En

ergy Laboratory (NREL) documented several cases in

which utilities insisted on separate equipment when gen

erators already had such protection.1

 Similarly, special

ized interconnection studies may be unnecessary for

broad classes of generating equipment and operating

conditions. Such studies not only add costs but also can

delay the startup of distributed generation projects. For

the operators of smallscale distributed generators—

especially in residential or small commercial settings—

those costs can represent a sizable part of the total cost of

interconnecting with the grid, and in many cases they are

steep enough to jeopardize the economic viability of us

ing distributed generation in those applications.

The NREL study documented numerous instances in

which developers of distributed generation projects faced

interconnection costs that they viewed as “above nor

mal.” In 12 out of 42 projects, developers cited excessive

technical costs. Another six projects were abandoned be

cause of barriers. The “above normal” costs ranged from

$20 per kilowatt to more than $1,000 per kilowatt.

Smaller projects tended to face higher perkilowatt inter

connection costs because some of those charges do not

vary depending on the size of the generator. 

Utility Surcharges: Paying for Stranded

Costs and Standby Service 

Under the electric utility regulations in most states, util

ities may levy surcharges on customers who install dis

tributed generators and operate them regularly. Typi

cally, the surcharges take the form of flat monthly

charges based on customers’ past maximum usage.

Monthly charges may be used to help utilities cover the

costs of public benefits programs (such as purchasing

renewable power or providing service to remote custom

ers). Regulators in every state require utilities to conduct

such programs, which are otherwise financed by electricity

sales. More commonly, however, monthly charges are used

to pay for past capital investments and for standby service.

Helping utilities recover some portion of their past cap

ital investments is part of the purpose behind those

monthly charges. Normally, a utility makes a capital in

vestment (for example, to build a new generation plant)

and then sets electricity rates at a level that will ensure

recovery of those costs over time. But if electricity sales

are lower than the utility expected—perhaps because

rules change to allow some customers to generate power

themselves—the utility’s rates will not be sufficient to

1. Department of Energy, National Renewable Energy Laboratory,

Making Connections: Case Studies of Interconnection Barriers and

Their Impact on Distributed Power Projects, NREL/SR20028053

(May 2000).
CHAPTER FOUR BARRIERS THAT IMPEDE WIDESPREAD ADOPTION OF DISTRIBUTED GENERATION 25

pay off the investment. Revenues from socalled exit fees

(surcharges imposed on customers who shift from full

service to backup service) can help make up that deficit.

Proponents of distributed power argue that the unrecov

erable (or “stranded”) costs covered by exit fees often do

not reflect the actual costs of past investments, which

have become uneconomic with the drop in customer

demand.2

The more common purpose of the recurring monthly

charge that some utilities impose on operators of distrib

uted generators is to pay the utility’s cost of maintaining

standby generating capacity and distribution lines to

serve that household or business. As retail utility custom

ers, operators are able to purchase electricity whenever

their onsite generators experience an outage (for what

ever reason), and the utility must provide service to

them. For example, Pacific Gas and Electric Company

charges $2.55 per kilowatt per month for standby service

to customers “who require PG&E to provide reserve

capacity and stand ready at all times to supply electricity

on an irregular or noncontinuous basis.”3

 If those sur

charges exceed the cost to the utility of providing standby

service, they will discourage the efficient siting of distrib

uted generators.

For nonresidential customers, the charge for standby ser

vice is often based on the maximum amount of electric

ity that the business draws from the grid in a short in

terval, such as 15 minutes. That maximum is often de

termined by the customer’s past consumption. If a cus

tomer had drawn electricity at a maximum rate of 50

kilowatts for 15 minutes in the past three years, for

instance, then that kilowatt level would be used to set the

monthly charge. The utility would charge, say, $2 per

month per kilowatt, or a total of $100 per month, for

that customer’s standby service. For a typical customer,

the charge would amount to roughly onehalf cent per

kilowatthour.

Proponents of distributed generation argue that standby

charges often overstate the cost of the service provided by

the retail utility and fail to account for the benefits that

distributed generators provide to the system. Because the

probability of broad unscheduled outages by distributed

generators is slight, the extra capacity needed to serve

those customers is only a small fraction of the standby

service (the maximum potential draw on the system) for

which they are charged. Utilities can benefit from dis

tributed generation by deferring some spending on trans

mission and distribution upgrades that would otherwise

be needed to serve new customers. In general, however,

such benefits are not subtracted from customers’

monthly charges.

The Public Utility Regulatory Policy Act (PURPA) spe

cifically requires utilities to provide standby service for

cogenerators and others that use certain renewable fuels

at nondiscriminatory rates. But many utilities only have

pro forma tariffs for standby service, and they set the

actual rates on a casebycase basis.4

 As a result, rates vary

widely; in many cases, they can significantly increase the

costs of distributed generation projects. The NREL study

on barriers to adoption of distributed generation docu

mented charges for standby service that ranged from less

than zero (a credit) to more than $18.75 per kilowatt per

month. In New York, charges for standby service range

from $4 to $16 per kilowatt per month. For the average

residential customer or small commercial enterprise that

may draw a maximum of only about 2 kilowatts, a

monthly charge at the high end of those ranges could

boost its electricity bills by as much as 20 percent. The

NREL noted that such wide variations “demonstrate a

lack of consistency and an absence of regulatory oversight

of [standby] tariffs.” According to the study, “the lack of

appropriate regulatory principles or standards . . . creates

uncertainty” that increases the financial risk for distrib

uted power projects.5

2. For a discussion, see Congressional Budget Office, Electric Utilities:

Deregulation and Stranded Costs (October 1998).

3. That charge is equivalent to approximately 35 cents per kilowatt

hour per month for customers who operate their equipment

continuously. 

4. A pro forma tariff contains general language authorizing the utility

to charge for a service on the basis of defined conditions and cost

categories. The actual price is determined on a casebycase basis,

consistent with the conditions stated in the tariff.

5. Department of Energy, National Renewable Energy Laboratory,

Making Connections, pp. 21 and 24.
26 PROSPECTS FOR DISTRIBUTED ELECTRICITY GENERATION

Compensating for Avoided Costs:

Prices for Power Sold to Utilities

A third category of barriers identified by proponents of

distributed generation is the price operators receive for

selling their excess electricity to the utilities. To date,

markets for excess power from small distributed genera

tors are underdeveloped in many areas of the country. In

those areas, there are no standardized rules that allow

most operators to sell electricity onto the power grid, and

no generally accepted mechanism is in place to set the

prices for such sales. In some cases, federal and state rules

have mandated that utilities purchase power from certain

distributed generators, but the administratively set prices

for that output generally do not induce producers to op

erate efficiently. 

PURPA requires utilities to purchase electricity from

independent generators that use cogeneration or various

renewable energy technologies at prices based on the

utilities’ wholesale cost of power (their “avoided cost”).

In the past, utilities have often determined their avoided

costs on the basis of the least expensive alternative source

of power, regardless of when it was generated. Independ

ent power producers have complained that those prices

are unreasonably low. Utilities frequently fail to provide

credits for reducing costs during peak periods of con

sumption and for deferring upgrades to transmission and

distribution networks. 

Another way that certain operators receive credit for

power they supply to the grid is through net metering.

As of 2001, 33 states had mandated some type of net

metering through legislation or regulation.6

 Under a

typical netmetering tariff, a customer’s electricity meter

is allowed to run backwards when it supplies power,

reducing the customer’s net consumption. This device

effectively provides a credit for the generated power at the

retail electricity rate, up to the point at which the cus

tomer generates more power than he or she consumes in

a billing period. Some states require utilities to purchase

power beyond that point at avoided costs, whereas other

states do not require any additional compensation for

customers. Most states with netmetering tariffs limit

eligibility to small generators (typically, maximum sizes

range from 10 kilowatts to 100 kilowatts) using renew

able and highefficiency technologies. 

PURPAmandated purchases and netmetering tariffs

create the only organized markets for the sale of excess

power from most operators of small distributed genera

tors in the United States today. For operators who do not

qualify for those markets (because their generators use

conventional technologies such as internal combustion

engines), often no outlet exists through which they can

sell excess power. Such outlets may develop in the future,

along with the establishment of wholesale power markets

that compete in each region. Until they do, however,

customers considering distributed generation must assess

its financial attractiveness without the option of selling

excess power. That limitation will constrain customers

to considering generators that serve only their needs,

even though largercapacity generators could be more

costeffective, both for the customer and for all rate

payers.

For operators who do qualify to sell their excess power to

the utilities, the prices they receive may not offer suffi

cient incentives to install and operate their distributed

generators in a costeffective manner. That is because the

prices in those markets generally do not reflect the costs

of the additional utilitysupplied power that would have

been produced in the absence of power from the distrib

uted generators. At the wholesale level, the costs of pro

ducing and delivering electricity vary continuously by

time and location, as consumption fluctuates in real

time. During periods of peak demand, the cost of elec

tricity typically rises as lessefficient generators are placed

in service. The costs also vary by location because of con

straints in the capacity of the transmission and distribu

tion system that affect deliveries during periods of peak

demand. 

But at the retail level, prices generally do not vary by

time or location.7

 Similarly, administratively set “avoided

cost” payments to qualifying operators of distributed

generators are often fixed, with predetermined prices in

6. For a summary of state net metering programs through May 2001,

see www.awea.org/policy/netmeter.html.

7. Many retail customers are billed under timeofuse tariffs, which

charge fixed prices only during predefined periods.
CHAPTER FOUR BARRIERS THAT IMPEDE WIDESPREAD ADOPTION OF DISTRIBUTED GENERATION 27

defined periods. Whether the cost of power is high or

low during a given period, retail customers typically pay

the same price per kilowatthour for electricity, and net

metered customers receive the same credit per kilowatt

hour. Under costofservice regulated rates, that price

may include charges for past investments that have little

relation to the cost of additional power. 

That disparity between the wholesale cost of electricity

and the prices that operators of distributed generators

receive may raise the overall cost of electricity by limiting

operators’ incentives to run their units most efficiently.

Distributed generators may operate during periods when

it is less expensive to supply additional power from the

grid, or they may remain idle when they could be pro

ducing electricity at a cost lower than that of additional

gridsupplied power. In the long run, customers might

install distributed generators even though the longrun

marginal costs of gridsupplied power would be lower (a

situation known as uneconomic bypass), or they might

decide not to install generators even though the costs of

distributed power would be lower.

Environmental Concerns:

Siting Restrictions and

Permitting Requirements

Almost all states, counties, and cities regulate the install

ation and operation of electricity generators. Those regu

lations, which vary widely across the country, are often

enforced by multiple, and sometimes overlapping, juris

dictions.8

 Some analysts argue that the lack of stan

dardized environmental regulations for distributed gener

ation inappropriately hinders its development by making

it impossible for national manufacturers to design equip

ment to meet a set of clear, uniform requirements. They

also contend that most air quality programs fail to rec

ognize the environmental benefits of distributed genera

tion in reducing emissions from other sources that may

be less efficient, including central power plants and cus

tomerowned boilers. An NREL study of environmental

regulations surrounding distributed generation recom

mended that “air quality permitting should provide

credit for avoided or displaced emissions” from distrib

uted generation.9

 

Air quality issues are one component of the permitting

process for installing distributed generators. The other

components are landuse approvals and building codes.

Local governments require landuse approvals to ensure

that a project conforms to zoning ordinances governing

allowable uses for a property. Typically, ordinances do

not identify electricity generating plants as a permissible

land use, so jurisdictions usually require a review to

weigh benefits and drawbacks and determine whether a

permit should be granted. In some states, the landuse

review may trigger an environmental impact review if the

project might be detrimental to air and water quality, for

example. 

The building permit process—a separate requirement

—ensures that a project conforms to certain safety stan

dards. Those standards are described in building codes

governing such characteristics as fire protection, plumb

ing, electric power, and mechanical equipment. Building

permits are required for all new construction and most

substantial building improvements and equipment ad

ditions. Building codes usually require that developers

submit plans for review and approval before installation.

In the case of distributed generation, building code de

partments may require additional information if the

equipment has not been certified by an independent

testing organization, such as Underwriters Laboratories.

Many building codes include specific regulations for on

site generators. Codes often require that certain building

classifications be equipped with an emergency power sup

ply to generate electricity when normal service is inter

rupted. Those generators must typically be powered by

a fuel supply that is on the premises, such as diesel fuel

or gasoline. That requirement can preclude the use of

distributed generation technologies fueled by natural gas

(which must be piped in), even though they can be less

8. For a detailed discussion of environmental issues surrounding the

siting of distributed generation, see California Energy Com

mission, Distributed Generation: CEQA Review and Permit Stream

lining, Report No. P70000019 (December 2000).

9. Department of Energy, National Renewable Energy Laboratory,

The Impact of Air Quality Regulations on Distributed Generation,

NREL/SR20031772 (October 2002).
28 PROSPECTS FOR DISTRIBUTED ELECTRICITY GENERATION

costly to operate and are associated with fewer harmful

emissions than diesel fuel or gasoline. For buildings that

are required to have an emergency power supply, natural

gas could be used only if the operator installed a dualfuel

generator—burning natural gas for nonemergency power

needs (and sales to utilities) and burning diesel or gaso

line for backup power. 

State air control agencies and regional air quality manage

ment districts usually oversee the permit process for emis

sions. Regulations vary widely, although most districts

restrict dieselfueled backup generators to no more than

200 hours per year of operation, and only under emergency

conditions. In areas that are out of compliance with air

quality standards, nonexempt (large) generators must use

the “best available control technology” to limit emissions

and may be required to purchase rights to emit nitrogen

oxides. Those requirements represent a barrier to the adop

tion of distributed generation because they can substantially

increase the installed capital and effective operating costs

of conventional internal combustion generators.

Although building standards and regulations on land use

and air quality are designed to protect against significant

environmental risks, some observers argue that the existing

regulations governing distributed generation are often too

broad or are inconsistent from site to site. The NREL study

on environmental regulations and distributed generation

concluded that “the complex, casebycase permitting process

designed for ‘large’ generators is inherently incongruous

with application to small, standardized distributed gen

eration technologies.” Examples of such regulations include

blanket prohibitions on electricity generation, limits on

operation of backup generators, and height restrictions

on towers needed for wind generators. The applicant bears

the burden of obtaining an exception to those regulations,

increasing the cost and time needed for approval. At a mini

mum, the regulations increase the uncertainty on the part

of prospective owners and operators about the costs of adop

tion for all technologies. 

Future Competitiveness:

Uncertainty Surrounding Costs

With the elimination of arbitrary barriers, the market

circumstances in which distributed generation technologies

can compete favorably with centrally generated power,

supplied by utilities, are likely to expand. But even so, the

costs of power from new large generators, favored by utilities

and independent producers, will probably be lower than

those of distributed generation technologies in most ap

plications. The costs of utilitysupplied power are not likely

to remain constant either, especially if further advances

in wholesale competition or moves toward retail competition

take place. The future prospects for distributed generation

will depend greatly on just how the costs of utilitysupplied

power change. If current constraints on electricity transmission

are eased or the marginal costs of producing and delivering

power from central generators decline, the attractiveness

of investing in distributed generation will probably diminish.

It is also possible that some forms of distributed genera

tion—especially in smallscale applications—may not fare

as well as others. The bottom line is that today’s investors

in distributed generation technologies must be concerned

not only about current barriers but also about uncertainty

regarding the technologies’ future competitiveness. 
5

Policy Options

The barriers discussed in the previous chapter could

be lowered in several ways without jeopardizing other

important social goals of state regulators and local gov

ernments. The most important initiatives that would al

low an economic and wider use of distributed generation

include the following:

# Ensure access to the grid for distributed generators

under uniform technical and contractual terms and

charges for interconnection that are based on eco

nomic costs—so that owners know in advance the

requirements for parallel interconnection and manu

facturers can design standard packages to meet tech

nical requirements;

# Establish prices that owners of distributed generators

both pay and receive for electricity at levels consis

tent with utilities’ wholesale hourly costs to deliver

power to different locations, and set uniform, ex

plicit rates for standby electricity service based on

costs—so that owners can decide between purchas

ing or generating power on the basis of prices that

reflect utilities’ incremental costs of serving them;

and

# Set uniform requirements for emissions, land use,

and building codes that are based on the technology

of electricity generation—so that manufacturers can

design suitable units and owners of distributed gen

erators are not restricted in their siting and operating

decisions relative to other new sources of generation.

The design of any policy initiative in those areas is com

plicated by the division of regulatory authority among

the federal, state, and local governments. Under the reg

ulatory framework for electricity markets that has evolved

from the Federal Power Act of 1935, the federal govern

ment has primary responsibility for the regulation of

pricing and access in the wholesale power markets, and

the states have responsibility for the retail markets served

by investorowned utilities. The stateowned, municipal,

and cooperative utilities that also serve retail customers

generally regulate themselves. Decisions about the siting

of power plants—in consideration of safety, air quality,

noise, and local congestion—are generally in the domain

of state and local governments. The issue of reducing

barriers to distributed generation, no matter whether the

power comes from small independent suppliers of cogen

eration electricity or households with solar panels, cuts

across all those jurisdictions.

In terms of economic efficiency, it may not matter which

level of government is responsible for effecting those

types of regulatory change. But it is important that broad

changes to operational practices and rules occur together.

Unless fundamental changes in restrictions on siting and

operation, access to the grid, and pricing are all ad

dressed, the prospect of improving the economic effi

ciency of electricity generation through wider adoption

of distributed generation may not advance noticeably. 

Access to the Grid: Reducing

Technical, Contractual, and

Cost Barriers

The ability of owners of distributed generators to gain

full access to the local distribution grid—whether to

continue receiving utility power or to provide distributed

generation power—can be impeded by poorly defined

technical requirements for interconnection, contractual

CHAPTER
30 PROSPECTS FOR DISTRIBUTED ELECTRICITY GENERATION

conditions that impose onerous liability and insurance

provisions, or arbitrary charges for special services re

quired as a condition for interconnection. Those barriers

could be lowered by specifying the requirements, condi

tions, and charges more clearly and grounding them in

sound principles of economic costs.

Prescriptive technical standards for interconnection would

clearly define the conditions under which utilities allowed

broad classes of distributed generators to connect to local

power grids without customized equipment or special

studies.1

 Standards could help reduce uncertainty about

the costs of the controls and equipment necessary for con

nection and ensure that customers’ costs for connecting

reflected the actual costs of those controls and equipment.

Such standards could also lower costs by fostering a

market for packaged controls and interconnection equip

ment. In such packages, the controls that ensure the safety

of the system and protect the quality of the power would

be incorporated in distributed generation equipment at

the factory rather than custom designed and built for each

application on the basis of casebycase requirements from

the utility. Regulatory authorities or other public agencies

could establish rules requiring utilities to expedite inter

connections with customers who installed such equip

ment. A market for standard packages could also help the

industry achieve design and manufacturing economies

that would lower the total costs of distributed generation

equipment and connecting to the grid. 

In an effort to clarify and tighten interconnection stan

dards, the regulatory bodies in some states have adopted

rules that limit the conditions under which interconnec

tion studies are required or prescribe the conduct of such

studies. The New York Public Service Commission ex

empts customers from the need for utility interconnection

studies if their generators have capacities below 10 kilo

watts—generally enough power to supply a small com

mercial building or a block of homes. Additional ex

emptions can apply to customers with generators as large

as 150 kilowatts, depending on the type of interconnection

they have with the grid. Similarly, the Texas Public Utility

Commission (PUC) prohibits utilities from charging for

interconnection studies for customers that request parallel

service but do not export power to the grid and customers

that have precertified generators under 500 kilowatts that

contribute less than 25 percent of the maximum current

on a radial grid connection.2

 If an interconnection study

is needed, the Texas PUC requires that the customer re

ceive an estimate of the study’s cost, that the study be

completed within four weeks, and that it consider benefits

to the utility system from the interconnection.

In addition to technical standards, uniform contracts

would help prospective investors in distributed generation

by clarifying the liability, insurance, and other conditions

for interconnection and their costs. Those contracts could

be developed under the auspices of regulatory bodies to

ensure the evenhandedness of the provisions. Such con

tracts would tend to lower the costs of insurance, because

they would clearly define the conditions under which own

ers would be liable and the procedures under which dis

putes would be resolved.

The Federal Energy Regulatory Commission is in the early

stages of developing standard procedures and agreements

for the interconnection and parallel operation of generators

and utility transmission systems.3

 Those proceedings have

produced proposals for draft contracts that spell out the

responsibilities of the interconnection customer and

transmission provider in the design and operation of their

facilities, the liabilities of each party, procedures for testing

and inspection, insurance obligations, and other relevant

provisions. Other organizations have developed their own

procedures and agreements for interconnecting generators

1. Interested parties are already actively developing technical stan

dards under the auspices of the Institute of Electrical and Elec

tronics Engineers (IEEE). The IEEE subcommittee responsible

for that work has published draft standards that provide technical

specifications and test requirements for connecting distributed

generation technologies under 10 megawatts in capacity to elec

tric power systems at low voltages. See Institute of Electrical and

Electronics Engineers, “Draft Standard for Interconnecting

Distributed Resources with Electric Power Systems,” IEEE

P1547/D08 (August 29, 2001).

2. A radial connection has only a single path on the grid between

the point of consumption and the substation.

3. Department of Energy, Federal Energy Regulatory Commission,

“Advance Notice of Proposed Rulemaking on Standardization of

Small Generator Interconnection Agreements and Procedures,”

Docket No. RM0212000 (August 16, 2002).
CHAPTER FIVE POLICY OPTIONS 31

and transmission providers. Such organizations include

the Electric Reliability Council of Texas, the California

Public Utilities Commission, the Edison Electric Institute

(a trade organization representing investorowned util

ities), and the Electric Power Supply Association (a trade

association representing independent power producers).4

All of those initiatives would, at a minimum, reduce im

portant types of uncertainty on the part of customers

about the costs of distributed generation. They would also

eliminate the time and expense of negotiating terms of

interconnection for each proposed project. That would

allow customers to make meaningful comparisons of the

merits of distributed generation relative to utilitysupplied

power.

At some point, further progress on national technical and

contractual standards and utility charges might require

the impetus of federal legislation—for example, in the

form of directions to FERC to establish a standard con

tract or federal assistance to state and private efforts to

agree on prescriptive standards. The different versions of

energy legislation in the 108th Congress contain language

that requires utilities to provide distributed generation

systems with competitive access to the local distribution

grid, offer simplified standard contracts for the inter

connection of small generators, and not charge distributed

generation customers for interconnections.

Real-Time Prices Based on Wholesale Costs: Reducing Pricing Barriers

The prices that operators of distributed generators pay and

receive for electricity are also key to achieving potential

benefits in electricity markets. Electricity services fall into

three major categories—electric energy, transportation,

and socalled ancillary services. Electric energy is the power

that generators produce. Transportation is the high

voltage transmission and local distribution of power from

the point of generation to the place of consumption.

Ancillary services encompass various support functions

that ensure the delivered electric power meets certain levels

of quality and reliability. For operators of distributed

generators, the most important of those functions is

standby service, which allows them to draw power from

the grid whenever they need it and thus protects them

against losses from unplanned outages of their generators.

If the prices for those electricity services—power, trans

portation, and support functions—reflected the incre

mental costs to utilities of providing them, then customers

would have incentives to install and operate distributed

generators only in situations in which their costs were

lower.

Realtime tariffs for electricity sales both to and from

operators of distributed generators could provide the ap

propriate price signals for electric power and transmission

services. Under realtime pricing, the retail rate for elec

tricity varies hourly and geographically in accordance

with the utilities’ wholesale cost of power. With that

form of pricing, customers would have a financial incen

tive to install distributed generators in locations where

prices were chronically high as a result of transmission

congestion. They would operate their units at times

when the price of electricity exceeded their operating

costs and would purchase utilitysupplied power when

the price fell below those costs. Relative to the current

situation, that behavior would reduce net demand (and

possibly increase net supply) for electricity from the

utility network during periods of high prices, which

would reduce local congestion on the grid. It would also

displace more expensive central generation during pe

riods of peak demand and tend to reduce wholesale elec

tricity prices. Those reductions would typically be passed

on to all retail customers in the form of lower rates.

Putting realtime pricing into practice on a wider basis

has implications for the economic efficiency of electricity

markets. Potential benefits to consumers that flow from

offering tariffs under which prices vary according to whole

sale costs in real time may exceed those from an eco

nomically efficient adoption of distributed generation.

Nevertheless, realtime pricing would send market signals

that would encourage investment in and use of distributed

generation. 

How Would Prices Be Set? 

The development of prices that encourage efficient siting

and operation of distributed generators has been the shared

4. All of the agreements are available under FERC’s “Advance Notice

of Proposed Rulemaking on Standardization of Small Generator

Interconnection Agreements and Procedures.”
32 PROSPECTS FOR DISTRIBUTED ELECTRICITY GENERATION

responsibility of legislators and regulatory bodies at both

the federal and state levels. A recent federal legislative

proposal (S.14 in the 108th Congress) includes provisions

that will require state regulatory bodies to consider real

time tariffs. FERC has recently proposed creating regional

wholesale markets for power throughout the United States

that would feature different prices at each delivery point.

And at least one state regulatory body, the California PUC,

has instituted general proceedings to set policies for real

time pricing for all customers. Several utilities (including

Georgia Power and Niagara Mohawk) have designed and

offered voluntary realtime tariffs to large customers.

Developing tariffs that reflect efficient pricing is not a

simple matter. In the retail electricity market, where

regulators typically approve utility tariffs, the goal of

promoting economic efficiency must be reconciled with

other ratemaking principles, including the recovery of

embedded costs and the allocation of fixed costs on the

basis of consumption. Conflicting interests—for example,

those of distributed generation customers who want prices

to reflect generation and transmission costs and a utility

that is required to subsidize the cost of power to rural

households—may be difficult to reconcile at the state or

local level. That difficulty suggests that the federal gov

ernment may need to step in to resolve pricing issues.

Specific suggestions for federal intervention are related

to the need for marginal costbased prices that vary fre

quently to reflect current market circumstances and the

installation of netmetering service to facilitate such pric

ing. The Congress has recently considered those proposals

as a part of comprehensive energy legislation.

The technical feasibility of identifying marginal costbased

prices in real time is supported by information processed

by transmission systems owned by individual utilities, as

well as by regional transmission networks in which several

utility and nonutility generators participate. Both of those

operating models produce values for timevarying costs

by location, which could be the basis for designing real

time tariffs. In many utility transmission systems today,

operators calculate the values of electricity at different lo

cations almost continuously as demand fluctuates in real

time. Computer programs perform those calculations to

determine the least expensive mix of electricity generation

from available plants at any time, given the level of de

mand, capacities of transmission lines, and other operating

constraints. The same calculations—typically performed

at very short time intervals, as frequently as every five min

utes—also yield an estimate of the cost of supplying an

additional kilowatt at each delivery point in the network.

A second source of such realtime, marginal costbased

prices is the bidding systems of the integrated transmission

networks, jointly owned by several utilities and run by a

single operator. Those networks include such entities as

the PJM Independent System Operator, which manages

the transmission system covering several midAtlantic

states, and the New York Independent System Operator,

which manages the transmission system in the state of

New York. Those networks have developed systems to

operate power plants and handle power exchanges among

members as well as purchases from independent producers.

Several use bidding systems in which producers offer to

generate power at prices above a set minimum. Operators

select plants to run on the basis of those prices (from lowest

to highest) in place of the operating cost schedules used

under a single owner/operator system. The end result is

similar, with a price for each delivery point, referred to

as locational marginal prices. 

FERC is encouraging all transmission owners in the

United States to form integrated networks and designate

independent operators to run them under such a bidding

system. The realtime prices that could come out of those

systems would track wholesale costs as they varied at short

time intervals. Those prices would give owners of dis

tributed generators the price signals and incentives they

needed to operate during periods of critical consumption.

In the long term, price differentials across locations would

give customers an incentive to build new distributed gen

eration plants in places where they could reduce transmis

sion congestion and losses to the greatest extent.5

 

Other Issues Related to Pricing

At least three practical considerations must be accounted

for in designing realtime pricing for owners of distributed

5. Under FERC’s proposal, the price differentials would only apply

to the transmission portion of the electricity network. Retail

utilities would need to associate those prices with delivery points

in the distribution system and possibly add locationspecific sur

charges for distribution congestion.
CHAPTER FIVE POLICY OPTIONS 33

generators. First, owners are both consumers and producers

of electricity. If the prices they pay for electricity differ

from the prices they receive, the differences may distort

their incentives. (See the appendix for a discussion of the

relationship between market reform and the pricing of

electricity for distributed generation customers.) For

example, industrial customers with multiple meters could

shift loads, buying power at low average costbased rates

while selling power at high realtime prices. Those types

of distortions can be avoided if distributed generators are

obliged to buy and sell power at the same realtime prices.

Second, the costs for data collection and administration

of realtime tariffs are significantly higher than those of

traditional tariffs. Meters that record electricity consump

tion in short time intervals (hourly or in 15minute

periods) range in cost from $200 to $3,700, depending

on their features.6

 Recently, in California, realtime meters

and automated communications systems were installed

for more than 20,000 large customers, whose electricity

consumption represents almost 30 percent of the state’s

annual peak demand. The average cost per installed meter

was approximately $1,600. That figure provides a

reasonable estimate of the cost of the metering equipment

that would be needed for a large number of installations

for large customers. Metering equipment with fewer fea

tures, which would be suitable for smaller customers,

would cost much less. One study estimated that the

monthly cost of an interval meter used for a simple form

of realtime pricing would be less than $5 per month under

a fiveyear contract.7

 

Data acquisition, processing, and reporting can add sig

nificantly to the costs of administering realtime tariffs.

All those costs must be recovered from customers billed

under the realtime tariffs. Utilities offering such tariffs

today typically recover metering and administrative costs

through fixed monthly charges. Georgia Power levies a

fixed charge of $175 per month on its customers billed

under realtime pricing who have peak demand that ex

ceeds 250 kilowatts per month. That fixed charge, which

covers billing, administrative, and communications costs

for the program as well as costs for the metering and com

munications equipment, represents less than 5 percent

of the monthly bill for a typical qualifying customer.

Third, realtime tariffs must incorporate other ratemaking

principles in regulated markets. Those principles include

embedded cost recovery and standards of equity in sharing

common costs. In some cases, reconciling those principles

with realtime prices based on wholesale costs may be very

difficult. For example, many regulatory bodies have

adopted a standard of equity that reflects the notion of

sharing common costs in proportion to consumption.

Under that standard, small users in a customer class pay

the same rate per kilowatthour as large users. When cus

tomers install onsite generators to meet their own

demand, their share of the common costs is shifted to the

remaining ratepayers, unless the utility charges a standby

service fee or exit fee. Those fees may discourage the

installation of distributed generators, even if their electricity

is the cheapest to produce. 

One possible solution to that last problem, discussed by

some analysts, is to levy a fixed monthly charge—paid

by all customers, not just operators of distributed genera

tors, on the basis of capacity—to recover common costs.8

The fixed charge would cover network costs that do not

vary with the level of electricity usage, replacing standby

tariffs for distributed generation customers. A twopart

tariff with such a fixed charge and a perkilowatthour price

equal to the marginal wholesale cost is known as a Coase

tariff, named after the economist who proposed it. As long

as the fixed charge did not prevent customers from con

necting to the electricity network, that price schedule

would promote the efficient consumption and production 6. For a discussion of those issues, see Robert Staunton and others,

“Demand Response: An Overview of Enabling Technologies,”

Public Utilities Fortnightly, vol. 139, no. 20 (November 1, 2001),

pp. 3239.

7. That cost is equivalent to approximately $250 in real (inflation

adjusted) capital expense at an 8 percent discount rate. See Cali

fornia Energy Commission, Meter Scoping Study (report prepared

by Levy Associates for the Public Interest Energy Research Pro

gram, February 2002).

8. For an extensive discussion of efficiency and equity issues sur

rounding multipart electricity tariffs, see James C. Bonbright,

Albert L. Danielson, and David R. Kamerschen, Principles of Public

Utility Rates (Arlington,Va.: Public Utilities Reports, 1988).
34 PROSPECTS FOR DISTRIBUTED ELECTRICITY GENERATION

of electricity.9 Such a tariff may be considered inequitable

in many jurisdictions, however, because it violates the

principle of cost sharing in proportion to use.

Local Government Permits: Reducing

Siting and Environmental Barriers

Federal, state, and local rules surrounding the installation

and operation of distributed generators, although intended

to protect the public, can create costs and uncertainty for

investors in distributed power. The American Council

for an Energy Efficient Economy has identified the Envi

ronmental Protection Agency’s (EPA’s) New Source Re

view process as a significant barrier to the growth of com

bined heat and power systems, a key distributed generation

technology, and has complained that the current require

ments fail to credit CHP for emissions reductions from

increased efficiency. The California Energy Commission

has investigated the local environmental review process

for the siting of certain types of distributed generators with

the objective of streamlining the local permit process. That

initiative is one effort to lower the costs and uncertainty

associated with complying with environmental and other

siting and operating restrictions without materially in

creasing risks to the community. In general, that result

could be achieved by clarifying and rationalizing the regu

lations affecting land use, building safety, and air quality.

More specifically, such an approach would require local

governments to replace general restrictions with regulations

that clearly specify the technologies, operating characteris

tics, and conditions for which distributed generation ap

plications would be permitted. 

The existing general regulations include such provisions

as blanket prohibitions on electricity generation in many

landuse categories, restrictions on the operation of backup

generators, and height limits for towers used by wind

generators. Those regulations could be replaced with rules

that permitted the installation and operation of certain

smallscale, generally benign technologies—such as solar

photovoltaic systems and fuel cells—under defined op

erating conditions. Other highefficiency technologies—

such as microturbines and natural gasfueled internal com

bustion generators—could be included along with stan

dards for emissions thresholds, noise levels, and aesthetics.

In addition, revised regulations could specify standard

mitigation measures and testing procedures for distributed

generators in cases in which conditionaluse permits were

required.

Much of the direct responsibility for those types of changes

currently lies with local governments—including cities,

counties, and regional air resource boards—although those

bodies may be acting in response to broader state and

federal mandates. For example, the federal Clean Air Act

requires local governments to establish programs to bring

local air quality into compliance with standards enforced

by the EPA. The federal government or state public agen

cies could take additional steps to encourage or require

local governments to make those types of changes.

Among the options available to the federal government

is directly assisting in the streamlining of the local envi

ronmental permit process by developing model regulations

and certification guidelines or by providing technical

support to local enforcement offices. For example, the

government could develop uniform building code re

quirements for various classes of distributed generation.

Such codes could streamline the approval process for

installing distributed generators, reducing both the un

certainty about the requirements and the typical cost of

compliance. Federal support could also include recom

mendations for updating zoning ordinances to identify

where and under what conditions distributed generators

would be allowed. Those new guidelines could cover rec

ommended standards for emissions and other environmen

tal impacts, as well as specify the testing procedures that

would be used to verify compliance. Technical support

could include information for building departments and

other local enforcement offices about the checking of plans

and the inspecting of newly installed distributed generation

technologies.

9. Bridger Mitchell and Ingo Vogelsang, Telecommunications Pricing:

Theory and Practice (Cambridge, England: Cambridge University

Press, 1991), p. 36.
Electricity Market Restructuring and

Distributed Generation

The ongoing deregulation of the generation portion

of electricity markets in the United States strongly affects

the prospects for distributed generation and its potential

to reduce electricity costs. The structure of deregulated

wholesale power markets will influence the prices for

distributed generation output and for related electricity

services. The levels of those prices relative to retail elec

tricity prices will determine whether distributed genera

tors can be used in a manner that benefits their owners

without raising costs for other customers. In particular,

when a retail customer can also act as a supplier of elec

tricity by operating distributed generation, differences

between prices in the retail and wholesale markets may

create incentives that increase costs for other customers.

Changes in How Utilities 

Are Structured

The structure of wholesale and retail electricity markets

varies widely throughout the United States. Historically,

investorowned utilities have supplied most of the electric

power. The federal government has played a key role in

developing and managing hydroelectric power in several

regions. Municipal and cooperative utilities also are signif

icant suppliers, especially of distribution services in rural

areas. Many aspects of this structure have changed dra

matically in the past two decades, and more changes are

expected in the future. 

Investorowned utilities, which typically own an entire

system of generators, transmission and distribution lines,

and equipment (referred to as vertical integration), are

regulated by federal and state bodies. The Federal Energy

Regulatory Commission (FERC) oversees the transmission

system and wholesale electricity markets. State public util

ity commissions govern retail markets. Traditionally, state

regulators have authorized the tariffs that investorowned

retail utilities can charge, setting rates that allow recovery

of past investments and a reasonable return on those invest

ments. That structure of regulated, vertically integrated

monopolies that supply electricity at prices based on em

bedded (historical) costs has dominated electricity markets

in the United States for most of the 20th century. 

But over the past few decades, the vertical structure has

changed in several important ways. First, utilities have

integrated the interconnection and operation of their

transmission networks substantially. That integration has

allowed them to provide more reliable service at lower costs

by taking advantage of generation from diverse sources

and “gains from trade” (agreements to exchange power)

with other utilities. Approximately 150 control areas have

been organized in the United States under which a single

operator manages an interconnected transmission grid

and power plant system, using computerized controls to

balance supply and demand and maintain the system’s

safety and reliability. Power exchanges and sales in those

areas are governed by negotiated agreements and operating

rules, subject to FERC’s approval.

Second, starting in the late 1970s with enactment of the

Public Utilities Regulatory Policies Act (PURPA), federal

and state legislatures and regulatory bodies established

rules for utilities to buy power at negotiated rates from

independent, nonutility producers. What has gradually

emerged since then is a mixed system of utilityowned

generation, bilateral transactions for power at negotiated

(marketbased) prices, and several regional wholesale mar

kets for electricity organized around interconnected trans

mission systems. The regional markets that have devel

oped as a result of PURPA feature power exchanges in

APPENDIX
36 PROSPECTS FOR DISTRIBUTED ELECTRICITY GENERATION

which prices fluctuate hourly, on the basis of supply and

demand.

Third, in 1999, FERC called for the establishment of

independent transmission organizations throughout the

United States that would operate regional wholesale elec

tricity markets. In July 2002, the commission presented

its proposal on how those markets would function. The

operation that FERC envisions is similar to the way in

which some regional markets, including PJM (covering

several midAtlantic states) and the New York Independ

ent System Operator, currently operate.

Under FERC’s proposed system, generators would bid

to sell power in the regional markets on an hourly basis.

Bids would vary widely because of differences in the

operating costs of available generators. Starting with the

lowest bid and moving higher, the transmission system

operator would select the generators to produce sufficient

electricity to meet final demand each hour.1

 All generators

selected to run would be paid the value of the highest

accepted bid. If congestion on a segment of the transmis

sion system forced the operator to run a generator whose

bid was above the highest accepted bid, prices of power

at the delivery points served by the congested segment

would be raised to reflect the difference. As a result, the

price of electricity would vary each hour depending on

the incremental generation costs incurred to serve the

load, and it would vary by delivery point depending on

transmission congestion. Price differences resulting from

congestion would be managed through a market for trans

mission rights between the point of generation and the

point of delivery.

In FERC’s system, individual generators and wholesale

customers could have bilateral contracts at fixed rates. If

the generator failed to meet its contracted obligation, then

it would buy power in the spot market to eliminate the

deficit. If the customer used more than its contracted

load, then the customer would buy the excess power in

the spot market.

The competitive spot market for power would establish

an unambiguous incremental wholesale cost of electric

power. The marketclearing (highest accepted) price in

the spot market would be the cost of an additional kilo

watthour in each hour and at each delivery point, even

when the majority of the power was transmitted under

longterm bilateral contracts at fixed prices.2

 The (realized

or avoided) cost of an additional kilowatthour would be

the shortterm spot price. 

The Impact of Electricity Pricing on

Distributed Generation

Most retail electricity customers in the United States face

prices that are the same during predefined periods, re

gardless of the wholesale cost of power in a given hour.

In states that continue to set electricity prices on the basis

of traditional costofservice regulation, those prices are

based on past investments. The rates may include charges

that are unrelated to the current incremental cost of pro

duction—for example, charges to recover past invest

ments in power plants that have proven uneconomic or

charges for previously signed longterm contracts with

prices above those for newly constructed generation. In

states that have introduced competition in retail markets,

suppliers are free to offer electricity at any price, with a

regulated surcharge for the transportation of the power.

That surcharge may include an additional component to

recover the “stranded” costs of past investments made by

the old regulated utility before the switch to competition.

The difference between wholesale and retail electricity

prices may induce customers to install and operate distri

buted generators in a manner that fails to lower, and pos

sibly raises, costs for other retail customers. For example,

a customer in a state with high rates stemming from ex

pensive past investments can avoid those rates by operating

a distributed generator and shifting the burden of re

covering those past investments to the remaining rate

payers. That shift can happen even when the cost of whole

sale power is below that of distributed power. Such situa

1. In the wholesale market, the customers are retail distribution

utilities. They act as intermediaries, buying electricity at

wholesale prices to meet the final demands of their retail cus

tomers.

2. In the geographic area managed by the PJM Independent Sys

tem Operator, for example, more than 80 percent of the

power is either owned by the retail utility or purchased under

longterm contracts.
APPENDIX ELECTRICITY MARKET RESTRUCTURING AND DISTRIBUTED GENERATION 37

tions are referred to as “uneconomic bypass” because they

raise the total cost of supplying electricity to ratepayers

as a group.

Even when regulated retail rates are not burdened by ex

pensive past investments, they may fail to offer customers

the incentive to operate distributed generators during

periods of peak demand and high wholesale prices. That

is because regulated retail electricity prices generally do

not track hourly variations in wholesale prices. If a cus

tomer faces a constant retail price, as most do, it has an

incentive to operate its distributed generator either con

tinuously or not at all. As a consequence, the distributed

generator may run even when the wholesale cost is lower,

and it may not run even when the wholesale cost is higher.

Several strategies have been proposed to price electric power

from distributed generators. One widely used method for

small distributed generators is called net metering. In its

simplest form, net metering allows a retail customer’s

electricity meter to run backwards, so that transmission

onto the grid offsets purchases from the grid. The cus

tomer receives a credit from its energy service provider,

at the same rate it pays to buy power, for the electricity

it supplies onto the grid. Many states have already ordered

private utilities to offer net metering to certain small,

qualifying customers. Those customers include solar and

wind generators that operate intermittently. Through

2000, 33 states had mandated some form of net metering.

Although net metering provides a ready market for

distributed generation output at retail prices, its simple

application does not address the problems described earlier,

namely, uneconomic bypass and a lack of incentives to

operate during peak periods. A second approach, advocated

by many analysts, is known as realtime, or dynamic, pric

ing. Under realtime pricing, retail rates fluctuate at short

time intervals according to variations in wholesale spot

market prices. Such rates provide the price incentives for

customers to operate their units during peak periods, when

wholesale prices are highest. Those rates could be offered

in conjunction with net metering; in that case, credits

would be based on the wholesale price of electricity in each

hour rather than the average price for the month.

A range of technical and regulatory issues surrounds the

design of realtime retail tariffs. Those issues include recov

ering the costs of special metering equipment required

for tariffs and reconciling realtime rates with embedded

cost recovery. Some analysts have recommended adding

a fixed charge to realtime rates to cover those costs and

offering the tariffs on a voluntary basis to make them more

acceptable to customers. Analysts expect that the average

price of electricity under realtime rates would be lower

than it would be under the current flat monthly rates.

Customers who elected to receive service under the lower

realtime rates would assume the risks associated with the

price volatility.
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