Energy Efficiency: Challenges and

Opportunities for Electric Utilities

September 1993

OTA-E-561

NTIS order #PB94-107547
Recommended Citation:

U.S. Congress, Office of Technology Assessment, Energy Efficiency: Challenges and

Opportunities for Electric Utilities, OTA-E-561 (Washington, DC: U.S. Gov ernment

Printing Office, September 1993).
Foreword

T

his Report on energy efficiency and electric utilities was prepared as part of OTA’s

assessment of U.S. Energy Efficiency: Past Trends and Future Opportunities. The

assessment was requested by the Senate Committees on Governmental Affairs and

Energy and Natural Resources and the House Committee on Energy and

Commerce and endorsed by the Chairman of the Subcommittee on Environment of the

House Committee on Space, Science, and Technology. Other reports in this assessment

examine energy efficiency in residential and commercial buildings, industry, transportation, and the Federal Government,

This Report focuses on the opportunities for advancing the energy efficiency of the U.S.

economy through technology improvements and institutional change in the electric utility

sector. In particular, the Report examines the prospects for energy savings through

expansion of utility demand-side management and integrated resource planning programs

and related Federal policy options.

OTA appreciates the advice and assistance of the many individuals who contributed to this

project, including the advisory panel, workshop participants, and reviewers.

(7+- -

Roger C. Herdman, Director

iii
Advisory Panel

James F. Gibbons, Chairman

Stanford University

Dale Compton

School of Industrial Engineering

Purdue University

Mark Cooper

Consumers Federation of America

Robert deHaan

Amana Refrigeration Co.

(retired)

Daniel A. Dreyfus1

Gas Research Institute

Clark W. Gellings

Electric Power Research Institute

David B. Goldstein

Natural Resources Defense Council

Cheryl Barrington

Regulatory Assistance Project

formerly Commissioner,

Maine Public Utilities Commission

Kenneth Hickman

The York International Corporation

Edward Mclnerney

General Electric Co.

Alan Miller

Center for Global Change

University of Maryland-College Park

Gary Nakarado

National Renewable Energy Laboratory

formerly Commissioner, Public Utility

Commission of Colorado

John W. Rowe

New England Electric System

Maxine L. Savitz

Garrett Processing Co.

Sherwood H. Smith, Jr.

Carolina Power & Light Co.

Richard Tracey

Ryland Homes

B.C. Waycaster

Dow Chemical

Irvin L. White

Battelle Pacific Northwest Laboratories

Mason Willrich

Pacific Gas and Electric Enterprises

James L. Wolf

The Alliance to Save Energy

Eric R. Zausner

Strategic Performance Management

1Until January 1993.

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

panel does not, however, necessarily approve, disapprove, or endorse this report. OTA assumes full responsibility for the report and the

accuracy of its contents.

iv
Peter Blair

Assistant Director

Industry, Commerce, and International

Security Division

(beginning February 1993)

Program Manager, Energy and Materials

Program

(until August 1993)

Lionel S. Johns

Assistant Director, OTA

(until February 1993)

Emilia Govan

Program Manager

Energy and Materials Program Manager

(beginning August 1993)

Project Staff

PRINCIPAL STAFF

Karen Larsen

Project Director

Helene Kirwan-Taylor

Contractor

ADMINISTRATIVE STAFF

Lillian Chapman

Office Administrator

Linda Long

Administrative Secretary

Tina Aikens

Secretary
workshop Participants

Doug Bauer

Oak Ridge National Laboratory

Michael Dworkin

General Counsel

Vermont Public Service Board

Hossein Haeri

Central Maine Power Co.

John Hughes

Electricity Consumers Resource

council

Gary Nakarado

Commissioner

Public Utility Commission of

Colorado

Wally Nixon

Entergy Services Co.

Paul Norman

Bonneville Power Administration

Jackie Pfannenstiel

Pacific Gas and Electric Co.

Ronald E. Russell

Commissioner

Michigan Public Service Commission

Glenn Simpson

Potomac Electric Power Co.

Dennis Sumner

City of Ft. Collins Light&

Power Utility

Lynn Sutcliffe

Sycom Enterprises, Inc.

Marika Tatsutani

Natural Resources Defense Council

Nat Treadway

Electric Division

Public Utilities Commission of Texas

James L. Wolf

The Alliance to Save Energy

OTA appreciates and is grateful for the valuable assistance and thoughtful critiques provided by the participants in OTA’S workshop on

Energy Efficiency and Electric Utilities, September 9, 1992. The workshop participants do not, however, necessarily approve, disapprove,

or endorse this report. OTA assumes full responsibility for the report and the accuracy of its contents.
John Anderson

Electricity Consumers Resource

council

Joel Bladow

Western Area Power Administration

Ashley Brown

Commissioner, Public Utilities

Commission of Ohio

Ralph Cavanagh

Natural Resources Defense Council

Greg Collins

PSI Energy, Inc.

Kurt Conger

American Public Power Association

Rich Cowart

Commissioner, Vermont Public Service

Board

Ron Eachus

Chairman, Oregon Public Utility

Commission

Scott Hempling

Attorney-at-Law

Robert Hirsch

Electric Power Research Institute

Eric Hirst

Oak Ridge National Laboratory

Barbara Kates-Garnick

Commissioner, Massachusetts Department

of Public Utilities

Reviewers

Steve Kline

Pacific Gas & Electric Co.

Paul Komor

U.S. Congress

Office of Technology Assessment

Ed Mayberry

Potomac Electric Power Co.

Barry Moline

American Public Power Association

Andrew Moyad

U.S. Congress

Office of Technology Assessment

Steve Nadel

American Council for an Energy-Efficient

Economy

John Newman

U.S. Congress

Office of Technology Assessment

Karl Rabago

Commissioner, Public Utilities

Commission of Texas

Margaret Rostker

Electric Power Research Institute

Robin Roy

U.S. Congress

Office of Technology Assessment

Rick Tempchin

Edison Electric Institute

Mark Wieringa

Western Area Power Administration
contents

1 Introduction 1

Energy and Electric Utilities 3

Findings 4

2 Policy Issues and Options 9

Strategies for Energy Efficiency 12

Integrated Resource Planning 13

Demand-Side Management 16

U.S. Department of Energy Programs 16

Utility Rate Reforms 17

Federal Regulation of Power Transactions 18

Leading by Example: The Federal Government

as Energy Consumer 19

Supporting Energy-Efficient Technologies 22

Increasing Utility Resource Options 23

Leveling the Playing Field in Resource Planning 24

3 Electric Utility Industry Structure,

Regulation, and Operations 27

Electric Utilities in the U.S. Economy 27

Electric Power Regulation 34

Overview of Electric Utility Systems and Operations 48

4 Using Electricity More Efficiently:

Demand-Side Opportunities 63

How Much Electricity Can Be Saved? 63

Energy-Efficiency Opportunities for Residential

Customers 67

Energy Efficiency Opportunities in the

Commercial Sector 79

Energy Efficiency Opportunities in the

Industrial Sector 88

$&-

>>>: ::: A
- Utility Energy Efficiency Programs

and Experience 99

Scope of Utility Energy Efficiency Programs 99

Influencing Customer Behavior 100

Measuring Energy Savings and

Evaluating Effectiveness 105

Mixed Results from Utility Energy

Efficiency Programs 110

Incorporating Energy Efficiency Into Utility

Operations: The Role of IRP 114

State Energy Efficiency Initiatives 117

Plannin g for Future Electricity Needs 117

IRP Requirements 122

State Incentives for Utility DSM Investments 129

Energy Efficiency Research and Development Programs 140

Federal Programs 143

The Federal Government and Energy Efficiency 143

U.S. Department of Energy Programs 144

Federal Power Systems 171

Rural Electrification Adrmru “stration 188

Federal Energy Regulatory Commission 189

Encouraging Voluntary Efforts 190

x
Introduction

E

nergy efficiency offers seemingly glittering promises to

all-savings for consumers and utilities, profits for

shareholders, improvements in industrial productivity,

enhanced international competitiveness, and reduced

environmental impacts. The technical opportunities are myriad

and potential savings real, but consumers and utilities have so far

been slow to invest in the most cost-effective, energy-efficient

technologies available. The energy efficiency of buildings,

electric equipment, and appliances in use falls far short of what

is technically attainable. Energy analysts have attributed this

efficiency gap to a variety of market, institutional, technical, and

behavioral constraints. Electric utility energy efficiency programs have great potential to narrow this gap and achieve

significant. energy savings.

But along with opportunities, greater reliance on energy

efficiency as a resource to meet future electricity needs also

entails risks—that efficient technologies will not perform as well

as promised, that anticipated savings will not be truly costeffective in practice, and that the costs and benefits of energyefficiency programs will not be shared equitably among utility :,

t’

customers. ,,

.:

More than 30 States have adopted programs for promoting “

energy efficiency through utility integrated resource planning

(IRP) and demand-side management (DSM) and programs are

rapidly being developed and implemented in most of the

remaining States (see box l-A). These programs reflect a

recognition that increasing the efficiency of energy use by

consumers to offset demand growth can be a financially

attractive and reliable alternative to the addition of new

generating plants. They also reflect a belief by policymakers that

tapping the economic and technical resources of electric utilities

can be an effective strategy for speeding the adoption of

energy-efficient technology in all sectors.

11
2 I Energy Efficiency: Challenges and Opportunities for Electric Utilities

Box l-A-Key Terms

I Energy efficiency refers to the physical performance of specific end uses or energy services such as

lighting, heating, cooling, and motor drive. Greater energy efficiency is achieved by replacing, upgrading,

or maintaining existing equipment to reduce the amount of energy needed. Energy efficiency is usually

measured by the output quantity per unit of energy input (miles per gallon or lumens per watt, for example).

Because energy is one of several factors of production (labor, capital, and materials are others), energy

efficiency improvements contribute to greater energy productivity and economic efficiency.

• Energy conservation refers to measures taken to reduce energy consumption. Conservation measures

include substituting more energy-efficient equipment to produce the same level of energy services with less

electricity and changing consumer behavior to cut energy use. The term is sometimes used interchangeably

with energy efficiency.

● Demand-Side Management (DSM) refers to utility-led programs intended to affect the timing or amount

of customer electricity use. These include energy efficiency programs aimed at reducing the energy needed

to serve customer needs and programs that shift electricity demand to reduce peak loads or to make more

economic use of utility resources. All utility DSM programs fit into one or both of following: 1) programs

affecting the way energy-using equipment is operated, and 2) programs that focus on the installation of

improved technologies. A variety of DSM mechanisms are in effect, including audit and information

programs, rebates and other consumer financial incentives, direct installation programs, technical

assistance, and energy performance contracting.

• Integrated Resource Planning (IRP) is a teohnique used by utilities and State energy regulatory agencies

to develop flexible plans for providing reliable and economic electric power supply for customer needs. The

process includes explicit comparisons of both supply-and demand-side resource options to meet a range

of future electricity demand scenarios. Utility planners compare the lifetime capital and operating costs,

availability, reliability, and environmental impacts of the various supply-and demand-side resource options

in a consistent manner to develop an overall plan to meet Identified future needs at least cost. There are

several competing methodologies for defining what resource chokes constitute “least-coost” mix. The IRP

process usually includes public participation and comment and may require approval of State regulators

before adoption. After adoption, the plan is used to guide utility chokes in acquiring new resources. IRP

is sometimes also referred to as least-cost planning.

SOURCE: Office of Technology Assessment, 1993.

With passage of the Energy Policy Act of 1992, sions, maximizing energy efficiency will be an

the Federal Government also has adopted a policy

favoring expansion of utility IRP and DSM

programs and reaffirmed its support for development and commercialization of more energyefficient technologies.1

Efficient use of electricity and changes in the

electric power sector will play a vital role in any

strategy for achieving a more energy-efficient

society. If the threat of global climate change

prompts concerted action to reduce carbon emisimperative and a major overhaul of how energy

services are provided and paid for will be required

on a more accelerated schedule.

This report is part of the Office of Technology

Assessment (OTA) ongoing assessment of U.S.

Energy Efficiency: Past Trends and Future Opportunities. It examines mechanisms for achieving greater energy efficiency through electric

utility planning, operations, and regulation. In

particular, the report looks at the results of State

1 Public LllW 102486, 106 StaL 2776, Oct. 24, 1992.
and utility IRP and DSM programs. The report

also looks at the influence of State and Federal

regulatory policies on utility investments in

energy efficiency and presents a range of legislative policy options for encouraging energy efficiency through the electric utility sector.

ENERGY AND ELECTRIC UTILITIES

Electric utilities are important as energy users,

as providers of vital energy services, and as an

economic force in the U.S. economy. Electric

utilities are the Nation’s biggest purchaser of

primary energy supplies-coal, nuclear fuel, gas,

and oil. Utility power generation accounted for 36

percent of total primary energy use in the United

States or 29.6 quads in 1990.2

Energy efficiency improvements have slowed

electricity demand growth, but electricity use is

still increasing, Energy use for electric power

generation as a share of the Nation’s energy

consumption has been growing-faster than

growth in demand for other energy sources and

that trend is projected to continue. Electricity

demand growth over the past decade has slowed

from the high (7 percent/year) annual growth rates

that characterized the 1950s and 1960s to an

average of 2.3 percent/year in the 1980s.3

Projecting future electricity demand is a highly

uncertain art-adding to the risks that utilities

face in planning and building for the future.

Current estimates of 10-year electricity demand

growth range from 1 percent to 3.5 per year (see

figure l-l). Estimates of new powerplant construction needed to meet this new electricity

demand and replace retired units range from 56 to

221 gigawatts (a gigawatt is one billion watts) in

addition to the 700 gigawatts already installed.4

6000

5000

4000

Chapter l–introduction 3

Figure 1-1—Electricit y Demand Growth,

3000

2000

1000

0

1970-2010

billlons of kWh

- Low growth

‘-”A

/ ’

//”

m Mid-range

/

/

~ High growth /

/’

1970 1980 1990 2000 2010

SOURCES: Office of Technology Assessment, 1993, based on data

from U.S. Department of Energy, Energy Information Administration,

Annual Energy Outlook 7993, DOE/ElA-0383(93) (Washington, DC:

U.S. Government Printing Office, January 1993); and Edison Electric

Institute, “Meeting Electrcity Needs in the 1990s,” September 1991

(briefing paper prepared for the Strategic Planning Executive Advisory

Committee by Science Concepts, Inc.).

The U.S. Department of Energy uses a range of

about 80 to 100 gigawatts for the new capacity

needed by the year 2000--equivalent to construction of up to 100 new 1,000-megawatt coal-fired

powerplants. 5 The differences in the estimates of

new capacity needs reflect hundreds of billions of

dollars in new capital equipment costs to ratepayers.

Efficiency advocates have long maintained that

it is often cheaper for ratepayers and better for the

environment and society to save energy rather

than build new powerplants. This view is now

embraced by many utilities, regulators, shareholders, and customers. The energy efficiency

2 U.S. Department of Energy, Energy Information Administration, Annual Energy Review 1991, DOWEIA-0384(9 1) (Washingto~ DC:

U.S. Government Printing OffIce, July 1992), p. 15, table 5.

3 Edison Eleetric Institute, “Meeting Electricity Needs in the 1990s, ” September 1991 (brief~ paper prepared for the Strategic Planning

Executive Advisory Committee by Science Concepts, Inc.).

4 Ibid.

5 U.S. Department of Energy, Energy Information Administration, Amud Energy Outlook 1993, D0E/EIA-0383(93) (WashingtoIL DC:

U.S. Government Printing OffIce, January 1993).
4 I Energy Efficiency: Challenges and Opportunities for Electric Utilities

Figure l-2—impacts of Energy Efficiency Savings

Electricity demand

/’”) Market forces

and standards

Utility DSM

programs

Range of costeffective potential

Maximum technical

potential

1 9:o2000

This figure shows the different levels of projected energy

savings impacts depending on what measure of energy

efficiency is used.

SOURCE: Office of Technology Assessment, 1993, adapted from

Barakat & Chamberlinr Inc., Efficient Electricity Use: Estimates of

Maximum Energy Savings, EPRI CU-6746 (Palo Alto, CA: Electric

Power Research Institute, March 1990).

strategy is already shaping our future-initial

results are promising, but substantial uncertainties remain, and hundreds of billions of dollars are

at stake.

FINDINGS

1. There are significant opportunities for

cost-effective, energy efficiency savings

in all sectors of the economy.

Analyses by OTA and others have consistently found that there are numerous cost-effective

opportunities to use electricity more efficiently

and to avoid the costs and pollution associated

with new powerplant construction and still have

the same energy services-warm showers, cold

drinks, comfortable surroundings, and a vital

economy.

6

There is general consensus that the most

promising technical opportunities for achieving

more efficient use of electricity include:

improvements in the thermal integrity of

building shells and envelopes;

improvements in the efficiency of electric

equipment;

lighting improvements;

net efficiency gains from shifting energy

sources from fossil fuels to electricity (electrification); and

Optimization of electricity use through better

energy management control systems, shifts

in time of use, and consumer behavior and

preference changes.

Estimates of the amount of cost-effective

electricity savings that might be achieved through

full adoption of currently available efficiency

technologies vary, falling within a range of from

20 to 45 percent of present use by 2000 depending

on the study. This wide range in the estimates

reflects differing assumptions about technology

availability, adoption rates, and cost-effectiveness (see figure 1-2). The high estimates would

require replacing much of the entire stock of

electricity-using equipment with the mostefficient models available and would require

6 See the following reports by U.S. Congress, Of3ice of ‘lMmology Assessment: Energy Technology Choices: Shaping Our Future,

o’rA-E493 (Washington DC: Us. Gov emrnent Printing Office, July 1991); Changing by Degrees: Steps to Reduce Greenhouse Gases,

OTA-O-482 (Washington, DC: U.S. Government Printing Office, February 1992); Energy E@ciency in the Federal Government: Government

by Good ExampZe?, OTA-E-492 (WashingtorL DC: U.S. Government Printing O!Xee, May 1991); Building Energy Eficiency, OIA-E-518

(%%shingtou DC: U.S. Government Printing Office, May 1992); and Industrial Energy Eficiency, OTA-B560 (Washin@oW DC: U.S.

Govemment Printing OftIce, August 1993).

See also: National Energy Strategy: Powerjid Ideas for America, First Edition 1991/1992 (WashingtoKL DC: U.S. Government Printing

Ofi3ce, February 1991); American Council for an Energy-Eff’icient Economy and New York State Energy Office, The Achievable Conservation

Potential in New York Statefrom Utility Demand-Side Management Programs, Energy Authority Report 9018 (Albany, NY: New York State

Energy Research and Development Authority and New York State Energy OffIce, November 1990); Ameriean Council for an Energy-Efficient

Economy et al., America’s Energy Choices: Investing in a Strong Economy and a Clean Environment, (Cambridge, MA: The Union of

Concerned Scientists, 1991): and Arnold P, Fickett, Clark W. Gellings, and Amory B. IAwins, “Efllcient Use of El~trici~,” S~”en@c

American, September 1990, pp. 65-74.
Chapter I-Introduction ! 5

mobilizating of staggering amounts of capital to

finance the transition even though it would result

in significant long-term savings in energy costs.

Even without aggressive retrofitting and replacement of electric equipment, it is projected that

present trends in energy efficiency improvements

due to energy prices, standards, and technological

improvements, coupled with existing utilitysponsored resource planning, conservation, and

DSM efforts will result in about a 9 percent

reduction in electricity use by 2000 from what it

would be without the expected efficiency savings. 7 Utility DSM programs are expected to

offset about 14 percent of new electricity demand

growth over the next decade.8

There is general consensus among energy

analysts that we can cut electricity demand

growth further and maybe even produce a net

reduction in electricity demand over the next

several decades. Doing so clearly offers substantial benefits. We believe with wise implementation of cost-effective measures, they likely will

outweigh the costs and risks inherent in this

strategy.

2. Investments in energy efficient technologies offer significant benefits to electric

utilities and the Nation.

Improvements in energy efficiency through the

electric utility sector offer the promise of savings

for ratepayers and electric utilities, profits for

shareholders, and societal benefits to energy

security, international competitiveness, and environmental quality. Figure 1-3 illustrates the

potential contributions of energy efficient technologies to national interests.

Increasingly, utilities are finding that energy

efficiency programs make good business sense.

-’&-

A home energy audit in progress.

Investments in energy efficiency through demandside measures and enhancing the performance of

supply-side options can provide reliable, flexible,

and lower-cost alternatives to reliance solely on

conventional generating options. Efficiency contributes to improved load factors for existing

plants, reduces financial risks, and generates good

will among customers.9 In addition, energy efficiency improvements are becoming an important

strategy for environmental compliance by reducing emissions and qualifying utilities for additional emissions allowances under the acid rain

provisions of Clean Air Act Amendments of

1990. With the growth of State regulatory incentives for DSM investments, utilities are finding

that energy efficiency programs offer new profit

opportunities.

Improving the energy efficiency of electricity

use contributes to greater productivity, lower

energy costs overall, and more competitiveness in

the international marketplace for U.S. businesses.

Moreover, utility DSM investments tend to create

more job opportunities for lower-skilled workers

7 Barakat & Charnberl@ Inc., Estimating E#iciency Savings Embedded in Elecm’c Utility Forecasts EPRI CU-6925, Project 2788, Final

Report (Palo Alto, CA: Electric Power ResearchInstitute, August 1990). Electric Power Research Institute and Edison Electric Institute, Impact

of Demand-Side Management on Future Cmtomer Electricity Demand: An (@date, EPRI-CU 6953 (Mo Alto, CA: Electric Power Researc h

Institute, September 1990)

g MC Hirst, Electric Utility DSM-Program Costs and Effects: 1991-2001, ORNIXON-364 (Otik Ridge, TN: O* Ridge NatioK@

Laboratory, May 1993).

9 B~nt B~~r, “EneTgy Ei31ciency: Probhg th? Ltits,” EPRIJournai, March 1992, j)p. 14-21.
6 I Energy Efficiency: Challenges and Opportunities for Electric Utilities

Figure 1-3-Energy Efficiency and Energy-related National Policy Goals

SOURCE: Office of Technology Assessment, 1993, adapted from Energetics, Inc., Utility Enerrgy Efficiency Srategies: The Role of Effiency,

Productivity, and Conservation, EPRI CU-6272 (Palo Alto, CA: Electrie Power Research Institute, February 1989), p. 2-2.

than construction programs for conventional supply-

-side generation and transmission additions.10

DSM measures also can help reduce our oil

import vulnerability. Even though electric utilities today account for less than 5 percent of U.S.

oil demand, oil-fried generation remains an important resource in the Northeast, California,

Florida, and Hawaii. For utilities in these areas,

accelerating the implementation of DSM measures to displace oil-fired generation is a key

strategy for responding to potential oil import

disruptions. l 1

3. Electric utility energy efficiency programs can produce cost-effective energy

savings and help overcome economic,

institutional, and behavioral impediments

to investment in energy efficient technologies.

The potential of using the electric utilities

sector and utility regulation to spur changes in the

energy efficiency of America’s homes, schools,

and workplaces has captured the attention of

energy efficiency advocates, utilities, entrepreneurs, State regulators, Federal policymakers, and

consumers. Public utilities are well positioned to

promote the adoption of more energy-efficient

technologies. Their integrated operations, technical expertise, established ties to customers, and

familiarity with customer energy use equip them

with the technical skill, marketing tools, and

information to identify energy-savings opportunities. Their special status as regulated public

10 How~ (&gler, Jo~ ~icm, ~d Sfip ~~er, Energy Eficiency ad Job creation: The Employment and Income ~enefits from

fnvesting in Energy Conserving Technologies (Washington DC: The American Council for an Energy-Efficient Economy, October 1992).

II s= U.S. CoW~~, OffiWof~c~oloW As~ssmen~ U.S. Oil Import Vulnerability: The Technical Replacement Capability, 0~-E-503

(Washingto% DC: U.S. Government Printing Office, October 1991), chs. 2 and 3.
Chapter I-Introduction I 7

utilities offers access to capital, a relatively secure

cash flow, and a concomitant responsibility to

provide cost-effective and reliable service to their

customers. Their regulated status also makes

them attractive targets for policy initiatives in

pursuing energy efficiency, as it has in improving

environmental quality. Utilities are by no means

the only entities that can provide energy efficiency investments-the growth of energy service companies and energy management technology companies testify to this. Many of these

companies owe much of their market to opportunities created by utility programs and rebates.

Utility efficiency programs can work—

providing significant savings and profits for

utilities. Energy efficiency and utility demandside management and conservation efforts have

become big business. An estimated $2 billion was

invested by utilities in DSM in 1991 and this will

grow significantly in years to come.

Initial results have demonstrated that welldesigned and implemented utility energy efficiency programs can deliver sustained, reliable,

and cost-effective electricity savings. Despite this

promise, there have been early disappointments.

In many programs, participation rates have been

low and actual savings have been well below

cost-effective technical potential. In part this is

due to the fact that many utility programs are of

recent vintage and are still limited in scope.

Nevertheless, even the best programs have experienced gaps between technical potential and

actual savings. In coming years, utility programs

will have to narrow this savings gap and expand

the degree of customer participation in order to

make energy efficiency the true equal of new

generating units and other supply-side options in

meeting customer energy needs.

DSM programs entail some risks both in

technology and the associated regulatory changes:

that the savings will not be as high or as durable

as expected, or that consumers will be asked to

pay more than necessary to achieve them. DSM

programs and IRP methods are evolving to take

advantages of lessons learned and to target a

broader range of electricity saving opportunities.

The challenge is to assure that expanded utility

and State programs achieve their goals and that

Federal policies support, or at least not frustrate,

those objectives.

4. State and Federal Governments will play

key roles in overcoming the barriers and

constraints to utility energy efficiency

investments because of the regulated

nature of utilities and government’s influence over other sectors of the economy.

States and utilities are already well-advanced

in establishing energy efficiency programs. The

Federal Government has only limited direct

influence over utility resource decisions, demand

management programs, and retail operations.

Most of these matters are regulated at the State

and local level. Yet there is a strong Federal

interest in energy efficiency arising from the

importance of reliable and economic electric

power production to the economy, concerns over

the environmental impacts of power generation,

and the Federal Government’s roles as wholesale

power producer, utility regulator, and utility

customer.

Our future energy path will be determined by

choices made by utilities, consumers, regulators,

and government. If we choose to pursue the

energy efficiency alternative, success depends on

cooperation by utilities, acceptance by consumers, and institutional change. The States and many

electric utilities have already moved far ahead of

the Federal Government in direct initiatives for

more efficient electricity use through the utility

sector. There are, however, a number of areas

where the Federal Government can make a

contribution in encouraging the development and

availability of energy-efficient technologies for

electric utilities and their customers. Moreover,

Federal Government decisions in a number of

areas could signicantly affect the success and

cost-effectiveness of utility programs and investments.
8 I Energy Efficiency: Challenges and Opportunities for Electric Utilities

Federal policy options for encouraging greater energy efficiency; 2) continued support for comenergy efficiency through the electric utilities mercializing energy-efficient technologies

sector are discussed in chapter 2 of this report. through tough energy efficiency standards for

The overall strategies include: 1) support for buildings and equipment; and 3) support for

expanded IRP and DSM programs and other State energy efficiency research, development, and

regulatory incentives for utility investment in technology transfer activities.
.

T

he Federal interest in encouraging energy efficiency

throughout the U.S. economy rests firmly on three broad

national policy goals: economic growth, environmental

protection, and national security. The Federal Government has a long history of involvement in the utility sector, both

as a regulator and as the builder and operator of large power

systems. Following the energy crises of the 1970s, new Federal

laws and programs were established to support energy conservation activities, minimum energy efficiency standards, utility

regulatory reforms, and the research, development, demonstration, and commercialization of new and more environmentally

friendly technologies for generating electric power.

Improvements in energy efficiency through the electric utility

sector offer the promise of savings for ratepayers and electric

utilities, profits for shareholders, and societal benefits to energy

security, international competitiveness, and environmental quality. But, as discussed later in this report, the Federal Government

has only limited direct influence over utility resource decisions,

demand management programs, and retail operations. Most of

these matters are regulated at the State and local level. Yet there

are a number of areas where the Federal Government can make

a contribution in encouraging the development and availability

of energy-efficient technologies for electric utilities and their

customers. Moreover, Federal Government decisions in a number of areas could significantly affect the success and costeffectiveness of utility programs and investments.

This chapter discusses a range of legislative policy options for

encouraging greater energy efficiency through the electric

utilities sector. They include Federal policy options for supporting expanded integrated resource planning, demand-side management programs, and other State regulatory incentives for

utility investment in energy efficiency. The chapter also presents

options for new Federal energy efficiency standards for buildings

Policy

Issues

and

Options 2

I 9
10 I Energy Efficiency: Challenges and Opportunities for Electric Utilities

and equipment and greater support for efficiency in whole or in part in recently enacted legislation.

research and development and technology trans- We have noted some of these new provisions in

fer. the text and in box 2-A. The recently passed

This report was completed and sent to the legislation leaves many issues for subsequent

‘Technology Assessment Board before passage of Congresses. Decisions will have to be made about

the Energy Policy Act of 1992.1 The policy appropriations levels for newly authorized prooptions discussed include many that were adopted grams and the efficacy of agency implementation.

Box 2-A–The Energy Policy Act of 1992

The Energy Policy Act of 19921 was passed in October 1992 following 2 years of extensive legislative

consideration and debate. The act contains a wide range of Federal initiatives intended to Improve the energy

efficiency of the U.S. economy, encourage the commercialization of energy-efficient and renewable energy

technologies, reduce oil import vulnerability, and Iessen the environmental impacts of energy production and use.

Provisions that aid utility energy efficiency efforts are highlighted below.

Energy Efficiency Policy Goals

National energy policy plans submitted after 1993 must contain a national least-cost energy strategy to meet

the goals of increasing energy efficiency by 2010 by 30 percent over 1988 levels, expanding use of renewable

resources by 75 percent over 1988 levels, and reducing greenhouse gas emissions.

Integrated Resource Planning

State utility regulatory commissions must consider adopting standards requiring utilities to adopt integrated

resource planning (IRP).

The Tennessee Valley Authority (TVA) must establish a least-cost planning process to develop a resource

plan with the lowest system cost. The process must consider a full range of supply and demand resources,

including renewable resources, energy conservation and efficiency, and provide opportunities for involvement by

TVA distributors.

The Western Area Power Administration (WAPA) must require its long-term firm power customers to

implement IRP within 3 years. WAPA will provide technical assistance in developing IRP programs and review the

plans prepared. Utility resource plans must select options that minimize life-cycle costs, including adverse

environmental effects, and give priority to energy efficiency and renewable energy to the extent practicable. WAPA

may impose penalties for failure to file or carry out IRP. Special provisions are included to aid small utilities in

preparing resource plans.

DOE is to study the implementation of IRP and its impacts and report to Congress in 2 years.

Demand-Side Management

State utility regulatory commissions must consider standards giving utility energy efficiency investments a

return at least as high as that given supply-side investments.

Federal grants of up to $250,000 each to State regulatory commissions are authorized to encourage utility

demand-side management (DSM) measures and help weatherization grantees participate in State Ieascost

planning processes.

TVA is directed to provide technical and financial assistance to its distributors in the planning and

implementation of cost-effective energy efficiency options.

1 puMic bW 102-466, 106 Stat. 2776, Oct. 42, 1992.

1 Public bIW 102-486, 106 Stat. 2776, Oct. 24, 1992.
Chapter 2–Policy Issues and Options I 11

DOE will provide grants to States to promote industrial energy efficiency and utility industrial energy efficiency

programs.

Utility subsidies to residential customers for energy efficiency measures are granted an exemption from

Federal income tax and payments to commercial and industrial customers are made partially exempt.

Energy Efficiency Standards

Categories of electric equipment subject to standards are expanded to include: lamps; shower heads; electric

motors; commercial heating, cooling, and water heating equipment; and utility distribution transformers.

Existing Federal efficiency standards for appliances and fluorescent ballasts must be upgraded to the highest

levels that are technologically feasible and economically justified.

Federal energy testing and labeling requirements are expanded to cover light fixtures, office equipment, and

major consumer appliances, and to disclose Iife-cycle energy costs, usage, and comparisons to the most efficient

models. DOE will support industry efforts at voluntary ratings and labeling systems for windows, office equipment,

and lighting fixtures, however, mandatory Federal standards are to be issued if the private efforts fail.

Federal cofunding will be made available to set up 10 regional centers to demonstrate efficient lighting,

heating, cooling, and building technologies.

DOE will provide technical assistance to help States update and enforce commercial and residential building

codes to incorporate model industry energy efficienccy standards.

DOE will issue voluntary guidelines for home energy rating systems and provide technical assistance to local

officials.

The Department of Housing and Urban Development will establish a pilot program for energy-efficient home

mortgages for new homes and improvements in existing homes.

Energy Efficiency Research, Development and Demonstration

Many existing DOE programs are reauthorized as part of a 5-year program to increase the use of

energy-efficient and renewable technologies in the buildings, industrial, and utility sectors. Goals for the utility

sector are to accelerate the development of technologies that will increase energy efficiency and the use of IRP.

DOE is required to submit a plan for the 5-year program within 180 days of enactment.

Federal Energy Management

DOE must develop tough, new energy efficiency standards to be effective in 3 years for all new Federal

buildings. Federal agencies must install cost-effective, energy and water saving technologies by 2005.

Authorization and conditions for Federal agency participation in utility DSM programs and energy savings

performance contracts are clarified.

The Federal Energy Management Program is extended to the Congress and the U.S. Postal Service.

New public housing and new homes with Federal l-busing Administration and Veterans l-busing

Administration mortgages have to meet Federal energy efficiency standards.

Expanding Utility Resource Options

New wind or closed loop biomass energy systems may qualify for an income tax credit of up to 1.5 cents/kWh

generated for up to 10 years.

To encourage growth of independent power producers, qualifying wholesale generators are granted a new

exemption from the limitations of Public Utility Holding Company Act.

The Federal Power Act is amended to expand Federal Energy Regulatory Authority to order utilities to provide

transmission services to other utilities and power generators.
12 I Energy Efficiency: Challenges and Opportunities for Electric Utilities

Several significant utility-related issues were left

unresolved, especially in the delicate area of

conflicts in Federal and State jurisdiction over

utility planning on multistate systems, wholesale

power transactions, and their effects on retail

rates.

STRATEGIES FOR ENERGY EFFICIENCY

Efforts to harness the utility sector as a means

to achieve greater energy efficiency have focused

on three regulatory strategies: requirements for

adoption of utility integrated resource planning

(IRP), also called utility least-cost planning;

expansion of utility demand-side management

(DSM) programs; and rate reforms and other

regulatory incentives for utilities to invest in

energy-saving technologies. Programs for promoting energy efficiency through utility IRP and

DSM measures are already entrenched in many

States and are rapidly being developed and

implemented in many others. These State and

utility efforts could eventually involve the expenditure of billions of dollars of ratepayer funds.

These programs reflect a recognition that increasing the efficiency of energy use by consumers can

be a financially attractive and reliable alternative

to the addition of new energy supplies to meet

demand growth and a belief that tapping the

economic and technical resources of electric

utilities can be an effective strategy for speeding

the adoption of energy-efficient technology in all

sectors.

Initial results have demonstrated that welldesigned and implemented utility energy efficiency programs can deliver sustained, reliable,

and cost-effective electricity savings. Despite this

promise, there have been early disappointments.

Many programs have failed to achieve the significant electricity savings and high degree of participation needed to make DSM the true equal of

new generating units and other supply-side options in meeting customer energy needs. DSM

programs and IRP methods are evolving to take

advantages of lessons learned and to target a

broader range of electricity-saving opportunities.

The challenge is to assure that expanded utility

and State programs achieve their goals and that

Federal policies support, or at least not frustrate

those objectives.

Although energy efficiency through IRP was a

keystone of the Bush Administration’s National

Energy Strategy, Federal financial commitments

to energy efficiency are dwarfed by Federal

investments in conventional supply-side technologies (fossil and nuclear power) and in renewable

energy sources (see chapter 7). Part of the

disparity can be explained by the fact that electric

utility resource planning decisions and DSM

programs are matters largely within the purview

of State regulation and Federal regulatory influence is largely indirect. The Federal Government

clearly lags far behind the States in programs and

expertise in the utilities sector, particularly in the

areas of resource planning and DSM. Moreover,

at the same time, Federal policies and regulatory

initiatives are promoting both the growth of a

competitive bulk power sector that includes more

unregulated nonutility generators and greater use

of market-based rates in wholesale power contracts in place of traditional cost of service rates.

To the extent that utilities rely on wholesale

power purchases to supply future needs instead of

investing in their own plant and equipment,

Federal regulatory control over power supplies

will increase and State regulators’ influence over

power supply costs will diminish and so too will

their ability to enforce State-approved least-cost

plans unless there is a change in law at the Federal

level. 2

The Federal Government has provided modest

levels of financial support to State initiatives and

supported research on IRP and DSM through the

z The implications for greater cordlict between Federal and State regulation of electric power is discussed in detail in U.S. Congress, Office

of lkchnology Assessmen~ Electric Power Wheeling and Dealing: Technological Considerations for Increasing Competition, O’E4-E409

(Washingto~ DC: U.S. Government Printing Office, May 1989),
Chapter 2-Policy Issues and Options I 13

national laboratories. With the exception of

programs by the Bonnville Power Administration and, to a lesser extent, the Western Area

Power Administration, the Department of Energy

(DOE) and the Federal Energy Regulatory Commission (FERC) at present are ill-equipped to

provide substantive direction and technical support on increasingly sophisticated aspects of

utility resource planning and evaluation of DSM

efforts. New policy directions coupled with

modest funding support, would, however, improve Federal capabilities to further utility energy

efficiency programs and enhance cooperation

with State and local governments.

The primary strategies available to Congress to

advance energy efficiency through the utility

sector include:

■

9

■

m

9

■

Supporting, through Federal actions, expanded use of IRP, DSM programs, and State

regulatory initiatives to increase utility investment in energy efficiency technologies,

including legislation imposing new requirements on State regulators and electric utilities;

Providing Federal financial and technical

support to State regulatory agencies for

implementation of utility energy efficiency

initiatives;

Providing Federal support for research, development and demonstration of energy efficiency technologies and technology transfer

programs;

Strengthening and expanding Federal energy

efficiency standards and labeling and information requirements for a wider variety of

electric products and equipment;

Requiring the Federal Energy Regulatory

Commission to advance IRP and energy

efficiency in its direct regulatory responsibilities;

Requiring the Tennessee Valley Authority to

adopt IRP principles to guide its future

resource acquisitions (including investment

in cost-effective energy efficiency measures)

and to assist its customer utilities in developing IRP and DSM programs of their own;

Expanding the activities of Federal power

marketing administrations to support IRP

and DSM; and

Requiring the Federal Government to “lead

by example” by improving the energy efficiency of its buildings and operations and

participating in utility sponsored energy

efficiency programs.

The Energy Policy Act of 1992 includes

provisions that commit the Federal Government

to many of these strategies (see box 2-A). The

challenges now lie in the implementation of new

Federal policies and requirements. For Congress,

this means decisions over appropriations levels

for new energy efficiency initiatives and hard

choices over competing demands for Federal

funds in a time of financial difficulty and looming

budget deficits. Congressional oversight of the

pace and direction of agency implementation of

energy efficiency measures and the successfulness of these programs also plays a role in

assuring that the ambitious energy efficiency

mandate is attained. Even given the breadth and

detail of the recently passed energy act, there

remain, however, several areas where additional

legislation may be appropriate to further goals of

increased energy efficiency and greater use of

integrated least-cost planning methods.

Much of the success of these initiatives will

depend on how they are implemented and will

require continued congressional oversight and

support.

INTEGRATED RESOURCE PLANNING

IRP is a technique used by utilities and State

energy regulatory agencies to develop plans for

providing reliable and economic electric power

supply for customer needs. The process includes

explicit consideration of both supply-side and

demand-side resource options. The process begins with development of a range of projections

of future electricity demand under alternative
14 I Energy Efficiency: Challenges and Opportunities for Electric Utilities

future scenarios. Next, the planners assemble a

menu of potential resource options for meeting

those energy service needs including both supply-

-side resources (new generation, transmission and

distribution (GT&D) facilities, retrofit or improvement of existing GT&D facilities, and/or

bulk power purchhases) and Utility-Sponsored demandside resources (conservation, load management,

and end-use efficiency improvements). The lifetime capital and operating costs, availability,

reliability, and suitability of the various supplyand demand-side resource options are then compared to develop an overall plan to meet identified

future needs. There are several competing methodologies for defining what resource choices

constitute a “least-cost” mix. In developing a

least-cost plan, some planning processes require

that environmental externalities be quantified and

explicitly weighed in the resource selection

process, others give preferences to certain technology choices, i.e., locally produced coal, DSM,

low carbon emissions, or renewable resources.

The planning process usually includes public

participation and comment and may require

approval of State regulators before adoption.

After adoption, the plan is used to guide utility

choices in acquiring new resources.

Many utility analysts and energy-efficiency

advocates believe that, compared with past supplyoriented utility planning methods, IRP will favor

the selection of more cost-effective, more efficient, and more environmentally-friendly energy

technologies, including renewable energy technologies and demand-side options. Adoption of

an IRP process alone will not automatically

produce these results. What is even more important are the policy choices made in establishing

the goals and in weighing the costs, reliability,

and other attributes of alternative technology

choices in resource plans.

Adopting formal utility IRP processes has

certain clear effects that are usually deemed

positive by State regulators. First, the IRP process

opens up utility resource planning to review and

influence by the public, potential resource suppliers, and regulators. IRP creates a mechanism for

consideration of a wider variety of potential

resources and future planning contingencies than

might be the case under past internal supplyoriented utility planning procedures. Opening the

process creates opportunities for developing broader

consensus among utility decisionmakers, ratepayers, regulators, and other interested parties about

preferred strategies-perhaps lessening some of

the contentiousness of adversarial proceedings on

capacity and rates. Indeed, some States and

utilities have made collaborative consensusbuilding efforts a keystone of their overall IRP

process. Open planning will perhaps avoid some

of the problems of utility construction programs

of the 1970s when unneeded capacity and cost

overruns in a time of slower demand growth

produced protracted, bitter rate hearings and

disallowances of recovery for investments later

found to be imprudent. Rigorous and open

advance review of utility plans and periodic

reassessments also encourages more flexible

responses to changing conditions.

Among the potential disadvantages of broader

application of IRP among States and utilities are

the additional procedural burdens it could impose

on smaller utilities and State regulatory programs.

Many smaller investor-owned public power and

cooperative utilities may not have the resources,

personnel, or need to do extensive independent

IRP. Their needs could perhaps be as well served

by participation in State or region-wide planning

exercises. For some utilities and financial analysts, more open planning processes and State

IRP approvals may be perceived as diminishing

the utility’s control over resource choices. There

is no doubt that this is a goal of some IRP

proponents. However, for many utilities, adoption of IRP with its more explicit consideration of

planning uncertainties and inclusion of more

flexible supply and demand alternatives is a

natural response to the changes in the utility

operating environment in the 1980s and 1990s.

Expanded use of IRP will require some utilities to

use longer plarming horizons than previously, and
Chapter 2–Policy Issues and Options I 15

public and regulatory review will mean that

resource planning may take longer than when it

was a purely internal exercise. Offsetting this, of

course, is the expectation that implementation of

the plan will be smoother.

To encourage the expanded use of IRP, Congress could direct State regulatory agencies to

consider adopting rules requiring jurisdictional

utilities to use IRP. This option follows the

approach established by the Public Utility Regulatory Policies Act of 1978 (PURPA) and upheld

in the courts and avoids a direct clash between

State and Federal powers or preempting State

authority. State regulators can constitutionally be

directed to consider a proposed action within a

specific period of time, but the decision whether

to adopt IRP and the precise form it would take is

left to the States. The legislation might further

provide that States consider requiring that utility

investments in supply and demand-side resources

be consistent with the State integrated resource/leastcost plan. The Energy Policy Act of 1992, indeed,

took this approach and requires State regulators to

consider several policies under PURPA section

111 on IRP, DSM, and supply-side efficiency

investments.

More than half of the States have already

adopted some form of IRP requirement without

any Federal prodding-attesting to the attractiveness of the process to State regulators (see chapter

6). Many of the remaining States are already

considering IRP proposals. These developments

mean that utility IRP will grow even without

Federal legislation. A key issue in formulation of

added Federal requirements would be how existing State IRP programs should be treated. Should

State regulators initiate new proceedings to consider IRP anew, or would the legislation exempt

States that had already adopted plans? Imposing

new procedural requirements could divert scant

resources and personnel away from implementing

existing initiatives. Utilities, too, would likely

object to additional requirements. To minimize

this outcome, legislation could provide for States

to certify that they have already met the procedural requirements for IRP consideration.

The Federal Government could also provide

additional inducements for State adoption of IRP

with or without any direct Federal requirement for

formal State rulemakings to consider adopting

IRP.

Federal financial and technical support could

be provided for State development and

implementation of IRP/LCP requirements

through direct grants to State agencies, and

funding of cooperative research on IRP

methodology. This assistance could help

offset the impact on State agency budgets

and staffing of developing and implementing IRP programs. The Energy Policy Act of

1992 includes authorization for grants to

State regulatory agencies of up to $250,000

to implement various efficiency initiatives.

Congress could require that Federal actions

including FERC rulings be consistent with

State approved integrated resource plans. If

FERC rulings are not consistent with approved regional or State least-cost plans,

FERC actions should be subordinate to State

actions needed to implement these plans.

Congress could amend the Federal Power

Act to delegate more authority over wholesale rates and intrastate electric power transactions from the FERC to States that have

adopted IRP programs that meet certain

minimum Federal standards.

Congress could authorize States to enter into

regional compacts for purposes of developing and implementing integrated resource

plans for utilities that operate in more than

one State or that are members of multistate

tight power pools. Congress might further

require that utility resource plans be consistent with these regional or multistate plans.

The comprehensive energy legislation passed

in 1992 did not address issues of State and Federal

regulation involving resource planning. Various
16 I Energy Efficiency: Challenges and Opportunities for Electric Utilities

proposals to clarify respective roles in regional

planning and to close the regulatory gap created

by recent developments have been offered. (See

chapter 3.)

DEMAND-SIDE

DSM refers to

affect the timing

MANAGEMENT

utility-led programs intended to

or amount of customer electricity use. These include energy efficiency programs

aimed at reducing the energy needed to serve

customer needs and programs that shift electricity

demand to reduce peak loads or to make more

economic use of utility resources. A variety of

DSM mechanisms are in effect, including audit

and information programs, rebates and other

consumer financial incentives, direct installation

programs, technical assistance, and energy performance contracting.

Utility DSM programs are rapidly proliferating

in extent and cost. Estimates of current annual

utility DSM expenditures range from several

hundred million dollars to almost $2 billion. One

large California utility is poised to spend $1

billion on energy efficiency investments over the

next decade and is awaiting the blessing of the

State public utility commission. Equally ambitious efforts are being mounted in other jurisdictions as utilities announce plans to meet a

significant portion of their demand growth in the

1990s through energy efficiency.

DSM programs have had mixed success to

date. Many have delivered dramatic electricity

savings at low cost-demonstrating their promise. However, many other programs have had low

rates of customer participation, produced actual

energy savings that were less than predicted, and

lacked adequate evaluation and verification of

energy savings over time (see chapters 5 and 6).

For energy conservation and efficiency to become

true alternatives to supply side resources, DSM

efforts will have to be expanded in size and to a

wider range of end-use applications, customer

participation rates will have to increase, and

actual savings will have to be closely monitored

and evaluated.

There are several options available for Federal

encouragement of utility DSM programs.

Congress could direct State regulatory commissions to consider requiring their jurisdictional utilities to establish or expand costeffective DSM programs.

The Federal Government could provide additional financial and technical assistance to

State agencies in developing, implementing

and evaluating utility demand-side management programs. These could take the form of

direct grants to State agencies, funding of

cooperative research and demonstration program, sponsorship of training programs for

State regulatory personnel, collection and

dissemination of information on various

State and utility DSM measures and their

effectiveness.

As noted, the Energy Policy Act of 1992 does

require States to consider financial incentives for

DSM and conservation investments under PURPA,

and authorizes Federal grants to State agencies.

The legislation does not establish any new

Federal program to aid in research and development and training in DSM evaluation.

U.S. DEPARTMENT OF ENERGY

PROGRAMS

The DOE Integrated Resource Planning (IRP)

Program, which has primary responsibility for

advancing IRP and DSM, has a modest budget of

a few million dollars and a very small staff. The

program originally was established in response to

congressional initiatives; its mission is to provide technical assistance and support on utility

planning issues including DSM. It has primarily

served as a conduit for funds to support research

efforts at national laboratories, sponsor conferences, and provide small grants for cooperative

efforts. Overall, the program results to date have

received praise from utilities, regulators, and

efficiency advocates. The growth of IRP and
— ——

Chapter 2–Policy Issues and Options I 17

DSM programs and the more sophisticated technical challenges they present for State regulators

are rapidly outstripping the low budgets, modest

research efforts, and limited expertise of the IRP

Program. Despite the high profile given to electricity efficiency in DOE’s energy policy pronouncements and budget submissions, the size and

activities of the IRP office indicate the low

priority actually attached to supporting utility IRP

and DSM (see chapter 7). If Congress wishes

DOE to provide leadership and support to State

efforts and provide needed imputs to national

energy policy debates, the IRP Program will have

to be expanded and given adequate resources to

establish a strong institutional presence to advance IRP and other utility energy efficiency

programs.

There are clear opportunities for the Federal

Government to be involved in research, development, and demonstration (RD&D) activities to

advance utility efficiency initiatives. Utilities are

funding significant amounts of resource independently and through the Electric Power Research Institute. Continued cooperative efforts

with Federal agencies and national laboratories

should be encouraged. The potentially large

amounts of funds at stake in utility demand-side

programs suggest that Federal policymakers and

State regulators also have a need for independent

and impartial assessments of IRP methods, DSM

programs, and alternative regulatory incentives

for efficiency investments. DOE-sponsored research can serve this public need by expanding

RD&D efforts on DSM, supply-side efficiency

technologies, IRP, conservation and load management methodologies, and on energy efficiency

estimation, metering, monitoring, and evaluation

technologies. Such research should include engineering, behavioral, and policy studies to assist

improvement of DSM and IRP efforts. The

research could be funded by redirecting a small

portion of funds now devoted to supply technologies. opportunities for joint funding of research

by the Federal Government, State agencies,

utilities, trade associations and other interested

parties could also be authorized and would allow

leveraging of Federal research dollars.

UTILITY RATE REFORMS

Under traditional approaches to utility ratemaking, utility profits are based on sales of kilowatthours of electricity and total investment in

generating, transmission and distribution equipment (see chapters 3 and 6). Almost without

exception, every additional kilowatt-hour sold by

a utility yields a profit.3 Investments that promote

energy efficiency and reduce electricity consumption, lower sales and threaten profits. States

are currently experimenting with various regulatory mechanisms to decouple utility sales from

profits and to make efficiency investments more

attractive to utilities and their shareholders as

detailed in chapter 6. To support these State

efforts, Congress could:

Direct DOE to expand funding for research

on model State utility regulations and innovative ratesetting mechanisms such as decoupling profits from power sales, time of day

pricing, interruptible rates, and performance

incentives for efficiency; research results

should be made widely available.

Establish a DOE-supported multidisciplinary resource center to assist State regulators

and utilities in developing and implementing

innovative rate reforms and in evaluating the

results.

Provide grants to States for experiments in

developing, implementing and evaluating

innovative rate structures to encourage costeffective supply and demand-side energy

efficiency investment by utilities.

Congress could also follow the precedent of

PURPA and direct States to consider the adoption

3 David Moskovi@ Profits and Progress Through Utility Least-Cost Planm”ng (Washington DC: National Association of Regulatory

Utility Commissioners, 1989).
18 I Energy Efficiency: Challenges and Opportunities for Electric Utilities

of ratemaking mechanisms that provide utilities

with financial incentives for implementing costeffective efficiency improvements and the Energy Policy Act of 1992 does this. Again, more

than half of the States have already adopted some

financial incentives for utility demand-side efficiency investments. Congress, could of course go

further and require that State regulators adopt rate

procedures that make demand-side efficiency

improvements at least as profitable for utilities as

investments in new supply-side resources. This

direct, and obviously preemptive approach would

likely be viewed with disfavor by many State

regulators who believe that the choice of a proper

incentive is a matter of State policy. Some

consumer representatives would likely argue that

such provisions could distort rates unnecessarily

as utilities are already under some obligation to

invest in cost-effective efficiency measures as a

means of minimizing rates whether or not they are

as profitable for shareholders as new generating

plants.

FEDERAL REGULATION OF

POWER TRANSACTIONS

While much Federal influence over utility

planning and State ratemaking policies is indirect,

there are three areas where the Federal Government can directly influence utility resource planning

1.

2.

3.

and energy efficiency investments:

FERC regulatory authority over wholesale

power transactions and transmission arrangements.

Operation of five Federal power marketing

administrations that supply power to local

utilities and oversight of the operations of

the Tennessee Valley Authority.

Rural Electric Administration loans and

loan guarantees to electric cooperatives.

The Federal Government can provide leadership

in adoption of IRP and cost-effective energy

efficiency investments through its established

regulatory and administrative authority in these

areas.

The extent to which FERC on its own initiative

and as a matter of policy could require utilities

engaged in wholesale power transactions and

multistate holding companies to develop integrated resource plans is not clear, even if FERC

were inclined to do so (see chapter 3).4 FERC has

used its conditioning authority to induce utility

compliance with various FERC economic policy

initiatives, most recently open transmission access. Under the recent policy directions of FERC

toward greater reliance on competition and marketbased prices, it seems unlikely that the commission would advance new policies that would

involve it more deeply in consideration of the

details of resource planning and least-cost determinations of utilities that are either purchasing or

selling power. Current FERC electricity policies

could actually work to increase disincentives to

investment in DSM. FERC could, however, use

its rate design authority to eliminate biases

against investment in DSM by wholesale power

providers and purchasers. As a practical matter,

FERC is largely bereft of the expertise that would

allow it to pass on the merits of utility resource

plans and DSM programs. Even if FERC does not

become involved in promoting IRP and demandside management, its preemptive jurisdiction

over wholesale transactions and cost allocations

in multistate holding companies has the potential

to frustrate State initiatives at least-cost planning

and DSM.

As mentioned above, if Congress wishes to

support State implementation of IRP and DSM

programs it could amend the Federal Power Act

to require that FERC decisions be consistent with

State-approved integrated resource/least-cost plans.

To accomplish this, FERC could be directed to

revise its procedures so that State regulators and

other interested parties can effectively participate

d The Federal Power Act provides that FERC has no authority to order utilities to expand generating facilities or to buy or exchange power

(16 USC 824f).
Chapter 2–Policy Issues and Options I 19

in wholesale proceedings to make regional or

local interests known to the commission.

In the late 1980’s the Tennessee Valley Authority (TVA) has discontinued its energy conservation and DSM programs and began to look at

the need for adding new generating capacity in the

later 1990s to meet the needs of its customers.

Congress could require that TVA develop and

implement its own least-cost planning program to

direct its future resource acquisition strategies. It

further could authorize and require TVA to invest

in demand-side resources where it is costeffective to do so as an alternative to construction

of new generating capacity. TVA could also be

directed to require its customer utilities to adopt

IRP processes and to certify that purchases are in

compliance with their plans. TVA could be

directed to reestablish its programs in support of

energy efficiency and conservation and provide

technical assistance in these areas to its customers. The Energy Policy Act of 1992 does just this

and requires TVA to adopt a least-cost planning

program including participation by its distributors and the public.

Congress could require that the Federal power

marketing administrations adopt an IRP approach

and require their customer utilities to adopt IRP as

a condition of power contracts. Under existing

law, the Bonneville Power Administration already engages in extensive regional power planning and must give preference to conservation

and renewable resources in its power procurement

(see chapter 7). The Western Area Power Administration has already embarked on a regulatory

effort to require its customers to engage in limited

IRP as a part of its power supply contracts. The

Energy Policy Act of 1992 incorporates much of

this into statute. The much smaller Southwestern

Power and Southeastern Power Administrations

have not yet implemented planning or energy

efficiency programs directed at their customers.

Southwestern is cooperating with Western in

development of programs and materials to help

customer utilities implement IRP. Legislation

has been introduced to approve the sale of the

Alaska Power Administration.) Design of IRP

and DSM requirements for power marketing

administration customers must be done with care

and sensitivity to the small size and limited

resources of many public power utilities and

cooperatives, and potential for Federal requirements overlapping with conditions imposed under

State regulation.

Congress could require that cooperatives seeking REA loans or guarantees for new generation

facilities demonstrate that they have adopted an

IRP process that includes explicit consideration

of energy efficiency alternatives and that the

proposed facility is consistent with the least-cost

plan. REA has already moved in this direction by

rule. Legislation could reinforce and make permanent such conditions for REA transactions. Again,

caution must be exercised in the design of

requirements because of the size of many cooperatives and the possibility of overlap with State

and other Federal agency requirements.

LEADING BY EXAMPLE: THE FEDERAL

GOVERNMENT AS ENERGY CONSUMER

The Federal Government is the Nation’s largest

single energy consumer, in fiscal year 1989 it

spent over $8.7 billion on direct energy purchases

for its own facilities and operations and about $4

billion more subsidizing the energy expenses of

low-income households under various programs.

Not reflected in this direct energy expenditure of

some $12.7 billion are the additional energy costs

for leased space for which the Federal Government does not pay utilities directly. Payments to

electric utilities accounted for an estimated $2.4

billion of the fiscal year 1989 Federal energy bill

for government buildings.

The Office of Technology Assessment’s (OTA)

May 1991 report, Energy Efficiency in the Fed-
20 I Energy Efficiency: Challenges and Opportunities for Electric Utilities

eral Government: Government by Good Example,

5 found that despite a wide array of

programs and policies developed over the past 15

years, the Federal Government still has many

opportunities to improve energy efficiency in its

facilities and operations using commercially available, cost-effective measures. OTA estimated that

total Federal Government energy consumption

could be cut by 25 percent with no sacrifice to

comfort or productivity. There are many measures with potential returns of 30 to over 100

percent. OTA’s report found that existing Federal

programs and present funding levels maintain

program capabilities and will yield gradual improvements in Federal energy efficiency. However, the status quo is not sufficient to capture

significant savings opportunities. At the present

low level of energy efficiency funding and

staffing for individual agencies, OTA estimated

that it would take several decades to make all the

economically attractive investments. During that

time tens of billions of dollars would be unnecessarily spent to buy inefficiently used energy.

The Energy Policy Act of 1992 toughens

energy efficiency standards for Federal buildings,

sets a new deadline of 2005 for Federal agencies

to install cost-effective, energy- and water-saving

technologies, and contains a number of other

measures to raise agency awareness and financial

commitments to energy efficiency improvements.

Nevertheless, taking full advantage of existing

opportunities will require a higher priority for

energy efficiency as reflected in adequate investment funding and staffing. One alternative is

private sector financing in the form of utility

rebate programs and shared energy-savings contracts that can be used to supplement direct

Federal investments.

OTA found significant benefits associated with

Federal actions to support energy efficiency.

Setting a good example by demonstrating the

cost and performance of a wide range of

energy-efficient technologies and practices

in its own facilities and operations,

Creating market pull for energy-efficient

goods and services through Federal purchasing power and promoting earlier introduction

of high-efficiency technologies by specifying the most cost-effective energy efficiency

products. 6

Providing first-hand experience basis for

national energy policy on the technical and

cost performance of energy efficiency measures from Federal projects.

Cutting Federal spending through energy

efficiency savings; and

Reducing the environmental, health and

security costs of energy use. Among the

congressional policy options for making the

Federal Government a leader in advancing

cost-effective energy efficiency measures

are several that would encourage Federal

agency participation in utility-sponsored demand management programs.

Congress could use its oversight and appropriations processes to press Federal agency managers to give greater priority to funding and

staffing to achieve the variety of existing congressional and presidential directives to cut building

energy use and improve energy efficiency in

operations. A 1991 Executive Order calls for a

reduction in Federal building energy use by at

least 20 percent by 2000 compared to 1985 and

greater participation in utility DSM services.7

Congress could provide clear authorization and

direction for Federal agencies to participate in

utility demand management programs and shared

s U.S. Congress, Office of Ikchnology Assessment, Energy E#iciency in the Federal Government: Government by Good Example,

OTA-E-492 (w&lSh@tOQ ~: U.S. (hWIU13 ent Printing OffIce, May 1991).

b For e-le,about 10 percent of residential appliances are used in federally assisted or Owned houh.g unit% but W PUthMd by private

individuals. Ibid., p. 106.

T Executive Order 12759, Apr. 17, 1991.
energy savings contracts, to accept payments,

services, and goods associated with such energy

efficiency programs, and to incur obligations for

financing of efficiency measures. Confusion over

agency eligibility and authority to enter into

utility demand management programs was found

to have deterred participation. Congressional

legislation has already been enacted that specifies

that Federal agencies (principally the Department

of Defense and the General Services Administration may enter into shared energy savings contracts for federally-owned buildings and facilities. 8 The Energy Policy Act of 1992 expands that

authority and specifically encourages agencies to

participate in utility programs and to negotiate

with local utilities for demand-side management

programs specially tailored to the needs and

characteristics of government facility loads.

Federal agencies could themselves become

purveyors of energy efficiency savings to meet

utilities’ resource needs. Many Federal facilities

would be attractive targets for energy efficiency

savings under utility programs seeking costeffective demand-side resources. Federal facilities managers should be authorized to enter

agreements with energy services companies or

directly with utilities to offer these potential

resources in competitive procurements. Under

such arrangements, utilities might install efficiency measures directly, the agency might pay

for the measure and receive a rebate for some or

all of the costs of the measures, or an energy

service company would install the measure and

recover its costs and profits from the utility. Such

agreements at a minimum should provide that

Federal payments for efficiency measures do not

exceed the value of electricity bills that would

have been due if the measure had not been

installed.

Congress could assure that agencies devote

sufficient funds and competent well-trained personnel to oversee and administer energy effiChapter 2–Policy Issues and Options I 21

ciency efforts, including those funded in whole or

in large part by private funds through utility

demand management programs or agreements

with energy service companies. Several provisions of existing law and executive order attempt

to do that through the budgeting process and

reporting requirements.

As an additional incentive agencies could be

allowed to keep some or all of the proceeds from

energy efficiency rebates for either general program activities or for additional energy efficiency

measures. Existing law authorizes retention of a

portion of such energy savings in DOD facilities

and allows them to be used for recreation.

Technical support could be provided to agency

energy efficiency coordinators/personnel to aid

them in identification of efficiency opportunities

and provide assistance in negotiations with local

electric utilities and energy service companies.

These might include establishment of several

regional model or demonstration energy efficiency facilities.

OTA’s report on the Federal Government

experience suggests that rewards for good performance in agency energy efficiency measures

would also aid both agency management and

energy efficiency staff deterrnination in capturing

possible savings. In addition to the prior suggestion that agencies be allowed to keep all or a

portion of savings, additional incentives might

include establishment of well-publicized agency

citations or awards for energy efficiency savings

and bonuses for individual energy managers.

Improving the energy efficiency of Federal

buildings and operations will require a long-term

commitment and many novel approaches to new

situations. It will be important that efforts be

periodically evaluated and that successes and

failures alike be analyzed and the results distributed among public and private energy managers

so that needed modifications can be made,

successes shared and failures avoided.

8 Comprehensive Omnibus Budget Reconciliation A@ Public Law 99-272, Title VIII, 100 Stat. 42, Apr. 7, 1986.
22 I Energy Efficiency: Challenges and

SUPPORTING ENERGY-EFFICIENT

TECHNOLOGIES

Opportunities for Electric Utilities

Federal support for improvements in the availability of energy-efficient equipment in the marketplace can complement utility energy efficiency programs. In addition to creating a market

pull for efficiency by creating incentives for

utility investment in DSM measures, Federal

efforts can create a market push to raise the

efficiency of new products.9

H Information, Labeling and

Efficiency Standards

Among possible approaches is strengthening

and expanding Federal efficiency standards and

labeling and consumer information requirements

applicable to buildings and to household and

commercial appliances, fixtures, and electrical

equipment. These actions provide consumers

with more information on energy use and can

require that new buildings and products incorporate cost-effective efficiency technologies.

The Energy Policy Act of 1992 contains a

number of provisions relating to increasing the

efficiency of electric equipment. Specifically, it:

Expands Federal energy efficiency standard

legislation to major categories of electric

equipment including: lamps; shower heads;

electric motors; commercial heating, cooling, and water-heating equipment; and distribution transformers.

Requires existing Federal efficiency standards for appliances and fluorescent ballasts

to be raised to the highest levels that are

technologically feasible and economically

justified.

Adopts expanded Federal energy testing and

labeling requirements for light futures, office equipment, and major consumer appliances, including life-cycle energy costs and

usage and comparisons to most efficient

models.

The major share of residential and commercial

energy use is for heating, cooling, lighting and

providing hot water to buildings. Improving the

energy efficiency of buildings offers significant

opportunities for energy savings. Options for

expanding and enforcing energy efficiency standards for buildings include:

■

■

■

✘

■

Developing and applying energy efficiency

rating systems for new and existing commercial and residential buildings.

Requiring DOE to work with national professional and trade associations to develop

strengthened energy efficiency standards for

new buildings to reflect the best costeffective energy savings practices.

Encouraging States to adopt these standards

as part of State building codes and assisting

them in strengthening building code compliance and enforcement procedures.

Requiring sellers to provide information on

energy efficiency features and energy use of

buildings.

Requiring compliance with the new Federal

standards for federally assisted housing,

mortgage guarantees, and Federal facility

housing.

The success of such information, labeling and

standards programs will require at least four

conditions to be met. First, adequate funding and

technical expertise must be available to develop

standards for technically achievable and costeffective energy-efficient technologies in a timely

fashion and to revise them periodically to reflect

technical advances. Second, mechanisms must be

put in place to educate Federal, State and local

officials, architects, manufacturers, wholesalers,

equipment installers, and construction trades

about new requirements. Third, monitoring and

enforcement mechanisms need to be established

Q Mrious Federal market push policy options and the effectiveness of past Federal efforts are discussed in detail in U.S. Congress, Office

of lkchnology Assessment Building Energy Eficiency, OTA-E-5 18 (Washington, DC: U.S. Gov ernrnent Printing OfIke, May 1992).
Chapter 2—Policy Issues and Options 123

and adequately funded and staffed to backup the

new standards. Lastly, the programs must be

periodically evaluated to assess their effectiveness (including review of quantitative indicators

of energy savings, costs, ease of administration,

alternative implementation methods), improvements needed, and the continuing need for

government involvement. Continuing congressional oversight and support will be key to assure

that the new initiatives will be successful in

attaining their goals.

H R&D and Technology Transfer

Federal programs promoting efficiency initiatives through the utilities sector are limited in

scope and funding. Most federally supported

efforts have been targeted at the buildings and

industrial sector and weatherization assistance for

institutions and low-income consumers. Between

1980 and 1990, Federal spending on conservation

and efficiency technologies and programs was

slashed. Only congressional steadfastness kept

many programs alive. Funding of efficiency

research and development has begun to rise.

However, most of the DOE research and development funds allocated as promoting electricity

efficiency in budget documents actually support

conventional fossil technologies, nuclear power

and nuclear waste disposal programs.l0 Less than

0.5 percent of the non-defense DOE research and

development budget went to programs to improve

energy efficiency in the utilities sector.

The Federal Government support for research,

development, demonstration and commercialization

activities can advance the availability of energyefficient supply-side and demand-side technologies. For example, the DOE Clean Coal program

could be redirected to give more preference to

technologies that improve powerplant efficiency

and reduce environmental impacts of burning

coal. Similar objectives can be applied to funding

of other advanced electric power technologies

offering significant efficiency gains. (for example, advanced generating technologies such as

advanced gas turbines, and fuel cells, improvements in automation, monitoring, and dispatch

controls, and high-efficiency transmission and

distribution technologies.) Efforts should be directed at technologies for new construction and

for retrofitting/repowering old generating plants.

Research efforts should yield information on the

performance characteristics, and the

operating costs of these technologies

more available to State regulators

planners.

capital and

to be made

and Utility

INCREASING UTILITY RESOURCE OPTIONS

A wider range of cost-effective supply- and

demand-side resources will increase potential

benefits to utilities and customers from the full

implementation of IRP. Proponents of greater

competition in electric power supplies contend

that competition will bring market forces to bear

to force greater efficiency in resource selection

and in the development of new power technologies. Allowing demand-side measures to compete

against supply-side options can help foster selection of more cost-effective efficiency alternatives

to new powerplant construction.

Utility resource planning and supply acquisition have largely been matters of State jurisdiction. However, if as seems likely, expanded

competition results in more wholesale power

transactions, Federal authority over resource acquisition will increase. This enlarged influence

could hinder rather than encourage efficiency

gains if utility transactions receive Federal approval without regard to State least-cost plans.

I Expanding Competition

Congress could increase competition either

directly or through FERC by:

10 G~~~ Accounting OffIce, “Energy R&D: DOE’s Prioritization and Budgeting Process for Renewable Energy Research”

GAO/RCED-92-155, April 1992, pp. 13-16.

330-075 : QL 3 0 - 93 - 2
24 I Energy Efficiency: Challenges and Opportunities for Electric Utilities

Requiring utilities to acquire new power

resources through competitive procurement

mechanisms and requiring the inclusion of

demand-side options in the competition.11

Amending the Public Utility Holding Company Act (PUHCA) to encourage participation in bulk power and energy efficiency

industries by broader group of potential

suppliers.

The Energy Policy Act of 1992 creates a new

exemption to PUHCA for entities engaged in

wholesale generation markets. The exemption is

applicable to utility affiliates.

i Transmission Access

Increased access to the transmission grid has

been advocated as a means to expand utility

resource options and to open additional markets

for capacity and electricity made available

through efficiency efforts. Greater access to

transmission facilities increases opportunities for

power producers to sell power and for buyers to

choose from a potentially greater variety of sellers

and a wider range of generating options. Among

options Congress could consider for encouraging

more open transmission access are:

Authorizing voluntary transmission-sharing

mechanisms through regional agreements

and joint planning among all prospective

transmission users—both utilities and independent generators-under nondiscriminatory guidelines to be established by the

FERC.

Requiring the FERC to consider conditioning approval of special rate treatment, mergers, etc. on the petitioning utilities offering

expanded non-discriminatory access to their

transmission services.

Providing additional Federal authority to

require utilities to provide transmission services with protection for system reliability

and native customer loads.

Directing the FERC to defer to State efforts

to improve transmission access and transmission services by State jurisdictional utilities unless the State efforts were found to be

unjust, unreasonable, or to confer undue

competitive advantage.

The Energy Policy Act of 1992 gave FERC

explicit authority to order transmission access for

wholesale transactions. The controversial details

of pricing policies and information requirements

to carry out this mandate have been left to FERC

and progress on these matters will have to be

monitored to determine if additional mechanisms

are needed. Many utilities have been pressing for

legislative approval for organization of voluntary

regional transmission groups as a more flexible

alternative to mandatory wheeling orders.

LEVELING THE PLAYING FIELD

IN RESOURCE PLANNING

Because most energy prices do not reflect all of

the social and environmental costs of particular

energy choices, many economists and energy

analysts believe that market-based mechanisms

alone cannot be relied upon to produce the most

efficient options from a social, environmental,

and economic perspective. (A similar imperfection is also introduced by the tax and other

“subsidies” that some fuels enjoy.)

1 Energy Taxes

One way of correcting such market failures

would be to impose taxes on various energy

sources that reflected the costs they imposed on

society and the environment. In fact, in Europe

and Japan, high energy taxes perform this function in some respects. Energy taxes have proven

to be a controversial and unpopular approach for

attaining energy policy goals in the United States.

Recently, there has been renewed interest in

energy taxes, not only as a means to promote

energy and environmental policy goals via the

11 see o~$~ ~t.Pn E[ec~ic power Wheeling and Dealing: Technological Coruideration.rfor Increased competition, ~pra note 2.
Chapter 2–Policy Issues and Options I 25

‘‘market-based mechanisms’ currently in vogue

among some policy analysts, but also as a means

of increasing Federal revenues to reduce budget

deficits. The Clinton Administration’s Btu tax

proposal would have imposed a small tax on a

broad range of energy sources, but was rejected

by Congress in favor of an increase in the

transportation fuels tax.

I Internalizing Social and

Environmental Costs

An alternative to energy taxes is to use a

surrogate price adjustment in the resource planning process so that relative costs of energy

options are more adequately reflected and energy

choices compete on a more level playing field.

One method, for example, would be requiring that

States and utilities include consideration of social

and environmental costs/’ ‘externalities’ in evaluating supply- and demand-side resources in

developing least-cost plans. Including adjustments for externalities in the plannin g process

avoids most of the political and economic impacts

of direct energy taxes, while offsetting market

imperfections in energy choices. Many conservation and renewable energy advocates believe that

consideration of externalities in cost-effectiveness determinations would boost prospects for

these options being selected in utility resource

plans. However, some economists would say that

the choice of a perhaps higher-priced energy

option would impose a hidden environmental/

social energy tax.

Consideration of externalities in resource choices

is already required in many States, but experience

is limited and the State efforts have proved highly

contentious and politically controversial. Moreover, economists are deeply divided over whether

and how to fashion mechanisms to internalize

such costs in energy decisionmaking. Some

States, such as Massachusetts and California,

have attempted to set a specific quantitative value

on external environmental costs to be used in

evaluating competing resource choices, while

other States have opted for a more qualitative

approach. Various legislative proposals have

been made that would require Federal agencies

and utilities to consider life-cycle costs of energy

options, including environmental and social costs

and benefits to the maximum extent possible, in

developing least-cost energy plans.

Whatever the conceptual difficulties of attempting to include externalities in integrated

resource planning, as a practical matter State

regulators and utilities are already doing it to

some extent and proposals for expanding this

approach to other States and Federal actions will

increase. Given experience to date, there is no

clearly preferred or accepted method of addressing the externalities problem. This suggests that

any Federal action to require explicit quantification of externalities is premature. Congress could

direct DOE to support research on alternative

methods for assessing and quantifying environmental, social, and other externalities in least-cost

planning and to report back on the experience to

date, additional research needs, and the feasibility

of including external costs in Federal least-cost

planning.
E

nity to

Industry Structure,

Regulation,

and Operations 3

lectric utilities occupy a unique place in the U.S.

economy. Their activities touch virtually everyone.

Their regulated status as public utilities imposes special

responsibilities in return for assurances of the opporturecover their costs, and for investor-owned utilities, to

earn a reasonable return on their investments. Maintaining the

reliable operation of the Nation electric power systems requires

a high degree of cooperation and coordination among sometimes

competing utilities and adherence to stringent performance

standards. Yet, there is great diversity in the structure and

organization of the industry. The recent growth of unregulated,

independent power producers and pressures from consumers and

regulators for greater utility investment in electricity-saving

technologies pose new challenges for utility operations and the

regulatory compact.

This chapter provides

sector. It begins with a

an overview of the electric utilities

look at utility energy use, financial

characteristics, environmental considerations, and an overview

of industry structure. Next, it gives a brief introduction to State

and Federal regulation of electric utilities. It concludes with an

overview of utility system operations.

ELECTRIC UTILITIES IN THE US. ECONOMY

@ Energy Use

Electric utilities are among the Nation’s biggest energy users

and energy producers. Utility power generation accounts for 36

percent of total primary energy use in the United States or 29.6

I 27
28 I Energy Efficiency: Challenges and Opportunities for Electric Utilities

Figure 3-1—U.S. Primary Energy Use,

1970-91 (quadrillion Btus)

100 I

■ Electric utilities

80 ❑ Total primary energy

i 970 1975 1980 1985 1 99(

SOURCE: Office of Technology Assessment, 1993, based on data

from U.S. Department of Energy, Energy information Administration,

Annual Energy Review 1991, DOE/ElA-0384 (91) (Washington DC:

U.S. Government Printing Office, June 1992).

quads in 1990.1 (See figures 3-1 and 3-2.) Energy

use for electric power generation as a share of the

Nation’s total energy consumption has been

growing-faster than growth in demand for other

energy sources—and that trend is projected to

continue.

Utility fuel demand strongly influences the

growth and structure of primary energy markets.

In 1990 energy inputs for providing electricity

accounts for virtually all nuclear power, 86

percent of coal use, 15 percent of natural gas, 3

percent of oil consumption, and over 40 percent

of renewable energy production.2

Of the 29.6 quads of energy input to electric

utilities to produce power, only 9.3 quads were

delivered to retail customers as electricity.3 On

Figure 3-2—U.S. Primary Energy Consumption by

Sector, 1990 (quadrillion Btus)

Utility power generation 36%

Industrial 24°A

19.9

Residential &

commercial 12% Transportatio l

on bwl I II 1

2 7 %

SOURCE: Office of Technology Assessment, 1993, based on data

from U.S. Department of Energy, Energy Information Administration,

Annual Energy Review 1990, DO/EIA-0384 (90) (Washington, DC:

U.S. Government Printing Office, May 1991), p. 5.

average only 31 percent of the primary energy

input to electric power generation and transmission is available/delivered to meet customer

needs. The rest is lost to inefficiencies in power

generation processes-heat loss, incomplete combustion, and transformer and line losses in transmission and distribution. Thus, even modest

gains in the efficiency of electricity production

and delivery systems could make significant

contributions to improving overall energy efficiency. And the impacts of demand-side electricity savings are magnified when they are translated

‘ U.S. Department of Energy, Energy Information AdministratioIA Anruud Energy Review 1991, DOE/EIA-03S4(91) (Washington DC:

U.S. Government Printing OffIce, July 1992) p. 15, table 5, hereinafter DOE, Annuul Energy Review 1991. Because electricity can be

considered an energy carrier, the means by which the energy content of fuels, falling water, sunlight, etc. is captured and converted to electricity

that is then used to power other activities or energy serviees, electric utilities are at times categorized as energy producers rather than energy

consumers. As a result, electric utilities would be omitted from profiles of energy consumera, and the primary energy inputs used by them to

generate electricity is alkated proportionately to end-use sectors.

2 DOE, Annual Energy Review 1991, supra note 1, various tables.

3 Ibid.
Chapter 3-Electric Utility Industry Structure, Regulation, and Operations I 29

Tables 3-1—SeIected Utility Statistics

by Sector, 1990

Figure 3-3-Electricity Sales by Sector

(billion kWh)

Sales to ultimate consumers (billion kWh). . . . . 2,713

Residential. . . . . . . . . . . . . . . . . . . . . . . . . . . . 924

Commercial. . . . . . . . . . . . . . . . . . . . . . . . . . . 751

Industrial. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 946

Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 92

Revenue from sales to ultimate consumers

($billion). . . . . . . . . . . . . . . . . . . . . . . . . . . . . 178

Residential. . . . . . . . . . . . . . . . . . . . . . . . . . . . 72

Commercial. . . . . . . . . . . . . . . . . . . . . . . . . . . 55

Industrial . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 45

Other*. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6

Average revenue/kWh (cents). . . . . . . . . . . . . . . 6.6

Residential . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7.8

Commercial. . . . . . . . . . . . . . . . . . . . . . . . . . . 7.3

Industrial. ..,.. . . . . . . . . . . . . . . . . . . . . . . . 4.7

Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.4

Emissions (million short tons)b

Sulfur dioxide (SO2). . . . . . . . . . . . . . . . . . . . . 16.5

Nitrogen oxides (NOx). . . . . . . . . . . . . . . . . . . 7.1

Carbon dioxide (C02). . . . . . . . . . . . . . . . . . . . 1,976.3

a includes public street and highway lighting, other sales to public

authorities, sales to railroads and railways, and interdepartmental

sales.

bincludes only those power plants with a fossil-fueled, steam-e

nameplate capacity (existing or planned) of 10 or more megawatts,

NOTES: Data on capabliity, generation, consumption, stocks, receipts,

and costs of fossil fuels for 1990 are final; other 1990 data are

preliminary. Totals may not equal sum of components because of

independent rounding.

SOURCE: Office of Technology Assessment, 1993, based on information in U.S. Department of Energy, Energy Information Administration,

Electric Power Annual 1990, DOE/EIA-0348(90) (Washington, DC:

U.S. Government Printing Office, January 1992).

into avoided fuel

supply side.

I Revenues and

Electricity sales

electric utilities an

and capacity savings on the

Capital Investments

and capital investments make

influential force in the economy. In 1990, consumers paid over $179 billion

for electric power. 4 Table 3-1 and figure 3-3 show

power sales and revenues by customer class, The

retail cost of electricity varies significantly among

the customer classes. Industrial customers generally are charged less per kilowatt-hour (kWh)

Commercial 28°/0

753

/

/ ’ ”

/

35%

‘\x=’’’’’0’h~030’0

Resldentlal 34%

922

SOURCE: Office of Technology Assessment, 1993 based on data from

U.S. Department of Energy, Energy Information Administration, Annual

Energy Review 7990, DOE/ElA-0384 (90) (Washington, DC: U.S.

Government Printing Office, May 1991), table 94, p. 215.

than residential or commercial customers. Utilities justify this on the basis of lower costs

incurred to serve industrial customers with large

loads and often a single point of delivery,

compared with residential service characterized

by many dispersed customers with relatively low

individual electricity sales volumes and higher

associated transmission and distribution investment and electricity losses per kilowatt-hour sold.

Lower prices are also justified to maintain market

share and to discourage industrial customers from

leaving the system by turning to natural gas or

self-or cogeneration for energy needs—which

could result in stranded investment costs that

must be borne by remaining customers in the form

of higher rates.

On a national average, the nominal price of

electricity in 1990 was 6.6 cents/kWh, up from

4 Public Power, Amual Statistical Issue, vol. 50, No, 1, January-February 1992, p. 56.
..———

30 I Energy Efficiency: Challenges and Opportunities for Electric Utilities

Figure 3-4-Average Retail Electricity Prices,

Nominal and Real (1987 dollars)

Cents/kWh

87

Real

I 1

6-

4-

+--’ + Nominal

I + Real (1987$)

I

, ‘

0! 1 r 1 [ I I 1 1 I I 1 I [ 1 1 I I 1 1 1 (

1970 1975 1980 1985 1990

SOURCE: Office of Technology Assessment, 1993, based on data

from U.S. Department of Energy, Energy Information Administration,

Annual Energy Review 1991, DOE/EIA-0384 (91) (Washington, DC:

U.S. Government Printing Office, June 1992), table 102, p. 229.

4.7 cents/kWh in 1980. However, real electricity

prices have, on average, declined during the last

decade (as shown in figure 3-4). Adjusting for

inflation, average retail electricity prices in 1990

of 5 cents/kWh are 10 percent less than they were

in 1980.5

The utility industry is highly capital-intensive.

Investor-owned utility capital investment in plant

and equipment was valued at $379 billion in

1990. 6 Total assets of public power systems and

rural electric cooperatives were estimated at

$125.8 billion in 1990.7 Estimates of new construction spending for investor-owned utilities

were some $26.3 billion in 1990 according to one

industry survey.8 The largest share of this capital

investment, $13.6 billion, was earmarked for

transmission and distribution construction and

improvements; only $8.9 billion was for building

new generating plants-a shift from the massive

new powerplant construction expenditures of the

1970s and early 1980s.

1 Environmental Impacts

Electric power generation is a significant

source of air pollution and carbon dioxide (CO2

)

emissions and thus has been a focus of environmental protection and cleanup efforts. In 1990

electric utilities’ fossil-fired steam electricgenerating plants spewed 16.5 million tons of

sulfur dioxide (SO2), 7.1 million tons of, nitrogen

oxides (NOX), and 1,979 million tons of carbon

dioxide into the air.9 According to data collected

by the U.S. Environmental Protection Agency

(EPA), burning of sulfur-laden coal and residual

fuel oil by electric utilities accounted for over 80

percent of SO2 emissions in 1989.10 Electric

utilities also were the source of some 60 percent

of NOX emissions in that year, Electric generation

is responsible for about 35 percent of total carbon

emissions in the United States and electric

utilities account for almost all of these emissions.

11 Any strategy to limit carbon emissions to

offset threats of global climate change will of

5 DOE, Annual Energy Review 1991, supra note 1, p. 229, table 102.

s ‘‘SWcl~ Report: 191 AILINMI Statistical Report Utility Construction stirs M NUG PIWM Grow, ’ Electrical World, April 1991, pp. 9-14.

See atso U.S. Department of Energy, Energy Information khninistratio~ Financial Stati”sfi”cs of Selected Investor-Owned Elecm”c Utilin”es,

DOE/EIA-0437(90)/l (WsahingtoQ DC: U.S. Government Printing (Mce, January 1992).

7 U.S. Department of Energy, Energy Information Administration Financial Statistics of Selected Publicly Owned Electric Utilities 1990,

DOE/ELA-0437(90)fl (Washington DC: U.S. Government Printing Off3ce, February 1992).

8 Electrical World, supra note 6, p. 9.

s DOE, Annual Energy Review 1991, supra note 1, p. 227, table I(K).

10 us. ~v~men~ ~otation Age~y, wlce of &r Quality Planning and Standards, Nafi”onal Air PoZlutant Emission Esthwes

1940-1989, EPA-450/4-91-004, March 1991. According to the same repofi utility emissions of sulfur oxides in 1989 would have km

approximately 60 percent higher without the installation of pollution control equipment required by the Clean Air Act.

11 See U.S. CoWess, Oflke of ‘EChnOIOw Assessrnen4 Changing by Degrees: Steps to Reduce Greenhouse Gases, O’IA-0482

(Washington DC: U.S. Government Printing Office, February 1991), p. 8.
Chapter &Electric Utility Industry Structure, Regulation, and Operations I 31

necessity target electricity generation—and increase the attractiveness of energy efficiency

alternatives through demand-side management

(DSM).

The Federal Clean Air Act required installation

of pollution controls at electric generating plants,

reducing emissions and spurring the development

of cleaner, state-of-the-art powerplants. Stringent

new acid precipitation provisions of the Clean Air

Act Amendments of 1990 will require electric

utilities to make further reductions in their

emissions of SO2 and NOX starting in 1995. These

requirements will fall most heavily on Eastern

and Midwestern utilities now burning high sulfur

coal and potentially involves billions of dollars in

new investment in control technologies to be paid

for by ratepayers. One potential result could be

the accelerated retirement or life-extending repowering of older plants. The 1990 Amendments

also offered utilities another option for compliance. The option was to buy emissions allowancesa kind of license to pollute-from other utilities

who have reduced their emissions below required

levels, This innovative ‘market-based’ approach

to environmental regulation-a new system of

tradable pollution allowances-was included in

the 1990 acid rain amendments and provides a

further spur to utilities to install pollution control

equipment, participate in integrated resource

planning, and invest in energy efficiency in their

operations. 12 The amendments established the

Conservation and Renewable Energy Reserve to

award additional emission allowances to utilities

that cut emissions by installing electricity-saving

DSM measures or by using renewable energy

resources.

13

In addition to air quality impacts, other environmental effects associated with electric power

generation are the extraction and processing of

fossil and nuclear fuel; construction and operation

of hydroelectric, geothermal, solar, and wind

facilities; and waste to energy plants. 14 Siting,

construction, and operation of the plants can

create local land-use conflicts, congestion and

noise impacts on neighbors, and adverse impacts

on natural habitats and wildlife. Power generation

contributes to water and waste pollution. Nuclear

power and handling and disposal of nuclear waste

also entail a special set of serious, contentious,

and long-term environmental issues because of

the radiation hazards. Opportunities to use energy

more efficiently are also opportunities to avoid

associated environmental impacts of energy production.

Electric power transmission and distribution

also have associated environmental impacts beginning with local land-use conflicts in the siting

of power lines and substations. The construction

phase contributes to erosion, soil compaction,

destruction of forests and natural wildlife habitat

in the right of way. During operation, nuisance

effects include visual impacts, audible noise,

corona effects, and interference with radio and

television reception. Transmission systems can

have deleterious effects on local bird life through

collisions with powerlines and towers and electrocutions. Use of chemical herbicides and other

vegetation management techniques along rights

of way raises concerns about ecological impacts

in some areas. In recent years, the as-yetunproven possibility of human health effects from

exposure to electric and magnetic fields has

12 ~bfic LAW, 101-549, sec. 404(f), Nov. 15, 1990, 104 Stit. 2601,42 U.S.C. 7651c(t_).

13 See ch. 7 of this report.

14 Enviro~en~ impacts of electric utility activities are S ummarized in ch. 7 of U.S. Congress, OffIce of Technology Assessment, Electric

Power Wheeling and Dealing: Technological Options to Increase Competition, OTA-E-409 (Washington, DC: U.S. Government Printing

Office, May 1989), hereinafter OTA, Electric Power Wheeling and Dealing.
. —. -— -

32 I Energy Efficiency: Challenges and Opportunities for Electric Utilities

become a prominent concern in siting transmission and distribution facilities.l5

1 Industry Structure

Electric utilities are the largest component of

the electric power industry, a diverse patchwork

of investor and publicly owned utilities; consumer cooperatives; Federal, State, and local

government agencies; cogenerators; and independent power producers. The distinguishing

characteristic of most electric utilities is that they

are regulated monopolies that sell power to retail

customers.

America’s more than 3,200 regulated electric

utilities supply electricity to over 110 million

households, commercial establishments, and industrial operations. The differences among utilities in size, ownership, regulation, customer load

characteristics, and regional conditions are important for policy. Table 3-2 shows selected

statistics for the electric utility sector by type of

ownership. Utility ownership and location determine regulatory jurisdiction over utility operations and rates.

Investor-Owned Utilities

The 267 investor-owned utility (IOU) operating companies dominate the electric power

industry, generating 78 percent of the Nation’s

power in 1990 and serving about 76 percent of all

retail customers. IOUS are private, shareholderowned companies ranging in size from small local

operations serving a customer base of a few

thousand to giant multistate corporations serving

millions of customers. Most IOUS are vertically

integrated, owning or controlling all the generation, transmission, and distribution facilities required to meet the needs of the customers in their

assigned service area.

IOUS can be found in every State except

Nebraska. Their local operations and retail rates

are usually highly regulated by State public utility

commissions, however their wholesale power

sales and wheeling (power transmission) contracts fall under the jurisdiction of the Federal

Energy Regulatory Commission (FERC).

Control over IOUS is further concentrated

because many of them are actually subsidiaries of

utility holding companies. Nearly one-quarter of

the IOU operating companies are subsidiaries of

registered electric utility holding companies regulated under the Public Utility Holding Company

Act of 1935 (PUHCA) by the Securities and

Exchange Commission and FERC. The following

are registered utility holding companies: Allegheny Power System, Inc., American Electric

Power Co., Central and South West Corp.,

Eastern Utilities Associates, General Public Utilities Corp., Entergy Corp., New England Electric

System, Northeast Utilities, and The Southern

Co. In addition to the registered holding companies, many other utilities are also part of holding

company systems consisting of affiliated utility

subsidiaries operating intrastate or in contiguous

States and, thus, are exempt from detailed oversight under PUHCA.

Publicly Owned Electric Power Systems

The more than 2,000 public power systems

include local, municipal, State, and regional

public power systems ranging in size from tiny

municipal distribution companies to giant systems like the Power Authority of the State of New

York. Publicly owned systems are in operation in

every State except Hawaii. Together, local public

power systems generated 9 percent of the Nation’s power in 1990 but accounted for 14 percent

of total electricity sales, reflecting the fact that

15 U.S. CoWss, offiw of ‘llxhnoIogy ksesrnen~ Biological Effects of Power Frequency Elecoic and Magnetic Fields, Bmkground

Paper, O-IA-BP-E-53 (wSshingtou DC: Us. Gov ernment Printing OflIce, May 1989). Several epidemiologic studies have been published

suggesting a link behveenmagnetic field exposures in the vicinity of local distribution lines and increased risk of childhood cancer. Pubtic health

concerns have resulted in increased researeh funds for investigating this possible heatth hazard in hopes of determining what risks, if any, exist

and how tbey might be mitigated. In the meantime, utility commissions and utilities are now increasingly including assessments of ekxtric and

wetic field exposures @d field r~uction ~te~tiv= in the consideration and approval of new tmnsmission facilities.
Table 3-2—U.S. Electric Utilities, Selected Statistics, 1990

Revenues from

Sales to sales to ultimate Installed generating Net

Ultimate consumer a

ultlmate consumers consumers capacity generation’

Type of utility Number Millions Percent Billion kWh Percent $billions Percent G W

b

Percent Billion kWh Percent

investor-owned. . . . . . . 267 84 76 2,071 71 140 79 529 77 2,203 78

Publicly ownedd. . . . . . 2,011 15 13 386 14 23 13 71 10 245 9

Cooperatives. . . . . . . . . 953 12 11 201 7 14 8 25 4 126 4

Federal e. . . . . . . . . . . . 10 <1 0 55 2 2 1 65 9 235 8

Total. . . . . . . . . . . . . . . 3,241 111 2,713 178 690 2,808

a Ultimate consumers in most instances are retail customers.

b GW, or gigawatt, is 1 billion watts.

c Includes 116 biIlion kWh purchased from nonutility generators.

d Publicly owned utilities are IocaI nonprofit government agencies including municipal, public power districts, irrigation districts, State power authorities, and other State organizations.

e Federal utilities include the electric power Operations of the Federal power marketing administrations and the Tennessee Valley Authority.

SOURCE: Office of Technology Assessment, 1993, based on information from the U.S. Department of Energy, Energy Information Administration, Electric Power Annual 1990, DOE/EIA

0348(90) (Washington, DC: U.S. Government Printing Office, January 1992).

-.

-.

<

%? tg

F

- .

“2
. ——

34 I Energy Efficiency: Challenges and Opportunities for Electric Utilities

many public systems are involved only in retail

power distribution and purchase power supplies

from other utilities.

The extent of regulation of public power

systems varies among States. In some States the

public utility commission exercises jurisdiction

in whole or part over operations and rates of

publicly owned systems. In other States, public

power systems are regulated by local governments or are self-regulated. Municipal systems

are usually run by the local city council or an

independent board elected by voters or appointed

by city officials. Other public power systems are

run by public utility districts, irrigation districts,

or special State authorities.

Rural Electric Cooperatives

Electric cooperatives are electric systems owned

by their members, each of whom has one vote in

the election of a board of directors. They can be

found in 46 States and generally operate in rural

areas. In 1990, rural co-ops accounted for 4

percent of total power generation and 7 percent of

sales to ultimate customers.

Congress created the Rural Electrification Administration (REA) in 1935 to bring electricity to

rural areas and subsequently gave it broad lending

authority to stimulate rural electricity use. Cooperatives have access to low-cost govemmentsponsored financing through REA, the Federal

Financing Bank, and the Bank for Cooperatives.

Early REA borrowers tended to be small cooperatives that purchased wholesale power for distribution to members. Over the past 20 years, however,

many expanded into generating and transmission

cooperatives in order to lessen their dependence

on outside power sources.

Regulatory jurisdiction over cooperatives varies among the States, with some States exercising

considerable authority over rates and operations,

while other States exempt cooperatives from

State regulation. In addition to State regulation,

cooperatives with outstanding Federal loans fall

under the jurisdiction of REA, which imposes

various conditions intended to protect the financial viability of borrowers.

Federal Power Systems

The Federal Government is primarily a wholesaler of electric power produced at federally

owned hydroelectric facilities and has less than

25,000 retail customers directly served by its

systems. Together, Federal systems had an installed generating capacity of approximately 65

gigawatts (GW) and accounted for 8 percent of

the Nation’s power generation in 1990. All

Federal power systems are required under existing legislation to give preference in the sale of

their output to other public power systems and to

rural electric cooperatives.

Federally owned or chartered power systems

include the Federal power marketing administrations, the Tennessee Valley Authority, and facilities operated by the U.S. Army Corps of Engineers, the Bureau of Reclamation, the Bureau of

Indian Affairs, and the International Water and

Boundary Commission. Wholesale power is marketed through five Federal power marketing

agencies:

1.

2.

3.

4.

5.

Bonneville Power Administration,

Western Area Power Administration,

Southeastern Power Administration,

Southwestern Power Administration, and

The Alaska Power Administration.

The Tennessee Valley Authority is an independent government corporation that sells power

within its statutory service area. Jurisdiction over

Federal power systems operations and the rates

charged to their customers is established in

authorizing legislation. More on these Federal

utility systems can be found in chapter 7 of this

report.

ELECTRIC POWER REGULATION

The electric utility sector is one of the most

heavily regulated industries in the U.S. economy

with virtually all aspects of power generation,

transmission, and distribution under the oversight
Chapter 3-Electric Utility Industry Structure, Regulation, and Operations

of State and/or Federal agencies. Like other

businesses, the electric power industry is subject

to laws and regulations governing financial transactions, employment practices, health and safety,

and environmental impacts. But unlike other

businesses, as a public utility, it (along with

segments of the natural gas, telecommunications,

and transportation industries) is subject to additional economic regulation. Economic regulation

of public utilities encompasses organizational

and financial structure, prices (rates), profits,

allocations of costs, franchise territories, and

terms and conditions of market entry and exit—

matters that for unregulated entities are normally

determined by management discretion and market forces. Economic regulation of public utilities

is exercised by Federal, State, and local bodies.

Which regulatory body has controlling jurisdiction typically depends on the type of utility, the

transaction involved, and State and Federal law.

It is not at all unusual for both State and Federal

regulators to be involved in review of some utility

decisions.

9 The Concept of a Public Utility

Public utilities enjoy a special status under

State and Federal law because their activities

provide vital services to businesses and communities (sometimes phrased as “affected with the

public interest”). This status confers specific

rights and obligations and distinguishes them

from most other business enterprises. Generally,

a public utility has an obligation to:

■ serve all customers in its service area (within

its available capacity limitations);

■ render safe and adequate service, including

meeting foreseeable increases in demand;

I 35

serve all customers within each service class

on equal terms (i.e., with no unjust or undue

discrimination among customers); and

charge only a‘ ‘just and reasonable price for

its services.l6

In return for assuming these obligations, the

public utility enjoys certain “rights.” First, the

utility has a right to reasonable compensation for

its services, including a profit on capital investment to serve the public. Second, through its

franchise and certificate of public convenience

and necessity, the utility generally is protected

from competition from other enterprises offering

the same service in the same service territory.

Third, the public utility has a right to conduct its

operations and render service subject to reasonable rates and regulations. Finally, in many States

public utilities can exercise the right of eminent

domain to condemn and take private property for

public use where necessary to provide adequate

service, subject to the requirement of just compensation to the owner. 17

Both State and Federal laws define any entity

that sells electricity as a public utility,18 thus

bringing generators and retail distributors of

electricity under regulation, unless provided with

an explicit exception. Jurisdiction over the activities of electric utilities is split between the Federal

Government and State agencies (including local

governments). This division reflects both the

historical growth of electric utility regulation in

this country, which began at the State and local

level, and the Federal Government’s constitutional authority over interstate commerce. Many

utilities are now directly or indirectly subject to

both Federal and State rate regulation.

lb ~les F. fitiips, Jr., The I?egu[crtiotl Of Public Utilities: Theory and Practice (Ad@toIL VA: Public Utilities RCPOm, k., 1984), p.

106.

17 Ibid., p. 107.

18 me definition of a electric utility in the Federal Power Act 1S: “any person or State agency which sells electric energy, ” 16 U.S.C.

7%(22), and the deftition of ‘electric utility company’ in the Public Utility Holding Company Act is ‘‘any company which owns or operates

facilities used for the generation transmission or distribution of electric energy for sale, ” 15 U.S.C. 79b(a)(3).
-. --- - . . -. — . . - -

36 I Energy Efficiency: Challenges and Opportunities for Electric Utilities

H State Regulation

State regulation of electric power is diverse,

but four broad generalizations can be made about

the form and extent of government oversight

exercised .19

1.

2.

3.

4.

State regulatory jurisdiction over utility

rates and operations is typically vested in

independent multimember boards or commissions whose members are either appointed or elected.

State (or local government) regulators control market entry by granting certificates of

public convenience and necessity to electric

utilities--creating what are usually monopoly franchise territories.

All States regulate retail prices of electricity. In setting retail rates, State regulators

must approve a level that covers the utility’s

cost of providing service and a reasonable

rate of return to the utility and its shareholders. Under various formulations, many

States require that utility investments be

determined to be prudent and “used and

useful” before they can be recovered

through retail rates. Some States allow

recovery for plants under construction, while

others defer recovery until the plant is

actually in operation.

State regulators also exercise control over

utility securities (e.g., stock issuance, stock

classifications) and financing arrangements

(bonds, loans, and other debt transactions).

This oversight was instituted because of the

historical abuses by public utility holding

companies and was intended generally to

prevent use of utility assets for nonutility

ventures and to protect the financial integrity of the utility.

The extent of State commission jurisdiction

over utilities varies. Some States regulate all

utilities, including public power systems and

cooperatives, while others limit jurisdiction to

investor-owned systems and leave regulation of

municipal systems to local governments.

Many States also regulate other aspects of

utility operations in some detail, including the

planning and determination of resource needs

such as new generation, bulk power purchases,

and construction of transmission and distribution

facilities.20 A number of States regulate the siting

of utility facilities either through the public utility

commission or a separate siting agency .21

In some States public utility regulators have a

more general mandate to protect and/or promote

the public interest and welfare. This mandate has

been interpreted as supporting other policy goals

for utility regulation, such as economic development, universal electric service, minimum levels

of service at equitable or affordable rates, and

environmental protection.

RETAlL RATE REGULATION

Regulators establish the rates charged to customers, as well as their view of appropriate profit

levels for utilities, through administrative proceedings. Under the most common ratemaking

approach-variously referred to as rate-of-return

regulation or cost-of-service regulation or traditional rate regulation-the utility commission

sets retail rates based on estimates of the expected

costs of service to meet projected customer

demand (i.e., kilowatt-hour sales).

19 For a mom de~]~ d.i~~sion of !$~te and Federal utility regulation, see Congressional Research Service, Elecm”city: A NWRegzdutory

Order? Committee on Energy and Commerce, U.S. House of Representatives, 102d Cong., 1st sess,, Committee Rint 1O.2-F, June 1991.

m For a summary of State requirements for utility planning and forecasting requirements, see Public Utilities Commission of the State of

Ohio, Transmission Line Cemj7cation and Siting Procedures and Energy Planning Processes: Summary of State Government Responses to

a Survey by the National Governors’ Association Task Force on Efecm”city Transnu”ssion, contractor report prepared for the Office of

Technology Assessmen4 July 1988.

21 For more ~om~oq see the d~ussion of Swe si~ requirements in ch. 7 of OTA Electric Power Wheeling and Dealing, SUpm

note 13.
Chapter 3-Electric Utility Industry Structure, Regulation, and Operations I 37

Box 3-A-The Revenue Requirement

A utility’s revenue requirement is the total number of dollars required to cover its operating expenses and to

provide a fair profit. This rate setting method is sometimes called the fair return on fair value rule. The revenue

requirement is often expressed in a formula:

RR= OE + CD + (OC + 1- D)r

Where

RR. the revenue requirement (total dollars to be raised);

OE = operating expenses (e.g., fuel, maintenance, salaries, benefits, taxes, and insurance);

CD= current depreciation (on utility plant and equipment);

OC = original cost of capital employed in service to the public, sometimes partly adjusted for inflation;

I = Improvements in capital employed;

D - accumulated depreciation (in the value of capital employed); and

r. rate of return (percent earnings on the value of the capital employed in the business set by the regulators taking

into account the utility cost of equity and debt capital, performance, and returns on similar investments).

In the above formula:

(OC-I-D) = rate base (net valuation)

(OG-I-D)r = profit expressed as earnings on the rate base.

SOURCE: Office of Technology Assessment, 1993, adapted from Congressional Research Service, Electricity:A New Regulatory Order?

Committee on Energy and Commerce, U.S. House of Representatives, 102d Cong., 1st sess., Committee Print 102-F, June 1891, p. 137,

citing Jones and Tybout, "Environmental Regulation and Electric Utility Regulaton: Compatibility and Conflict,” Boston College Law

Review, vol. 14, 1986, pp. 43-44 (1986).

Retail rates are typically set based on the

utility’s revenue requirement, i.e., the estimated

revenues required to cover operating expenses.

These expenses include: administrative, financing, and marketing costs; personnel, fuel, maintenance, purchased power, and other operating

costs; plus recovery of capital investment in the

rate base (plant and equipment committed to

public service less depreciation). A percentage

profit (rate of return) on all investments included in the rate base is also included in the

revenue requirement for investor-owned utilities.

(See box 3-A.) What capital investments are

included in the rate base and what expenses are

allowed are left to the broad discretion of

regulators, as is judgment of what is a fair and

reasonable rate of return. The utility too has some

leeway in allocating expenses and capital costs in

its submissions for ratemaking. State policies and

regulations differ in formulations of matters

included or recoverable through rates, including

treatment of construction work in progress (investment in facilities that are not yet in operation).

There are also variations in classes of customers,

and related issues such as the availability of basic

or lifeline rates for low-income customers.

After establishing the revenue requirement,

State regulators must then determine how those

funds will be collected from customers-referred

to as the rate structure or the rate schedule. The

revenue requirement is divided by estimates of

expected sales to yield the rate per kilowatt-hour
38 I Energy Efficiency: Challenges and Opportunities for Electric Utilities

that is used to calculate the customer’s bill.

Typically, different rates are established for

different classes of customers. The rate design for

each class must yield a price (per kilowatt-hour)

that will produce sufficient revenue to cover the

costs of serving that class and contribute to

meeting the overall revenue requirement. Rates

are revised periodically to reflect changes in

utility investments and performance and general

economic conditions.

Because fuel prices can vary considerably in

response to market conditions, most States have

a separate fuel adjustment clause, a mechanism

intended to insulate utilities from fuel price

swings. The automatic fuel adjustment clause

allows utilities to raise or lower fuel charges on

customer bills to follow fuel costs as they are

incurred instead of waiting for a rate case.

There is no single approved constitutional

method of ratemaking. The U.S. Supreme Court

has held that the Constitution gives States broad

discretion to decide which rate-setting mechanism best meets their needs in balancing the

interests of the utility and the public.22 The rate

base method for determining just and reasonable

rates for public utilities as long as they are not

confiscatory was upheld by the Supreme Court in

Hope Natural Gas Company v. Federal Power

Commission .23

With utility profits under traditional ratemaking based on the total value of capital invested and

the amount of power sold, many analysts have

concluded there is a tremendous financial incentive for utilities to invest heavily in capitalintensive plant and equipment and to sell as much

power as they can at prices above their cost of

Service. 24This incentive is counterbalanced by

the threat of penalties and disallowances by their

regulators. For example, regulators have developed certain general principles limiting investments included in the rate base:

Negligent or wasteful losses that are the fault

of the utility management cannot be included

as operating charges.

Investments must be prudent--i.e., reasonable under ordinary circumstances and at the

time made. Recovery of costs from uncontrolled cost overruns, construction mismanagement, or plant abandonment can be disallowed as imprudent.

Some States further specify that the plant must

actually be in service to the public to qualify for

inclusion in the rate base.*

A utility’s profits from electricity sales are

supposed to reflect regulators decisions about

appropriate returns on prudent capital investments in rate base. While regulatory authorities

cannot force a utility to operate at a loss, recovery

of a utility’s authorized rate of return is not

guaranteed. At times, the utility may not actually

earn its authorized rate of return because of

adverse economic conditions, poor business judgment, or because regulators overestimated actual

sales. If a utility sells fewer kilowatt-hours than

projected in the rate case, its actual revenues will

be lower than assumed and, accordingly, its

profits will be less than authorized. If, however,

the utility sells more kilowatt-hours than projected, its revenues and profits will be higher,

assuming that the marginal cost of generating the

additional kilowatt-hours is less than the sales

price. This is usually the case, because automatic

zz con~ssio~ Research Service, SUpm note 18, pp. 619-620.

23320 U.S. 591 (1944).

~ 315 Us. 575 (1942).

25 ~~mquenne fjg~r CO. V. Bar~ch, 109 S. Ct 609, Jan. 11, 1989, the U.S. SllpKenle COW up~ld the pennsYlvtia s~tutory ~fiement

that a utility plant must be “used and useful in service to the public” to be includable in the rate base against claims that such a requirement

in the case of canceled plants violated constitutional protections for due process and just compensation. The ruling affirmed the State utility

commission decision precluding recovering initial costs of a canceled, unfinished nuclear plant even though the costs were prudently incurred

by the utility at the time.
Chapter 3-Electric Utility Industry Structure, Regulation, and Operations I 39

fuel adjustment clauses operate to reduce risks to

utility profits from fuel price changes. This

built-in incentive toward additional sales is what

gives rise to the claim that traditional utility

ratemaking is biased against utility investment in

conservation and energy efficiency.

If the costs of serving additional consumption

exceeded the established rates per kilowatt-hour,

the financial incentives would change and utilities would profit by restraining demand, However, the immediate cost of procuring or generating additional kilowatt-hours usually falls well

below the rates at which utilities are permitted to

sell them, thus providing a powerful incentive for

utilities always to increase power sales and to

resist efforts to lower sales.

Under conventional rate-of-return regulation,

short-term profit considerations favor increased

sales of kilowatt-hours, especially in situations of

surplus capacity that is cheap to operate. Recognition of this tendency has lead State regulators,

spurred in large part by consumer and environmental activists, to adopt various measures to

insulate or ‘‘decouple’ shareholder returns from

the volume of kilowatt-hours sold.26 One such

device is the Electricity Revenue Adjustment

Mechanism (ERAM) used in California and in

variations in other States, in which customer rates

are automatically adjusted upward or downward

so that the utility meets, but does not exceed, its

revenue requirement set in prior rate proceedings.

These approaches are discussed in chapter 6 of

this report.

Ratemaking is not an exact science, although,

as practiced today, it relies heavily on economics,

statistics, computer modeling, and expert testimony. Much of the regulators’ work is political in

nature. Fundamentally regulators seek tradeoffs

among often competing policy goals of economic

efficiency, adequate and reliable service, environmental quality, and equity.

Assuring Quality of Service

Most State commissions are expressly empowered to assure that utilities provide adequate

and reliable service for their retail customers. The

obligation generally means that a utility must

provide safe, continuous, comfortable, and efficient electric service within its service area.

However, the utility is not required to supply

power under any and all conditions, such as

during severe storms or power outages beyond

their control. To provide reliable service, utilities

are required to plan to meet reasonably foreseeable contingencies and load growth.

Regulators have several mechanisms for enforcing this obligation. They can punish chronically poor, unreliable, and inefficient service by

denying or reducing rate increases. The commission can order the utility to take specific remedial

actions to improve service, such as acquiring

additional generation or transmission facilities, or

executing power purchase contracts. Finally,

under certain circumstances varying by jurisdiction, utilities can be held financially liable for

injuries or damages to their customers caused by

inadequacy, interruption, or failure of electric

services.

Energy Efficiency, Resource Planning,

and Demand-Side Management

With their plenary authority over retail rates

and the construction of electric power facilities,

State regulators can exercise considerable influence over utility resource planning and operations. In response to the sizable rate increases and

disputes over new powerplant construction that

arose in the late 1970s, many utility commissions

adopted policies encouraging or requiring utilities to engage in demand-side management (DSM)

programs and integrated resource planning (IRP).

Several commissions have also adopted incentives or requirements for improvements in the

energy efficiency of utilities’ supply-side opera26 Mph c. cavwg~ “ReSpO~lble power hl~et~g in an Increasingly Competitive Er%” ycde Journuf on Regulutioff, VO1. 5, ~er

1988, pp. 331-366.
40 I Energy Efficiency: Challenges and Opportunities for Electric Utilities

tions. These requirements are generally intended

to lower electricity costs for consumers by

encouraging the use of cost-effective energy

efficiency measures as an alternative to highercost conventional generation. Some policies also

have been adopted to support environmental

protection, and promote diversity of energy sources.

Chapter 6 of this report provides an overview of

these State efforts.

The legal basis for requiring utility IRP and

DSM varies by State. Some requirements are

backed by legislation, others are the result of

broad rulemakings by State regulatory commissions, and still others have arisen out of rate cases

involving specific utilities. By the 1990s State

regulatory requirements for utility planning activities were firmly established in more than 30

States and under development in many others. At

the same time, a broad range of financial incentives intended to encourage utility investment in

DSM programs had also been adopted by States.

These changes are altering the relationship between utilities and their regulators and shifting

the financial incentives in utility ratemaking.

8 Federal Regulation

JURISDICTION

The Federal Power Act gave the Federal Power

Commission authority over the rates and conditions for interstate sale and transmission of

electric power at wholesale.27 Federal regulation

of interstate and wholesale sales was initially seen

as a supplement to State authority to fill a gap

where existing State regulation had proven ineffective or unconstitutional. The creation of a

Federal role in the regulation of interstate activities in electric power was prompted by the 1927

Supreme Court ruling in Rhode Island Public

Utilities Commission v. Attleboro Steam and

Electric Co. that State regulatory agencies were

constitutionally prohibited from setting the prices

of electricity sold across State lines because doing

so would violate the Commerce Clause.** This

decision created a gap in effective regulation of

electric utilities that the Federal Power Act was

intended to close.

Originally, it was perceived that there was a

bright line between Federal and State jurisdiction—

Federal regulators would have jurisdiction over

wholesale transactions involving more than one

State and State commissions would oversee

utility operations, instate wholesale transactions,

and retail rates. But, as interconnections among

utilities grew and long-distance transmission

increased, virtually all electric power moving

over transmission lines was viewed as being in

interstate commerce and, hence, subject to exclusive Federal jurisdiction. These ever-more expansive interpretations of Federal jurisdiction have

now brought wholesale transactions between

utilities in a single State, as well as most instate

wheeling arrangements, under Federal law. These

rulings and the fact that most utilities are interconnected with utilities in other States have

arguably limited most State jurisdiction over

prices and terms of wholesale sales and wheeling

transactions, even when they involve instate

parties--except in Alaska, Hawaii, and parts of

Texas.29

H ~bfic u~i~ ~t of 1935, kt of Aug. 26, 1935, c. 687, Title II, sec. 213,49 Stat. 863, 16 U.S.C. 791a-825r, as amended.

26 ~S l~~k Supreme COUII case, Rhode Island Public Utilities Commission v, Attleboro Steam and Elecm”c CO., 273 U.S. 83 (1927),

held that a State could not regulate the price of electricity generated in that State and sold in another. It reflected the then prevailing view that

the Commerce Clause of the Constitution gave the Federal Gov ernment exclusive jurisdiction to regulate matters in interstate commerce and

foreclosed State action to intrastate matters even in the absence of Federal regulation.

29 S= Federal Power co~”sm”on v. Southern Cahyornia Edison Co., 376 U.S. 205 (1%8), also known u city of Cdton v. so~krn

Caf~ornia Edison Co, See also Flori& Power & h“ght Co., 29 FERC 61,140 (1984), in which FERC asserted exclusive Federal jurisdiction

over virtually all transmi ssion service in Florida. Because the power systems in the ERCOT region of ‘lkxas, and in Alaska and Hawaii, are

not synchronously comected to power systems in other States, it has been widely assumed that FERC does not have jurisdiction over most

power transactions in these States.
—

Chapter 3-Electric Utility Industry Structure, Regulation, and Operations I 41

With the establishment of the U.S. Department

of Energy (DOE), the responsibilities of the

Federal Power Commission for regulating electric utilities, natural gas pipelines, and oil pipelines were transferred to a new agency, the

Federal Energy Regulatory Commission.30 Its

five members are appointed by the President and

confirmed by the Senate to staggered, fixed terms;

no more than three commissioners may come

from the same political party. Although within

DOE, FERC retains its independent status. The

Secretary may submit his or her views on energy

policy to the commission, but the Secretary

cannot direct the commissioners to reach a

particular result.31

The Federal Power Act, as amended, gives

FERC jurisdiction over the prices, terms, and

conditions of wholesale power sales involving

privately owned power companies and of transmission of electricity at wholesale.32 It also

oversees sales and mergers of public utilities,33

the issuance of securities and indebtedness of

electric utilities,34 and power pools and utility

interconnections.35 In addition, FERC approves

the rates for public power sold and transported by

the five Federal power marketing administrations, and oversees and licenses nonfederal hydroelectric projects on navigable waters.36

The Public Utility Regulatory Policies Act of

1978 (PURPA) gave FERC expanded responsibilities for encouraging cogeneration and certain

alternative power technologies.37 PURPA required utilities to interconnect with and buy

power from cogenerators and small power producers that met standards established by FERC at

not more than the utility’s avoided cost of

power.

38 PURPA marked the frost major Federal

move to open up electricity markets to nonutilities. At the same time, PURPA exempted these

qualifying facilities (QFs) from most of regulatory burdens applicable to public utilities under

Federal and State law in order to reduce the

institutional barriers to QF development.

PURPA also imposed new requirements directly on State regulatory commissions relating to

the consideration of regulatory policy initiatives

and consumer protection and representation before State commissions. PURPA required State

commissions to give formal consideration to

adopting certain new Federal standards as part of

State utility law and policy, but PURPA also

expressly provided that States could, after such

consideration, decline to implement the standard.

Many of the proposed standards were already

being used by State regulators to ensure that rates

more accurately reflect the costs of providing

service and to encourage energy conservation.

The Federal standards included certain ratemaking methods: seasonal, time of use, and interruptible rate differentials; limiting declining block rate

(e.g., large volume) discounts unless they involved lower service costs; and requiring utilities

to offer load management technologies to their

customers. Federal standards were also proposed

31J me Department of Energy @g anization Act, Public Law 95-91, Title IV (1977), 42 U.S.C. 7101 et seq. FERC also regulates interstate

natural gas pipeline transactions and oil pipelines.

31 congm5io~ Rese~ch Semice, ~pm note 18, p. 129, Ciq ~enier~d cl- ‘ ‘me Rektionship ktween DOE ~d FERC: Innovative

Government or Inevitable Headache,” Energy L.uw Journal, vol. 1, 1980, p. 325.

32 see WCS. 201 and 205 of the Federal Power Act, 16 U.S.C. 824a and 824d, respectively.

33 Swtion 203 of the Federal Power A@ 116 U.S.C. 824b.

~ 16 U.S,C. 824c.

3516 U,S,C$ 824b.

36 Tifle I of tie F~e~ Power Ac$ 116 U.S.C. 791a to 823.

37 fibfic ~w 95+15, 92 Stat. 3117, Nov. 9, 1978.

38 Avold~ cost gener~ly ~em a price not exceq he cost of el~tric energy tit tie u~i~ wo~d o~erwise hve to genmte lkelf’ Or

purchase from another source. Public Law 95-615, WC, 210,92 Stat. 3144, 16 U.S.C. 824a-3.
.

42 I Energy Efficiency: Challenges and Opportunities for Electric Utilities

for consumer information, lifeline rates, and

procedures for terminating electricity service. Not

surprisingly, PURPA was challenged in the

Courts. However, the Supreme Court ruled that

this Federal intrusion into matters previously left

to the States was found to be within the broad

embrace of the Commerce Clause.39

FERC shares responsibility for enforcing the

Public Utility Holding Company Act of 1935

(PUHCA) with the Securities and Exchange

Commission (SEC).40 PUHCA vests broad authority over the structure, finances, and operations of public utility holding companies in the

SEC. PUHCA was enacted in response to widespread concern over the influence of a handful of

large interstate utility holding companies that by

1932 controlled over 75 percent of the private

electric utilities.41 PUHCA was intended to limit

severely the use of the holding company structure

and to force the regional consolidation of the

existing large multistate holding companies.

WHOLESALE RATEMAKING42

The Federal Power Act requires that rates

charged for wholesale power sales and for transmission be “just and reasonable” and “not

unduly discrimin atory or preferential. ’43 Utilities

under FERC jurisdiction must file detailed, written tariffs and schedules of all rates and charges,

which are available for public inspection. FERC

has established detailed regulations and guidelines on rate requests, allowable costs, and

matters considered in rate of return determinations. FERC also requires that electric utilities

follow a uniform system of accounting.

Proposed new rate schedules must be filed with

FERC 60 to 120 days before they are to go into

effect. Utilities must submit detailed schedules of

information, including actual and projected cost

of service data to support the increases. When a

proposed new rate is filed, FERC has several

choices: it can reject the filing, approve the rate

schedule immediately, or order a hearing and

suspend the new rate for 5 months. If FERC

schedules a hearing, the burden of proof is on the

utility seeking the rate increase. The Commission

must also consider evidence submitted by customers or other interested parties. Parties to

proceedings can seek review in Federal Courts of

Appeals, where the standard is whether the

agency decision is supported by substantial evidence.

FERC decisions are made on a case-by-case

basis. However, over the years a substantial body

of administrative precedent has accumulated that

guides the commission and applicants. FERC is

not wholly bound by precedent, however. Within

its broad and general authority under the Federal

Power Act, the commission can establish new

policies on electric power transactions through

39 Federal Ener~ Regulato~ Com”ssion V. Mississippi, 456 U.S. 742 (1982).

4 ~t of Aug. 26, 1935, c. 687, Title I, sec. 33, 49 Stat. 438, 1S U.S.C. 79.

41 ~hol~g ~omp~=’ ~owlex ~Worate s~c~= ~d interlocking ~siness ~~ements had frustrated both State ~d Fdmd

oversight of their activities, led to substantial investment fkaud, and weakened or bankrupted many load gas and electric utilities. For more

on the structure and influence of the holding companies, see tionard S. Hymam America’s Electn”c Utilities: Past, Present and Future, 3d Ed.

(Arlington, VA: Public Utilities Reports, Inc., 1988), pp. 71-83.

AZ For more bckgroud on Fede~ power regulatio~ see Congressional Research Service, Supra note 18, pp. 135-144.

4316 u.S.C. 824d and 824e. The term ‘ ‘just and reasonable’ as used by Congress in the Federal Power Act iII 1935 kd k~~bw

by decades of judicial review of administrative actions governing public utilities. Farmers Union Central Exchange, Inc. et al. v. Federal

Energy Regulatory Comnu”ssion, 734 F2d 1486, at p. 1502 (D.C. Circuit 1984). In that case, the court reviewed basic principles of rate

regulation observing that Courts will uphold agency mte orders that fall within a ‘‘zone of reasonableness’ where rates are neither “less than

compensatory” nor “excessive.” The zone of reasonableness requires striking a fair balance between the financial interests of the regulated

company and ‘‘the relevant public interests. ’ In determi.ning the reasonableness of rates to a producer, the concern is whether the rate is high

enough to cover the cost of debt and expenses and provide a return commensurate with investments in other enterprises with comparable risks

in order to maintain credit and attract capital. In deciding the justness and reasonableness to the consumer, the concern is whether the rate is

low enough to prevent exploitation by the regulated business.
Chapter 3-Electric Utility Industry Structure, Regulation, and Operations I 43

individual case decisions or in new rulemakings.

When FERC departs from past policies, however,

it must provide ample justification and documentation of its decision in the face of possible court

challenges.

In approving wholesale rates, FERC historically has followed a cost of service approach that

is, in principle, similar to that used by State

regulators. As with State rate regulation, Federal

economic regulation is based, in part, on lack of

effective competition in bulk power markets.

However, during the Reagan and Bush Administrations, FERC chairmen and staff embraced the

market deregulation rhetoric of the times and

embarked on several initiatives with the goal of

allowing utilities and independent power producers to charge ‘‘market-based rates’ for their

wholesale services rather than cost-of-service

rates established by regulators.44 Under marketbased pricing, wholesale power rates are not

based on a detailed evaluation of costs of service

plus an appropriate rate of return set by regulators,

but rather on a price set through competitive

bidding or arms-length negotiations between

power sellers and purchasing utilities where

market power is absent or mitigated. Some

proponents expressed a preference for wholesale

rates set by competitive market signals instead of

regulators’ projections, estimates, and judgments

in the belief that such an approach would produce

a more economically optimal result for society .45

Others also argued pragmatically that marketbased rates with prospects of higher profits than

those available to regulated utilities were needed

to attract new entrants, so-called independent

power producers, to build new powerplants because the pace of utility construction had slowed

and some feared an impending capacity shortfall. % Still others supported the availability of

market-based prices and the expanded participation of independent power producers in generation markets to provide utilities with a greater

variety of options in resource planning and

acquisition.

While FERC generally retains cost-of-service

rate policies for bulk power sales, in a growing

number of cases, the commission has accepted

market-based prices. By May 1993 FERC had

received more than 40 applications for market

prices for wholesale power contracts and had

approved 29 of these requests and rejected 9.47 In

approving these transactions, FERC imposed

various conditions intended to establish that the

applicant’s market power has been mitigated. The

preconditions for receiving market-based rates

have been evolving on a case-by-case basis and

FERC has not adopted any generic policy. In

these and other cases, FERC has used its conditioning power to require applicants to expand

access to transmission services to provide wider

44 ~ 1987, ~Rc ~oficited pubfic ~ments on ~= notices of propo~ ~cxs @opRs): 1) competitive bidding for new power

requirements, 2) deterrninW“on of avoided costs under PURPA, and 3) treatment of independent power producers. See discussion in OTA,

Electric Power Wheeling and Deuling, supra note 14, pp. 77-79. The FERC NOPRS proved controversial, and efforts to establish formal rules

or policies were abandoned as commission membership changed. With the support of several co remission members and key FERC staff,

however, the overall policy goals were still pursued on a case-by-case basis. See Congressional Research Service, supra note 18, pp 170-172.

45 For more dismssion ~d referenc~ for the various dere@ation propo~s, ~ co~cssioti Research Service, sllpra nOte 18, pp.

232-303.

46 J. Steven Herod and Jeffrey Sk=, “A bok at National and Regional Electric Supply Needs,” paper presented at the 12th Energy

lkchnology Conference and Exposition, March 1985; U.S. Department of Energy, Deputy Assistant Secretmy for Energy Emergencies, Staff

Repo~ “Electric Power Supply and Demand for the Contiguous United States, 1987-19%,” DOElfLOOll (Sprin~leld, VA: National

Technical Information Service, Febrniuy 1988); “Summary of Current Staff Proposal on PURPA-Related Issues, ” Federal Energy Regulatory

Commission Sept. 11, 1987. Other industry experts discount the shortfall theoxy, interpreting the slowdown as the natural result of aggmsive

overbuilding of large capacity baseload plants and slower economic gTowth. They also note that new capacity needs for many utilities are for

smaller increments of peak-load power, which would be met by combustion turbines and other short-lead time resources.

47 F~e~ Ener~ Re@atoV Commission OffIce of fiono~c policy, ~rso~ communicatio~ June z, 199s. One applkdOI) k Sti~

pending and another was termina ted for failure to respond to a deficiency finding.
44 I Energy Efficiency: Challenges and Opportunities for Electric Utilities

opportunities for other buyers and sellers in bulk

power markets.

TRANSMISSION ACCESS

Access to transmission services allows utilities

opportunities to purchase and sell power in a

wider area beyond their local host utilities and

adjacent utilities. Within segments of the electric

utility industry and regulators, there has been

longstanding concern that some transmission

“haves” might use their control over regional

transmission systems to keep their wholesale

utility customers captive and to deny competing

wholesale power providers access to bulk power

markets. Utilities that have been denied wheeling

services have had only limited options.%

The extent of FERC’S authority to order one

electric utility to transmit or “wheel” over its

lines power produced by another generator has

been a matter of contention for years. FERC’S

authority under the original Federal Power Act to

order wheeling was not explicit. PURPA, for the

first time, provided explicit wheeling authority

but placed such severe limitations on its exercise

that made it all but impossible to obtain wheeling

orders. 49 In recent years FERC has relied on its

authority under other provisions of law to advance its policy goals of expanding access to

transmission services to promote the growth of

competitive bulk power markets. For example,

FERC conditioned the approval of several large

utility mergers on agreement that the merged

utility system offer transmission services to other

utilities. 50 FERC also has encouraged several

utilities seeking acceptance of market-based rates

for wholesale power transactions to file openaccess transmission tariffs as a means of mitigating market power.

The Energy Policy Act of 1992 clarified and

strengthened FERC’S wheeling authority .51 Now

utilities, independent power producers, and others

can apply to FERC for mandatory wheeling

orders to carry out wholesale power transactions.

This change provides new impetus for the growth

of competitive power markets and expands the

options available to utilities in resource planning

and acquisitions. The act restricted retail wheeling—

provision of transmisson services to retail customers--

but left State authority in such matters untouched.

With the basic question of whether FERC can

issue wheeling orders settled, new controversies

are likely to arise as FERC struggles to establish

fair and workable policies on transmission pricing

and capacity determinations.

ASSURING QUALITY OF SERVICE

Unlike State regulatory commissions, FERC

has only very limited authority under the Federal

48 ~ Otier Tail power Co. V. United States, 410 U.S. 366, at 375 (1973), the U.S. Supreme Court noted in dicta tit the F~e~ POW~ ~t

did not grant any authority to order wheeling, but that wheeling could be ordered by the Federal Courts as a remedy under the antitrust laws.

A similar conclusion on wheeling authority is reached in National Regulatory Research Institute, Non-Techm”ca/ lmpedi”menrs to Power

Transjers, September 1987, pp. 52-68, although the author notes that FERC may have some as-yet-untested authority to order wheeling as a

remedy for anticompetitive behavior under sees. 205 and 206 of the Federal Power A@ id. at note 45, p. 64. See also FZorti Power & h“ght

Co. v. FERC, 660F. 2d 668 (5th Cir. 1981), p. 679. The report of the Conference Committee on PURPA is vague on the extent of any existing

wheeling authority FERC might have outside of sees. 211 and 212 and notes that PURPA is not intended to affect existing authority, House

Conference Report 95-1750, to accompany H.R. 4018, 95th Cong., 2d sess., Oct. 10, 1978, pp. 91-95, U.S. Code Congressional and

Administrative News, 1978, pp. 7825-7829.

@ ~~sws. 203 and 204, amended the Federal Power Act to add new sees. 211 and 212, 16 U.S.C. 824j and 16 U.S.C. 824k.

~ k~e Utah power& Li~ht CO. etcd. (Oct. 26, 1988), FERC approved the merger of Utah Power & Light CO. into Puific Pow~& Light

Co., subject to the condition that the merged companies provide firm wholesale transnu“ssion services at cost-based rates to any utility that

requested such service. The condition was necessary to prevent the future exercise of market power by the new company to foreclose access

by competitors to bulk power markets. The decision was reached under sec. 203 of the Federal Power Act which requires commission approval

of mergers and acquisitions. A more expansive ‘open access” provision was included in the FERC approval of Northeast Utilities acquisition

of the bankrupt Public Service Co. of New Hampshire.

51 ~b~c ~w 102-486, Oct. 24, 1992, 106 Stat. 2776. Expanded ~‘ sion access provisions are contained in Title VIII, Subtitle B, sea.

721-726, 106 Stat. 2915-2921, which amend sees. 211 and 212 of the Federal Power Act.
Chapter 3-Electric Utility Industry Structure, Regulation, and Operations I 45

Power Act to remedy inadequate service.52 If a

State commission fries a complaint, and if FERC

finds that interstate service of a public utility is

inadequate or insufficient, the commission can

order the utility to provide the proper level of

service provided that the utility has sufficient

capacity available .53 The commission has no

authority to compel a utility to enlarge its

generating facilities or to sell or exchange electricity when doing so would impair its ability to

render adequate service to its customers.

There is no Federal rate penalty for failure to

provide adequate and reliable service under

Federal law, nor is there a basis to provide more

favorable treatment to utilities providing superior

performance. Rate treatment provides no incentive or disincentive for performance or to remedy

inadequate service.

Nevertheless, there is a chain of decisions

creating a Federal obligation to provide wholesale

service. FERC can require a jurisdictional utility

to provide wholesale service to another utility

where the ability of the purchasing utility to meet

its customer needs is threatened and the selling

jurisdictional utility can provide the service

without imposing an undue burden on service to

its own customers. This has come into play when

long-term power purchase contracts have expired,

and the parties have not entered into new arrangements, and protects the purchasing utility from

being left without power supplies. If, however,

generating capacity is not available, FERC cannot

enforce wholesale contracts or the obligation to

seine.

Adequacy and reliability have been dealt with

as planning tools for electric utilities and not as

matters of regulatory concern. PURPA amended

the Federal Power Act to include provisions

dealing with interconnections and emergency

power sharing arrangements. Utilities are required to report anticipated power shortages to

FERC and contingency plans to State regulators.

FERC is authorized to work with State commissions and local reliability councils to promote

reliability in utility planning and coordination

activities. Beyond this, there are no explicit

responsibilities.

ENERGY EFFICIENCY, RESOURCE PLANNING,

AND DEMAND-SIDE MANAGEMENT

Compared to the scope and extent of State

regulation of utility activities, FERC leaves

largely untouched many areas related to energy

efficiency and resource planning. This has been

primarily a matter of policy, but also reflects

uncertainty over the extent of FERC power and

influence over generating resources and retail

operations under the Federal Power Act.

FERC regulations and rate procedures are

focused on the costs of service of the entity selling

electric power and not on the purchasing utility.

Its concepts of just and reasonable rates, and the

obligation to provide electricity at the lowest

possible rates consistent with adequate service,

have not been expanded into requiring that either

the selling or buying utility demonstrate that the

resource selected is the lowest cost alternative for

meeting customer needs, considering both supply

and demand-side alternatives.

PUBLIC UTILITY HOLDING COMPANIES

Under PUHCA any company that owns or

controls more than 10 percent of the voting

securities of a public utility is considered to be a

public utility holding company. An electric utility

company is any company that owns or operates

facilities used for the generation, transmission, or

distribution of electric energy for sale. The

holding companies are subject to extensive regulation of their financial activities and operations.

Public utility holding companies that operate

wholly within one State or in contiguous States

52 con~essio~ Research Service, supra note 18, p. 157.

5316 uSC s~tion 824 f.
46 I Energy Efficiency: Challenges and Opportunities for Electric Utilities

can qualify for an exemption from the most

stringent regulatory oversight of PUHCA. Exemptions also apply to companies primarily

engaged in nonutility business and not deriving a

material part of their income from the public

utility business.54 Nonexempt entities are registered holding companies and are limited in their

operations to “a single integrated public-utility

system, and to such other businesses as are

reasonably incidental, or economically necessary

or appropriate [there]to. ’ Integration means that

the utility operations are limited to a single area

or region of the country. Registered holding

companies must obtain SEC approval of the sale

and issuance of securities; transactions among

their affiliates and subsidiaries; and services,

sales, and construction contracts. In addition, the

companies must fide extensive financial reports

with the SEC. In contrast, exempt companies

need only file limited annual reports with the

SEC.

With the growth of wholesale power markets in

the late 1980s, PUHCA requirements were criticized as unfairly restricting entry into the competitive power industry and requiring unnecessarily

complex corporate structures for independent

power projects. These so-called “PUHCA pretzels’ ‘ were created to avoid the geographic

restrictions on holding company operations and/

or the loss of the PUHCA exemption for qualifying facilities under PURPA. Even so, the independent power sector grew substantially over the

period and among its major players are the

independent power affiliates of regulated electric

utilities.

The Energy Policy Act of 1992 amended

PUHCA to create a new category, the exempt

wholesale generator (EWG), for certain entities

either building or operating generating facilities

that sell electricity at wholesale to electric utilities. 55 The act also loosened restrictions on

involvement of domestic registered holding companies’ affiliates in power markets outside the

United States.

Regulation of resource planning and affiliate

transactions by registered holding companies has

been a recurring source of tension between State

and Federal regulators.

B State and Federal Conflicts

While States have exclusive retail rate jurisdiction, under the Narragansett doctrine they must

generally pass through wholesale rates previously

approved by FERC.56 The extent to which prior

FERC determinations of the reasonableness of

wholesale rates preempts State consideration of

the retail impacts of those same rates is a matter

of some controversy.

57 The strain arises because

State regulatory programs and the considerations

used in setting rates are generally far more

extensive than FERC’S. In some cases, requiring

States to adopt without question FERC’S wholesale rate determinations in setting retail rates

would preclude States from exercising their own

regulatory authority over issues normally within

their jurisdiction, such as resource planning and

acquisition and facility siting.

The major limitation on Federal preemption is

found in the Pike County exception, which

affirmed the right of a State commission to

examine the prudence of a wholesale power

purchase contract and to disallow the passS4 15 U.scc. 79f.

55 ~blic bw 102+36, Oct. 24, 1992, 106 Stat. 2776.

56 ~stie Wm ~t forth ~Narragan~ettE/ec~.c Co. v. Burke, 119 R.I. 559,381 A.2d 1358 (1977), cert. denied, 435 U.S. 972 (1978), one

of a series of State court decisions that recognized Federal preemption.

57 For diwussion of these issues, see the following: Rotdd D. Jones, “Regulations of Interstate Electric Power: FERC Versus the States,’

2 Natural Resources & Environment 3, Spring 1987; Lynn N. Hargis, “The War Between The Rates Is Over, But Battles Rem@’ 2 Natural

Resources & Environment 7, Spring 1987; and Bill Clinto% Robert E, Johnsto~ Walter W. Nixon, III, and Sam Brattou “FERC, State

Regulators and Public Utilities: A Tilted Balance?” 2 Natura/ Resources & Environment 11, Spring 1987.
Chapter 3–Electric Utility Industry Structure, Regulation, and Operations I 47

through of FERC-approved wholesale costs if

lower cost power supplies were available elsewhere.58 The issue of whether States can review

the prudence of wholesale power contracts will

become especially critical if, as a result of State

least-cost planning initiatives and competitive

procurement practices, utilities rely more heavily

on bulk power purchases for new power supplies.

Wholesale prices for power sales from utilities

and independent generators, except for QF transactions, fall exclusively within FERC’S jurisdiction, as do the terms and conditions for transmission services. This creates a situation where

States shape the initial consideration and choice

of resources for their jurisdictional utilities

through the planning process but have diminished

control over wholesale power costs. The split

jurisdiction increases the potential for utilities to

escape State jurisdiction at the same time that the

growth of competitive power’ entities, including

unregulated utility independent power affiliates,

raises State regulator concerns over their ability to

effectively control self-dealing, unfair competition, and other unfair practices.

The vitality of the Pike County exception has

been cast into doubt by the Supreme Court’s 1988

decision in Mississippi Power & Light Co. v.

Mississippi ex rel. Moore. In this decision, the

Court rejected State efforts to deny a rate increase

based on FERC’S allocation of the costs of a

nuclear unit built to meet the needs of an

integrated interstate holding company system, on

the grounds that the local subsidiary’s participation in the project was imprudent.59 The Court

held that a State prudence inquiry was preempted

even though FERC had not examined the issue

during wholesale rate proceedings. The State

regulators’ only recourse is to challenge the

prudence of the wholesale arrangements before

FERC. Whether the Mississippi Power & Light

decision is limited to the particular situation of

interstate holding companies, or whether it marks

further limitations on the powers of State regulators, is not yet known. Resolution of this controversy over conflicting Federal and State jurisdictional claims will be one of the major public

policy issues in any transition to a more competitive electric power industry.

Note that the House and Senate versions of the

Energy Policy Act of 1992 originally adopted

different approaches to the Federal-State jurisdictional conflicts over competitive power transactions. Conferees failed to reach agreement on an

alternative resolution, so the potential for conflict

remains.

In an increasing number of cases, FERC’S

efforts to expand competition in bulk power

markets in pursuit of economic policies and

streamlining g the bureaucratic process is moving

Federal regulation away from detailed consideration of costs of service. At the same time, States

though IRP, incentive rates, and DSM are moving

toward greater oversight and involvement in

utility planning and decisionmaking to promote

least-cost energy plans. A number of State

regulators see the potential for a clash between

State least-cost plans and FERC (and SEC)

preemptive regulation of wholesale transactions,

particularly in the area of multistate utility

holding companies. This has led to proposals for

legislation to give States greater responsibility in

resource planning areas, authorizing interstate

plans for multistate utilities, and requiring FERC

38 pike Coun~ Light & power CO. v. Pennsylvania Public Utility Commission, 77 Pa. COmm’W. 268, 465 A. 2d 735 (1983). me potenti~

exception was apparently accepted by FERC in Pennsylvania Power & Light Co., 23 F. E.R.C. 61,005 (1983) and noted by the U.S. Supreme

Court in Nantahula Power & L“ght Co. v. Thornburg, 106 U.S. 2349 (1986).

59 ~lssissippi power & Light CO. v. Mississippi ex rel, Moore, 487 U.S. 354, 108 S. Ct. 2428, 101 L. ~2d. 322 (1988.)
. . . . .

48 I Energy Efficiency: Challenges and Opportunities for Electric Utilities

rulings to be consistent with State plans or at least

involve consultations with State regulators.60

Other observers argue that such legislation is

not needed because in their view the potential for

conflicts is minimal and existing law could allow

cooperation and consultation among FERC and

affected State regulators and holding companies

before IRP approval. 61 Some also see the potential for regional integrated resource planning

decisions to result in some unspecfied adverse

impacts on bulk power markets and access to

transmission services.62

OVERVIEW OF ELECTRIC UTILITY

SYSTEMS AND OPERATIONS

Electric utilities provide much more than the

commodity of kilowatt-hours of electricity. Their

special obligations as public utilities require them

to assure reliable, adequate, safe, and economic

electric service on demand to customers in their

franchise area. Utility customers value electricity

for the energy services that it provides (e.g.,

lighting, heating, cooling, machine drive). The

evolving perception of the role of utilities as

providers of reliable and economic energy services to customers rather than purveyors of kilowatthours is evidenced in shifts both in internal utility

organization and in regulatory policies. These

changes reflect recognition of the potential contribution of utility conservation, load management,

and efficiency programs in reducing electricity

demand growth as an effective means of servicing

customer needs and as an alternative to new

powerplant construction.

As part of their obligation to serve, electric

utilities must anticipate and match customer

demand, while assuring system reliability, minimizing electricity rates, and maintaining financial

health. To do this effectively—and for privately

held systems at a profit-requires highly complex

physical systems, specialized personnel, a myriad

of operations, and extensive planning capabilities. Figure 3-5 shows a simplified electric power

system. The structure and operations of electric

utilities in the United States are shaped by the

physical requirements of running reliable interconnected electric power systems and by the

special institutional requirements imposed by

their regulated monopoly status and service

territories.

In particular, many features of the design and

operation of electric power systems reflect two

fundamental physical principles of electricity:63

1. Electricity must be generated as it is

needed because it flows at nearly the

speed of light with virtually no storage of

power in the system.

60 see, for ~mp]e, Stitement of Ashley C. Brow Commissioner, Ohio public Utilities Commission iII Htigs on S. 2607, ~~lation

Authorizing Regional Integrated Resource P1 arming before the Senate Committee on Energy and Natural Resources, May 14, 1992.

Commissioner Brown+ on behalf of the National Association of Regulatory Utility Cornmissionerx, testified that as a result of Federal court

rulings and FERC policies, ‘‘under current law, holding company systems registered under PUHCA cannot be effectively regulated at any level

of governm ent—State, Federal, or local. ” See also the Statement of Sam I. Brattoni Jr., Chairman, Arkansas Public Service Comrnissiou

Hearing on S. 2607 Before the Committee on Energy and Natural Resources, U.S. Senate, May 14,1992. Chairman Bmtton testiiled that as

a result of the U.S. Supreme Court decision in Mississippi Power & Light v. Srate of Mississippi ex rel. Moore, 487 U.S. 354 (1988), electric

utility holding companies could avoid State regulatory review of retail mtes by shifting generation from retail to wholesale subsidiaries. Bratton

further observed that while commentators continued to debate the extent of the Mississippi Power & Light decision+ “. . . participants in the

debate seemed to agree on one thing: State regulators and registered holding companies cannot plan for additions of resources for their system

and be assured that such plans will ultimately be overturned by FERC.’ He termed the situation “a major regulatory gap’ and ‘‘preemption

without planning. ” The State regulators were joined in their support of legislation on cooperative regional integrated resource planning by

Entergy Corp., the registered holding company involved in the Mississippi Power& Light case.

61 Sa test~ony of Willim S. She- General Counsel, Federal Energy Regulatory commis siom before the Committee on Energy and

Naturat Resources, U.S. Senate, May 14, 1992.

62 Ibid.

63 For a more de~led trmtment of utility operations and planning, see ch. 4 in OTA, Elecm”c Power Wheeling and Dealing, supra note 14,

from which this discussion was drawn.
—

Chapter 3-Electric Utility Industry Structure, Regulation, and Operations I 49

Figure 3-5 Simplified Model of an Electric Power System

Energy control center Interconnection D

/

‘1h

Power planVsubstation

x1

I

Interconnection

+\ <&**

h l!t&&

Distribution system

Distribution system

I J

I Power plant/substation

SOURCE: U.S. Congress, Office of Technology Assessment, Electric Power Wheeling and Dealing: Technological Opportunities for

Increasing Competition, OTA-E-409 (Washington, DC: U.S. Government Printing Office, May 1989), p. 11.

2. Every flow of electricity from a powerplant to a distribution system affects the

entire transmission system, not just the

most direct path between them.

The first principle means that electric power

systems must be planned and operated to follow

customer demand (load) instantaneously. Following load requires that if customer demand for

electricity increases, more generating units must

be dispatched to meet the increase in load, and

when load decreases, generation must also be

backed down. Customer demands on the system

change continuously, although they exhibit daily,

weekly, and seasonal load cycles. Figure 3-6

shows a weekly load profile for a typical utility.

Sudden failure of generating units or transmission

components instantly affects frequency and voltage across the power system. Following load

requires that utilities forecast likely patterns of

customer demand and possible equipment failures and plan for and maintain adequate generating resources and transmission capacity in reserve

and readily available to meet changes in demand

and respond to contingencies on short notice.

Moreover, power systems must be operated at all

times to maintain narrow frequency and voltage

standards to protect customer and power system

equipment and to preserve system stability.

The second principle means that power transmission affects not only the transmission lines of

the utility generating the power but also all the

transmission lines of utility systems interconnected with it. When one utility transfers power to

another utility, the receiving utility reduces its
50 I Energy Efficiency: Challenges and Opportunities for Electric Utilities

12

10

8

6

4

2

0

Figure 3-6-Weekly Load Curve

Thousand megawatts

n

%JW Intermediate

Base

Sunday Monday Tuesday Wednesday Thursday Friday Saturday

SOURCE: Office of Technology Assessment, 1883, based on Power Technologies, Inc., “Technical Background and Considerations

in Proposed Increased Wheeling, Transmission Access and Non-Utility Generation,” contractor report prepared for the Office of

Technology Assessment, March 1988, pp. 2-3.

generation while the selling utility increases its

generation, but the power flows over all paths

available, not just the transmission lines of the

two utilities involved. Part of the load may be

carried by the transmission lines of other utilities

hundreds of miles away, reducing the amount of

power that those utilities can place on their own

lines and, perhaps, overburdening a fully loaded

line, and thus risking failure. Therefore, to

maintain the integrity of the grid, each utility must

control its operations and coordinate its transactions with neighboring systems to ensure that no

components are overloaded on any of the possible

paths available.

In addition to satisfying basic physical conditions, utilities must meet certain operational

requirements. They must design and operate their

systems to provide electricity with the correct

frequency and proper voltage for customer equipment. The service must be reliable-sufficient to

meet changing customer loads with an acceptable

level of outages or service interruptions. In

practice, voltage, frequency, and reliability are

viewed as fundamental technical performance

standards that must be met in system operation

and planning. Plannin g and operating the power

system in a manner that minimizes costs to the

customer and maintains the profitability of the

utility enterprise are additional objectives for

utility decisionmakers and their regulatory overseers.

Satisfying these technical and operating conditions over seconds, hours, days, months, and

years requires a high degree of coordination,

planning, and cooperation among utilities, and

detailed data and engineering analyses. This

section reviews the major components of electric

power systems infrastructure and operation and

planning functions.
Chapter 3-Electric Utility Industry Structure, Regulation, and Operations I 51

Figure 3-7—Electricity Generation

(millions of kWh)

by Fuel 1990

c

1,

r

\

Nuclear

r 573, 1

NUGs 4

i\ ~ 108.6 5

20%

37

“/0

7

“o 9%

%’ 273, 862

,~~ $“~”1 Gas 9Y0 Other utility OO\O

259, 954 12, 913

SOURCE: Office of Technology Assessment, 1993, based on data

from the North American Electric Reliability Council.

I Electric Power System Components

The physical infrastructure of an electric power

system consists of:

generating units that produce electricity;

transmission lines that transport electricity

over long distances;

distribution lines that deliver the electricity

to customers;

substations that connect the pieces to each

other; and

energy control centers to coordinate the

operation of the components from moment to

moment and in the near future.

A wide variety of other planningand engineering

systems coordinate capacity utilization and expansion plans for the longer term. Figure 3-5

shows a simple electric system with two powerplants and three distribution systems connected

by a transmission network of four transmission

lines and is linked with neighboring utility

systems by two tie lines.

Electric generators convert mechanical energy derived from fossil fuel combustion, nuclear

fission, falling water, wind, and other primary

energy sources to produce electricity. Utilities

often have a mix of generating units that run on

different energy sources and that are suitable for

base, intermediate, or peaking loads. As shown in

figure 3-7, about 56 percent of electricity generated in the United States in 1990 came from

coal-fired generation and another 21 percent came

from nuclear units. Installed generating capacity

by fuel source is shown in figure 3-8.

Generators typically produce alternatingcurrent (AC) electricity at a frequency of 60

cycles per second (60 Hertz or 60 Hz) with

voltages between 12,000 and 30,000 volts. The

frequency of all generating units on a system must

be precisely synchronized. Automatic voltage

regulators on generating units control the unit’s

voltage output, and speed governors monitor

frequency and adjust power output in response to

changing system conditions to maintain balance.

Figure 3-8—Electric Utilities Installed Generating

Capacity 1990 (summer megawatts)

Nuclear 13°/0

r-lo 7Efl Hydro 10%

N

Coal

293,

/ c, 1 UCJ

\

2

Pumped storag

! 15, 961

>

,~ \

~ Oil 8%

/

/ ’

\ 57, 964

7

/“’” 140130

Dual fuel 190/0

Other utility 0°/0

2, 311

SOURCE: Office of Technology Assessment, 1993, based on data

from the North American Electric Reliability Council.

e 2%
52 I Energy Efficiency: Challenges and Opportunities for Electric Utilities

A powerplant consists of one or more generating units on a site together with a generation

substation that connects the generators to transmission lines. Power transformers at the substations raise the voltage to higher levels for efficient

transmission. Substations also hold monitoring

and communications equipment and control and

protective devices for transmission and generation facilities.

Transmission lines carry electric energy from

the powerplants to the distribution systems. To

minimize losses over long distances, transmission

lines operate at high voltages, typically between

69 and 765 kilovolts (kV). Most transmission in

the United States consists of overhead AC lines,

but direct current (DC) transmission lines and

underground cables are used for special applications. Power transformers raise the generator

voltage to the transmission voltage and back

down to the distribution network level (typically

under 35 kV) at the other end.

Transmission systems consist of interconnected

transmission lines (the conductors (e.g., wires)

and their supporting towers) plus monitoring,

control, and protective equipment and devices

housed in transmission substations and used to

regulate voltage and power flow on the lines.

Most customers receive their electricity from a

distribution system.64 Distribution systems operate at lower voltages than the transmission

system, typically under 35 kV, to transport

smaller amounts of electricity relatively short

distances. Power transformers reduce the highvoltage electricity from the transmission system

to the lower distribution system level. The power

transformers are housed together with control and

protection devices in distribution substations.

The distribution system is divided into the

primary distribution system, operating at between

2.4 and 35 kV, which moves power short distances and serves some moderately large industrial and commercial customers, and the secondary distribution system at 110 to 600 volts, which

typically serves groups of customers in neighborhoods. The primary distribution system delivers

power to distribution transformers, which reduce

voltage to the secondary system voltage levels.

Protective apparatus in the distribution system

includes circuit breakers in distribution substations that open automatically when a protective

relay detects a fault (or short circuit) and fuses on

the secondary systems that open when overloads

occur. Many of the circuit breakers and switches

in distribution circuits are manually operated

devices, so restoring service after outages is

usually done manually by dispatching a work

crew to the site.

Utilities may have a dozen or more generating

units and transmission lines, and hundreds of

distribution systems serving hundreds of thousands of customers, each with a variety of

energy-using devices. The energy control center

coordinates the operation and dispatch of all

power system components within a defined geographic region called a control area. One or more

utilities may make up a control area. The control

area in figure 3-5 is interconnected to two

neighboring control areas through transmission

lines. There are approximately 160 individual

control areas in the United States.

Energy control centers use a variety of equipment and procedures: monitoring and communication equipment (telemetry) to keep constant

watch on generator output and system conditions;

computer-based analytical and data processing tools which, together with engineering expertise, specify how to operate generators and

transmission lines; and governors, switches, and

other devices that actually control generators and

transmission lines. The control center equipment

and procedures are typically organized into three

somewhat overlapping systems:

~ Some vev kge elwtic consumers, such as major industrial plauts, take their power directly from the m~mission system ~ic~lY at

subtrausmission voltage levels between 23 and 138 kV. A substation containing metering, protective, and switching apparatus comects these

large customers to a transmission line.
Chapter 3-Electric Utility Industry Structure, Regulation, and Operations I 53

Utilities monitor and direct power system operations

within a control area from the energy control center

show here.

1.

2.

3.

automatic generation control (AGC) systems, which coordinate the power output of

generators to balance supply with customer

demand;

supervisory control and data acquisition

(SCADA) systems, which coordinate the

transmission line equipment and generator

voltages; and

analytical systems, which monitor and

evaluate system security and performance,

and plan operations.

These three systems are sometimes integrated in

a full energy management system (EMS).

Sophisticated coordinated operation and planning systems control the vast complex of generators, transmission lines, distribution systems, and

substations that makes up the typical electric

power system. Coordination operation systems

include monitoring and communication equipment, devices that actually control generators and

transmission lines, and engineering models and

expertise that together specify how to operate

generators and transmission lines. Planning systems focus on the selection of the technology

requirements (generation, transmission, distribution, and energy conservation/efficiency resources

and operating and maintenance practices) to

satisfy predicted demand in an economic manner.

Planning functions operate on several time horizonsfrom daily, weekly, or seasonal scheduling commitment of generation and transmission resources

to long-term, 20- to 40-year system capacity

expansion and maintenance plans. Integrated

resource planning is one planningmechanism

used to carry out utility intermediate and longterm strategic planning functions.

Backing the coordinated operation and planning systems are advanced software and engineering models, experienced technical personnel,

and a host of engineering and technical standards

and other institutional arrangements that together

assure the safe, reliable, and economic operation

of electric power systems and coordinate operations with other interconnected utilities. Carrying

out these various operations requires detailed and

extensive information on utility systems, load

characteristics, and customer needs.

I Operating and Planning Functions

Together the coordinated operating and planning systems and procedures aid utilities in the

performance of three general functions: following

changing loads; maintaining reliability; and coordinating power transactions.

In practice, utilities seek to perform these

functions at minimum cost. Each of these basic

functions focuses on different time horizons and

different aspects of the power system. See table

3-3. Some procedures are performed continuously, such as coordinating the energy output of

generating units to balance demand. Others, such

as planning generation additions and DSM programs, are performed far less often. Each time

horizon beyond a few seconds requires forecasts

of customer demand and performance of system

equipment. All require a tremendous amount of

information, computing power, and communication capability, as well as extensive coordination

within and among the various organizations

involved.
. .

54 I Energy Efficiency: Challenges and Opportunities for Electric Utilities

Table 3-3-Electric Utility Operating and Planning Functions

Function

Following load

Frequency regulation

Cycling

Maintaining reliability

Security

Adequacy

Coordinating transactions

Purpose Procedures Involved

Following moment-to-moment Governor control.

fluctuations.

Automatic generation control

(AGC) and economic dispatch.

Following daily, weekly, and AGC/economic dispatch. Unit

seasonal cycles (within commitment. Voltage control.

equipment, voltage, power

limits).

Preparing for unplanned Unit commitment (for spinning

equipment failure. and ready reserves).

Security constrained dispatch.

Voltage control.

Acquiring adequate supply and Unit commmitment.

DSM resources to meet Maintenance scheduling.

demand. integrated resource planning for

supply and DSM.

Buying, sailing, and wheeing power AGC/economic dispatch.

in interconnected systems. Unit commitment.

SOURCE: Office of Technology Assessment, 1993.

FOLLOWING LOAD

The ability to follow load is central to the

operations of utility systems. Following load

requires that at each moment the supply of power

must equal the demand of consumers and that

utilities maintain power frequency and voltages

within appropriate limits across the utility system. Consumer demand for electricity changes

continuously and somewhat unpredictably. Some

load changes tend to repeat cyclically with the

time of day, day of week, and the season. Others

result from the vagaries of weather, economic

conditions, and from the random turning on and

off of appliances and industrial equipment. Because these load patterns cannot be forecasted

accurately, utilities must plan for and secure

generating, transmission, DSM, and control resources to meet a variety of future customer load

patterns over the short, medium, and long term.

Utilities rely on unit commitment schedules,

economic dispatch, and automatic and operator

control of generation to follow loads while

maintaining frequency and voltage.

Utilities establish detailed unit commitment

plans to ensure a sufficient supply of generation

to follow loads and to provide backup power

supplies for immediate operation in case of

contingencies such as failure of a generating unit

or transmission line. The schedules are based on

forecasted load changes over daily, weekly, and

seasonal cycles plus an allowance for random

variations and equipment outages.

Unit commitment schedules specify which

units Will be warmed up and cooled down to

follow the load cycles and to provide spinning

reserves.

65 Some generators in a unit commitment

schedule increase or decrease their power output

according to a schedule, following predicted

loads; others are under AGC and economic

dispatch to follow actual loads as required. Power

65 sp~g reserves are generating units that are operating and synchronized with the power grid and ready to send power to the system

instantaneously to meet additional demand or respond to outages.
.——.— . -—

Chapter 3-Electric Utility Industry Structure, Regulation, and Operations I 55

purchases from other utilities are also specified.

The unit commitment plan ensures that sufficient

generation under governor control is available for

regulating frequency in response to changing

loads. Voltage control and reactive power devices

on the transmission system and in generating

plants are simultaneously coordinated to maintain

system voltages as loads and supplies change.

Utilities calculate unit commitment schedules

to minimize the total expected costs of power

generation and maintaining spinnin g reserves for

reliability and to meet expected changes in

demand. New unit commitment plans are typically established each day or after major plant

outages or unexpected load changes.

Unit commitment planning requires a vast

amount of information. Virtually all the information about generation and transmission operating

costs and availability required by the dispatch and

security systems is also needed to develop the

best unit commitment schedule. In addition, the

time and cost to warmup generating units and the

availability of personnel to operate generating

units must be considered. These factors vary

depending on the type of generating unit. Unit

commitment schedules are typically developed

using computers to perform the numerous calculations for identifying the minimum expected

total costs.

Maintaining Frequency

The design of customer equipment such as

motors, clocks, and electronics often assumes a

relatively constant power frequency of 60 Hz for

proper operation. Actual frequencies in U.S.

power systems rarely deviate beyond 59.9 and

60.1 Hz, well within the tolerance of consumers’

electronic equipment and motors. Power system

equipment is more sensitive to frequency deviations than consumer equipment and the control

systems of modem power systems function by

monitoring slight frequency deviations and responding to them.

Frequency fluctuations result from an imbalance between the supply and demand for power in

a system. In any instant, if the total demand for

power exceeds total supply (e.g., when a generator fails, or as demand increases through the

course of a day), the rotation of all generators

slows down, causing the power frequency to

decrease. A similar process occurs in reverse

when generation exceeds loads, with the governors reducing the energy input to generators to

maintain frequency. Speed governors on most

generating units constantly monitor frequency

and regulate those units’ power output to help

balance demand and restore the frequency.

The usefulness of a particular generator in

regulating frequency varies from unit to unit

because of differences in the vamp rate-the rate

at which generator’s power output can increase or

decrease. Large steam generating units such as

nuclear powerplants and large coal units generally change output levels slowly, while gas

turbines and hydro units are very responsive.

Power system operators and planners must consider the responsiveness and availability of generators to control frequencies in setting unit commitment schedules and plannin g new supply

resources.

Controlling Voltage

Many types of customer equipment require

voltage to fall within a narrow range to function

properly. For example, if delivered power voltage

is too low, electric lights dim, and electric motors

function poorly and may overheat. Overly high

voltages, on the other hand, shorten the lives of

lamps substantially and increase motor power,

which may, damage attached equipment.

Unlike frequency, which is the same at all

locations in a power system, voltage varies from

point to point. The voltages throughout a power

system depend on the voltage output of individual

generators and voltage control devices and the

flows of power through the transmission system.

Maintaining voltage involves balancing the

supply and demand of reactive power in the

system. Reactive power is created when current

and voltage in an alternating current system are

330-075 : QL 3 0 - 93 - 3
-.

56 I Energy Efficiency: Challenges and Opportunities for Electric Utilities

not in phase due to interactions with electric and

magnetic fields around circuit components.66

Reactive power is often referred to as VARS (for

volt amperes reactive).

Maintaining voltages within the standards required by system equipment is the function of

VAR control systems which monitor voltages and

adjust generation and transmission system components accordingly. Monitoring equipment at

various locations in the system measures and

telemeters voltages to the energy control center

where voltage levels are checked to ensure they

fall within the acceptable range. When voltages

begin to deviate from the acceptable limits, both

automatic and remotely controlled actions are

taken using a variety of reactive power control

devices. Supervisory control and data acquisition

systems combine telemetry of voltage to the

control center and remote control of VAR supplies.

Reactive power is regulated by adjusting magnetic fields within the generators either automatically or under the control of system operators.

Control of generator VAR output and offeconomy dispatch are common modes of voltage

control on the bulk power system. Other automatic and manual voltage control devices include

capacitors, shunt reactors, variable transformers,

and static VAR supplies.

Plannin g and selecting generation and transmission resources and designing coordination and

control systems must build in consideration of

reactive power flows and VAR control to keep the

system operating at the proper voltage.

Economic Dispatch

Economic dispatch is the coordinated operation of generating units based on the incremental

costs of generation and is a key to minimizing

cost. The incremental production cost of a generating unit is the additional cost per kilowatt-hour

of generating an additional quantity of energy or

the cost reduction per kilowatt-hour due to

generating a lesser quantity of energy. Incremental production costs depend on the cost of fuel

and the efficiency with which the unit converts

the fuel to electricity, and any other operation

costs that vary with the level of power output. In

economic dispatch, units with the lowest incremental costs are used as much as possible to meet

customer demand, consistent with system security requirements. Typically, economic dispatch

is entirely recomputed every 5 to 10 minutes at the

control area.

Automatic Generation Control

The dispatch of generators in a control area is

handled by computerized AGC systems that

calculate increases or decreases in each generating unit’s output required to maintain the balance

between supply and demand in the least costly

way. AGC gives utilities the capability of controlling system operations for economic dispatch,

load following, reliability, and coordinating transfers. An AGC system constantly monitors the

power system frequency to determine whether

increased or decreased output is required and

automatically resets generator governors to maintain frequency. AGC systems also monitor and

reset dispatch to use low-cost generating units to

displace more expensive generation to the extent

feasible given the availability of adequate trans66 ~m ~tcm~g -ent sy~te~ vol~e (elec~~ poten~ orpress~) ad current (the number and velocity of electrons flowiI@ vw

sinusoidally over time with a frequency of 60 cycles per second. The current and voltage, however are not necessarily in phase with each

other-i. e., reaching the maximum at precisely the same time. Real or active power results fkom current and voltage in phase with each other,

is measured in watts, and is the power delivered to a load to be transformed into hea~ light, or physical motion. Reactive power results from

that portion of current and voltage not in phase as the result of the interaction of real power flows with the eleetric and magnetic fields created

around circuit components. When voltage and current are in phase with each other over a transrm“ssion line, there is no net flow of reactive power.

An imbalance in the supply and demand of reactive power or VA.RS causes voltage to rise or drop across the power system, Understanding

the pattern of voltages and reactive power flows is a complicated problem arising from the physics of electric systems.
—. —

Chapter 3-Electric Utility Industry Structure, Regulation, and Operations I 57

mission capacity and system security (reliability)

criteria. AGC systems control both the planned

and inadvertent power exchange between control

areas. The AGC system typically resets generator

governors every 5 to 10 seconds based on an

approximation of economic dispatch.

To perform effectively, an economic dispatch

and AGC system needs detailed cost and performance information (unit efficiency, dispatchability,

capacity utilization, contract rates and terms)

about each of the power system’s operable

generating units. The economic dispatch-AGC

system also must take account of possible transmission line losses, and the adequacy and availability of transmission capacity to transfer power

within voltage and load flow limits in determining the order of dispatch.

The extent of generation dispatchable under

AGC systems is another factor that utilities

consider in scheduling unit commitment and in

planning new resource additions.

MAINTAINING RELIABILITY

Reliability is a measure of the ongoing ability

of a power system to avoid outages and continue

to supply electricity at the appropriate frequency

and voltage to customers. To preserve reliability,

utilities must plan for and maintain sufficient

capacity or power supply arrangements to cover

unscheduled outages, equipment failures, operating constraints for generating units, powerlines

and distribution systems, coordinating maintenance scheduling, and addition of new resources

and growth in customer demand. There are two

aspects of reliability-security and adequacy.

Preparing for continued operation of the bulk

power supply after sudden system disturbances

and equipment failures is called maintaining

security.

67 Bulk system outages occur when

generation and transmission are insufficient to

meet total customer demand at any instant, such

as when a lightning strike on a transmission line

or sudden equipment failure suddenly reduces the

availability of a critical generator or transmission

line. Bulk system failures account for a relatively

small portion of customer service outages—

around 20 percent. Distribution system problems,

often from storm damage to distribution lines, are

the source of most power outages experienced by

customers. Security is maintained by providing

reserve capacity of both generation and transmission in unit commitment schedules and securityconstrained dispatch. The order of economic

dispatch will be overridden if the dispatch scheme

would threaten system security. Together with the

coordinated engineering of relays and circuit

breakers used to isolate failed or overloaded

components, they ensure that no single failure

will result in cascading outages.

The second major element of reliability is

maintaining adequacy, which is the ability of the

bulk power system to meet the aggregate electric

power and energy requirements of the consumers

at all times, taking into account scheduled and

unscheduled outages of system components. Maintaining adequacy requires utilities to plan for and

operate their systems to accommodate a number

of uncertainties and constraints on system availability. The major uncertainties that utilities must

develop contingencies for include: the cost and

availability of fuels, future operating costs for

generating units, construction cost and schedules

for new equipment, and the demand for power.

‘Technical constraints on system availability that

must be addressed to preserve adequacy include:

unit commitment schedules and economic dispatch for load following and security requirements, scheduling maintenance requirements for

system components, and transmission and distribution system capabilities.

Planning new generation and transmission

capacity involves selecting the right mix and

location of both generation and transmission to

meet the needs of following load and maintaining

67 AS defin~ by tie Norr.tI American Electric Reliability Council (NERC), ‘‘security is the ability of the bulk power electric system to

withstand sudden disturbances such as electric short circuits or unanticipated loss of system components. ”
58 I Energy Efficiency: Challenges and Opportunities for Electric Utilities

reliability under a variety of possible futures. In

selecting an appropriate resource mix to meet

customer needs, system planners are supposed to

balance the value to the customer of having

reliable service with minimal outages and the

costs to the utility of providing this service.

However, deriving quantitative estimates of the

value of various levels of reliability to the

customer and the costs to the utility of avoiding

outages under a variety of conditions has proven

difficult and intractable. Therefore, in practice,

engineering planners assume a variety of rules of

thumb or de facto reliability standards in system

planning and operations. Three of the most

common reliability-related goals are:

1.

2.

3.

loss of load probability (LOLP) of 1 day in

10 years,

first (or second) contingency security, and

reserve margins of 15 to 20 percent. (See

box 3-B.)

These reliability standards specify the amount of

capacity to be installed (e.g., reserve margins and

LOLP), and how that capacity must be operated

(contingency security). Thus, they play a central

role in determining the constraints and capabilities of modem power system operations and

planning. The choice of which standard to use is

a matter of experience and engineering judgment

as well as system-specific characteristics for

individual utilities.

A key to security-constrained dispatch is scheduling generation in a “defensive” mode so that

the power system will have enough supplies ready

to continue operating within emergency standards

for frequency, voltage, and transmission line

loadings should contingencies (such as generator

or transmission failures) occur. Defensive operating practices entail holding generating units and

transmission capability in reserve for the possible

occurrence of a major failure in the system. Idle

generating units and transmission lines with

below-capacity power flows may mistakenly

seem to be surplus, when in fact they are essential

for reliability.

Emergency Operations

Reliability operations and planning also entails

establishing procedures for system emergency

operations and restoring power for reliability

emergencies. System emergencies occur when

there simply is not enough capacity available

either within the utility or through neighboring

systems to meet load. When voltages and frenquencies deviate too much as a result, relays and

circuit breakers may isolate overloaded generators and transmission components from the system, exacerbating the imbalance between supply

and demand. Emergency operations involve avoiding cascading outages by reducing the power

delivered to consumers. In the extreme, this

requires disconnecting customers from the system. Plans for load shedding must be coordinated

with the automatic isolation of generating units

that occurs under abnormal frequency and voltage

conditions. Restoring power also requires coordination of the system components and the devices

used to isolate the loads. Following system

failures, restoration requires that some generating

units be capable of starting on their own, called

“black-start capability. ” Not all generators have

this capability, typically taking their starting

power from the system, and must be taken into

account in unit commitment schedules and resource planning.

COORDINATING TRANSACTIONS

The third major function of coordinated operating and planning systems is to carry out power

transactions. Interutility transactions take a variety of forms, including: short- and long-term

purchases and sales with neighboring systems;

purchases from suppliers within a utility’s service

area (e.g., an independent power producer);

operation of jointly owned powerplants; and

wheeling of power. Coordinating transactions

involves scheduling and controlling generation

and transmission to carry out the power transfers,

as well as monitoring and recording transactions

for billing or other compensation. Coordination
Chapter 3–Electric Utility Industry Structure, Regulation, and Operations I 59

Box 3-B-Common Reliability Standards

Loss of load probability (LOLP) is a measure of the long-term expectation that a utility will be unable to meet

customer demand based on engineering analyses. Many utilities prescribe a standard LOLP of 1 day in 10 years.

This means that given the uncertain failure of generation and transmission equipment and variations in customer

demands, engineering analyses predict that there will be a bulk system outage for 1 day in a 10-year period.

Contingency security criteria means that sufficient reserves of transmission and generation are

immediately available so that the power system will continue to operate in the event that the one (or two) most

critical components fail. Usually the critical components are the largest generators or transmission lines, or some

component at a critical Iocation in the network. The reliability criterion applies at all times, even when some

elements are already out of service. The criteria are established based on contingency studies and rely on

engineering judgment to decide which types of failures are reasonable or credible.

Reserve margin is the difference between generating capacity and peak load expressed as a percentage

of peak load and is the oldest and most traditional measure of reliability.1 For example, in a system with a peak

load of 4,000 MW and installed capacity of 5,000 MW, the reserve margin is calculated as follows:

(5,000 - 4,000) (divided by) 4,000 - 0.25, or 25%.

Reserve margins of about 15 to 20 percent typically have been considered sufficient to allow for maintenance and

unscheduled outages. However, the appropriate reserve margin to assure reliability is determined based on

system-specific factors such as the number and size of generating units and their performance characteristics.

For example, a system with a few large units will require higher reserves than a system with many small units. 2

1 The North American Electric Reliability Council uses a similar measure called capacity margin, defined as

the difference between capacity and peak load expressed as a percentage of capacity (rather than peak load).

Because it uses a larger denominator, the capacity margin Is always smaller than reserve margins by a few

percentage points. In practice, however, most utilities refer to their reserve margins. Capacity margins of 13 to 17

percent are commmonly considered acceptable.

2 North American Electrlc Reliability Council (NERC), Reliability Concepts (Princeton, NJ: February 1985),

p. 16.

may involve parties to the power transaction and the return on capital investment in its rate base. It

third-party utilities that may be affected.

I Interutility Coordination and Cooperation

The simple model of an electric utility system

like that in figure 3-5 is of a stand-alone integrated

utility that serves its own needs within an

exclusive, geographically compact retail service

franchise area. The model utility generates sufficient electric power from its plants to meet

customer demand and delivers it via its own

transmission and distribution systems to its customers. It exercises sole control over the operation and planning of all its system components

and derives its profits from retail power sales and

operates under the oversight of a single State

ratemaking authority. The modern-day reality of

electric utility systems, however, is far more

complex.

Nearly all U.S. utilities operate as part of an

interconnected regional grid and not as isolated

systems. All these interconnected systems are

multistate operations with the exception of Alaska,

Hawaii, and utilities within the Electric Reliability Council of Texas (ERCOT). The transmission

interconnections improve electric system reliability by allowing utilities to share generating and

transmission resources, provide backup power

supplies at peak loads and during emergencies,
60 I Energy Efficiency: Challenges and Opportunities for Electric Utilities

and engage in other bulk power transactions.

While clearly conferring benefits, these interconnections also impose physical and legal constraints on utility systems. Utility operations and

planning require a high degree of cooperation and

communications among utilities on the system,

and must satisfy technical performance standards

and other formal and informal obligations imposed through control area and interconnections

agreements, power pools, reliability councils, and

various contractual arrangements for bulk power

transfers.

Each utility is responsible for providing the

power used by its customers without taking power

from neighbors, unless alternate arrangements

have specifically been made. Many utilities

depend on wholesale purchases of electricity

from other utilities or public power agencies or

independent power producers for some or all of

their power requirements. Utilities rely on wholesale transactions because they do not have enough

generating capacity to meet the needs of their

customers and/or because lower-cost power is

available from others. Indeed, there are a large

number of small municipal systems dependent on

regional investor-owned or public power systems

for their electricity supplies and transmission

services. Many large investor-owned utility systems support generation and transmission facilities not only to serve their own retail distribution

customers, but also to meet the long-term obligations to wholesale customers within their service

areas, and to engage in short- or long-term

wholesale power transactions with other utilities.

There are significant variations among utilities

in different regions, and among utilities in the

same region, that help shape plannin g and operations decisionmaking and regulatory policy. These

include differences in industry structure, composition, and resource base characteristics that are

traceable to patterns of population, climate, economic activity, and the history of electrification

within each region. Among utilities, differences

in generation reserve margins, fuel mix, load

growth and coordination, and access to regional

transmission systems will further shape power

markets and resource options.

The structure of the electric power industry has

been changing over the past decade as utilities

have merged, reorganized into (exempt) holding

company structures, and diversified into regulated and nonregulated ventures. One result of

this diversification and corporate reorganization

among investor-owned utilities is that traditional

electric utility operations are no longer the only

(or most profitable) source of corporate income.

In some cases, the regulated public utility subsidiary serving retail distribution customers could

find itself in competition with, or purchasing

from, unregulated independent power and energy

services subsidiaries or joint ventures of its parent

holding company. These changes are introducing

subtle and not so subtle influences into corporate

decisionmakingg--how will company officers and

directors decide between providing for long-term,

least-cost resources for the regulated electric

utility and pursuing potentially higher returns on

unregulated ventures. The changes create new

challenges for utility regulators in policing the

potential for self-dealing and cross-subsidization

of unregulated ventures by utility ratepayers and,

in many cases, transfer the regulatory venue from

State to Federal jurisdiction.

The picture is further complicated by the

growing presence of independent power producers and energy service companies as competitors

with, and suppliers to, regulated electric utilities.

These unregulated entities operate under different

financial and regulatory regimes than traditional

integrated utilities, and it remains to be seen if

existing resource planning and regulatory approaches will be adequate to secure reliable and

reasonably priced resources from these new

entrants over the longer term.

The growing split in jurisdiction over electric

utilities among States and between States and the

Federal Government will undoubtedly influence

resource decisions by individual utilities and by

regulators. Greater reliance on bulk power transactions in utility resource plans will mean that
—

Chapter 3-Electric Utility Industry Structure, Regulation, and Operations 161

Federal regulators will have a more dominant role

in determining electricity costs and that State

regulators’ control over utility costs, and ultimately retail electricity prices (rates), will be

diminished.

As a result of these various influences, each

utility system has a unique set of operational,

structural, regulatory, and geographic conditions

that drive its investment decisions and opportunities for enhancing energy efficiency. This diversity precludes easy generalizations and one-sizefits-all policy prescriptions for utility energy

efficiency. Nevertheless, most utilities generally

adhere to similar goals, performance standards,

and operating and plannin g functions and procedures.
I

c

Using Electricity

More Efficiently:

Demand-Side

Opportunities 4

ommercially available energy-efficient technologies offer

abundant opportunities to cut electricity consumption in

the residential, commercial, and industrial sectors. The

major electricity uses across all sectors are lighting,

space conditioning, water heating, motors, drives, and appliances. Studies of energy efficiency opportunities have identified

a variety of technologies for each of these applications that offer

cost-effective savings and rapid paybacks. Still other energysaving technologies are not currently cost-effective in most

applications, but could prove more financially attractive if

economies of scale cut costs, if energy prices rise, or if policy

interventions provide additional incentives to install them.

This chapter briefly examines some of the energy efficiency

opportunities in the residential, commercial and industrial

sectors, including a profile of electricity use in each sector,

examples of electricity-saving technologies, estimates of potential savings, and major factors influencing technology adoption.

HOW MUCH ELECTRICITY CAN BE SAVED?

Estimates of how much energy can be saved through more

efficient electric technologies vary. Some of the differences in

the estimates are attributable to what measure of energy

efficiency is used—maximum technical potential, cost-effective

potential, or achievable or likely savings potential. (See box

4-A.) The studies vary in assumptions about technology penetration rates, energy demand, consideration of cost-effectiveness

and discount rates,

The Electric Power Research Institute (EPRI) has estimated

that if the existing stock of equipment and appliances were

replaced with the most efficient commercially available technologies, projected U.S. electricity use in the year 2000 could be cut

by 27 to 44 percent without any diminution of services.l (See

1 Barakat & Chamberli~ Eficient Electricity Use: Estimutes of Maximum Energy

Sa\’ings, EPRI CU-6746 (Palo Alto, CA: Electric Power Research Institute, March 1990),

hereafter referred to as EPRI, Efficient Electricity IJse.

-/” “

I 63
.—

64 I Energy Efficiency: Challenges and Opportunities for Electric Utilities

Box 4-A-Estimating Energy Efficiency Savings

Estimates of potential energy savings from efficient technololgies vary considerably. At least part of the

difference in estimates can be attributed to what iS being estimated. Most published estimates use one of the

following measures:

Maximum technical potential, or MTP, is a measure of the most energy that could be saved if all possible

efficiency improvements were made with the most efficient technologies adopted in all new and existing

applications (i.e., 100 percent penetration reached. Achieving MTP savings assumes agressive government and

private efforts and implementation of policies designed to make efficient alternatives attractive to everyone.

Supporting policies rnight include, for example, increased R&D to lower costs, Informationprogram, and rebates

and other financial incentives.

Cost-effective potential is an estimate of the energy savings that could reobtained if efficient techndogies

are installed in new and replacement applications whenever they are cost-effective. Cost-effective potential is

lower than MTP and depends on projections of future marginal electricity costs and rates. Several

cost-effectiveness tests are in common use in utility planning and rate regulation. See chapter 6 for more on

cost-effectiveness tests.

Likely energy efficiency savings estimates are used in utility planning and reflect judgments about the

savings from efficient technologies adopted in response to utility programs. Likely impacts are lower than

cost-effective potential because of the influenoe of various factors inducting, for example: lack of customer

awareness of potential savings or utility programs, customer reluctance to convert with new or different

technologies, and constraints on the supply or deliverabilityof the technology.

Natural occurring energy efficiency savings estimates reflect estimates about the penetration of energy

efficient technologies in response to normal rnarketplace conditions and existing standards In the absence of new

utility or other programs to encourage their adoption. The savings arise from installation of newer, more efficient

technologies- but not necessarily the most efficient technologies commercially available--in new and

replacement applications. Estimates of naturally occurring savings are used by utilities to evaluate the

EPRI Base Case Usage and Maximum Technical

Potential (MTP) From Electricity-Savings Technologies

Savings in 2000

MTP Cost-effective

—

Likely Naturally

occuring

effectiveness of efficiency programs.

Actual electricity use is compared to

what consumption would have been if

efficiency levels were frozen at a base

year’s level and then the effects of

naturally occurring savings are subtracted to yieid the savings attributable

to the utility program

The figure shows a conceptual comparison of the relative magnitude of

different estimates of energy efficiency

potential.

In this chapter, OTA has adopted the

MTP estimates from efficient electric

technologies published in a 1967 report for the Electric Power Research

Institute (EPRI).1 The EPRI analysis

provides one of the few comprehenCU-6746(PaloAlto, CA: The Electric Power Research Institute, March 1990).The Electric Power Research- institute I

Isa research organization supported by the electric utility industry.
.——

Chapter 4-Using Electricity More Efficiently: Demand-Side Opportunities I 65

sive and economy-wide examinations of the potential energy efficiency savings.

The EPRI MTP estimates of savings from efficient electric technologies in the year 2000, included savings

from: 1) using the most efficent electricity-saving technologies available for new Installations and replacement of

all the existing stock of installed electric equipment; and 2)replacing Iess-efficient fossil-fired equipment with more

efficient electrotechnologies in industrial processes. EPRI’s MTP estimates compared with current and projected

electricity use by sector are shown in table 4-1.

The estimates of savings were developed using a baseline projection of eletricity demand in the year 2000,

which includes naturally occurring improvements in efficiency and the effects of mandatory standards and a best

ease scenario in which all applicable technologies are replaced instantaneously with the most efficient

commercialty available electric equipment.

The MTP estimates are subject to a great deal of uncertainty including:

● the efficiency levels of new and existing equipment;

~ the unknown impacts from naturally occurring efficiency Improvements; and

● physical constraints that limit the applicability, compatibility, or deliverability of efficient equipment.

To account for these uncertainties, the EPRI report used two scenarios reflecting a range of Impacts from technology

adoption: an ‘optimistic” or high impact scenario assuming adoption of all commercially available technologies (i.e., no

prototypes, demonstration models, or lab bench-scale technology@, and a conservative” or low impact scenario

reflecting possible constraints on the perpetration rates due to technology applicability and manufacturer capacity.

Neither estimate reflects considerations of cost-effectiveness, the economic tradeoffs between efficiency improvements

and equipment cost.

table 4-l.) (EPRI is the joint research institute lar applications or projections of future electricity

supported by funds from America’s electric

utilities.) The EPRI analysis presents its best-case

estimates of the most energy that could be saved

through efficient technologies, further improvements in existing technologies, and policy initiatives such as information programs, rebates and

other incentives that make the alternatives attractive to everybody. The range in their estimates

from “conservative low impacts” to best-case,

“high” impacts reflects uncertainties in technology applicability, manufacturing capabilities, and

performance characteristics.

The analysis did not include assessments of the

cost-effectiveness of the technologies in particucosts and rates that would strongly influence

cost-effectiveness determinations. Considerations

of cost, practicality, and capital availability may

preclude attainment of the maximum savings

potential, but nevertheless EPRI believes that

many opportunities remain for substantial gains.2

The EPRI maximum technical potential estimates

are cited in this chapter to provide some measure

of prospective energy savings that can be targeted.

Amory Lovins and others at the Rocky Mountain Institute have estimated the maximum technical potential of efficiency savings as high as 75

percent by 2010.3 Other studies have included considerations of cost-effectiveness in their estimates.

2 OW*S ow @ysis concluded that cost effective, enexgy-eftlcicncy measures cm.dd yield savings of o-third in total energy use in the

residential and commerc id sectors by 2015 over a business as usual scenario. IrI fact total energy use in these sectors would decline somewhat

undtx an aggressive efficiency strategy. These two sectors combined are ofta dubbed “the buildings sector” because energy use for building

systems (space heating and conditioning, ventilation% lighting, and watex heating) has made up the overwhelming bulk of energy consumption

in these two sectors. Reported energy use for the buildings sector includes building systems, appliances, ofilce systems, and oth= electrical

@pnt. U.S. COngreSS, ~lce of ~bnoIogY AM=smm4 Building Energy E@ciency, OTA-E-5 18 (WaahingtorL DC: U.S. Governrmmt

Printing Office, May 1992), p. 3, hereafter referred to as 0~ Bu”ld”ng Energy Efidency.

3 See, e.g., the estimates from Rocky Mountain Lnstitute cited in Arnold P. Ficke~ Clark W, GeUings, and Ammy B. IKJvins, “Efficient

Use of Electricity,” Scientific Amen’can, September 1990, pp. 65-74.
66 I Energy Efficiency: Challenges and Opportunities for Electric Utilities

Table 4-1—EPRI Base Case Usage and Maximum Technical Potential (MTP)

From Electricity-Savings Technologies (gigawatt-hours)

Elect ricity consumption Electricit y savings

1987 2000

Base Base Low case % of High case % of

Residential end uses sector GWh GWh GWh base GWh base

Space heating. . . . . . . . . . . . . . . .

Water heating. . . . . . . . . . . . . . . . .

Central air conditioning. . . . . . . . .

Room air conditioning. . . . . . . . . .

Dishwashers. . . . . . . . . . . . . . . . .

Cooking. . . . . . . . . . . . . . . . . . . . .

Refrigeration. . . . . . . . . . . . . . . . .

Freezer. . . . . . . . . . . . . . . . . . . . . .

Residual appliances. . . . . . . . . . .

159,824

103,499

78,127

15,254

15,308

30,390

146,572

59,779

240,861

223,024

134,509

90,134

13,063

23,707

39,271

139,255

48,073

353,620

71,915

43,481

26,265

2,421

1,240

3,115

30,716

11,534

98,242

32.20/.

32.3

29.1

18.5

5.2

7.9

22.1

24.0

27,8

122,285

88,995

30,996

4,222

6,233

7,132

66,896

15,594

141,552

Total residential. . . . . . . . . . . . . 849,613 1,064,656 288,929 27.1% 483,904

Industrial end uses

Motor drives. . . . . . . . . . . . . . . . . . 570,934 780,422 222,226 28.5% 351,040

Electrolytic. ... , . . . . . . . . . . . . . 98,193 138,273 25,950 18.8 41,124

Process heating. . . . . . . . . . . . . . . 83,008 125,274 9,928 7.9 16,606

Lighting. . . . . . . . . . . . . . . . . . . . . . 84,527 114,097 19,016 16.7 38,032

Other. . . . . . . . . . . . . . . . . . . . . . . . 8,453 9,192 0 0.0 0

Total industriala. . . . . . . . . . . . . 845,266 1,167,413 277,119 23.7 446,802

Commercial end uses

Heating. . . . . . . . . . . . . . . . . . . . . .

Cooling. . . . . . . . . . . . . . . . . . . . . .

Ventilation. . . . . . . . . . . . . . . . . . .

Water heating. . . . . . . . . . . . . . . . .

Cooking. . . . . . . . . . . . . . . . . . . . .

Refrigeration. . . . . . . . . . . . . . . . .

Lighting. . . . . . . . . . . . . . . . . . . . . .

Miscellaneous. . . . . . . . . . . . . . . .

77,245

154,299

76,959

24,068

16,172

60,883

238,488

108,447

128,322

208,106

96,094

39,794

26,381

81,652

283,124

177,254

16,335

62,432

28,828

15,917

5,276

9,925

62,916

32,228

12.7%

30.0

30.0

40.0

20.0

12.2

22.2

18.2

30,333

145,674

48,047

23,876

7,914

27,857

157,291

64,456

Total commercial. . . . . . . . . . . . 756,561 1,040,726 233,858 22.5940 505,448

54.8%

66.2

34.4

32.3

26.3

18.2

48.0

32.4

40.0

45.5%

45.0940

29,7

13.3

33.3

0.0

38.3%

23.694.

70.0

50.0

60.0

30.0

34.1

55.6

36.4

48.6%

Total. . . . . . . . . . . . . . . . . . . . . . . . 2,451,440 3,272,795 799,905 24.4%. 1,436,154 43.9%

a Sum of end uses may not add to total due to rounding.

SOURCE: Office of Technology Assessment, 1993, based on 8arakat and Chamberlin, Inc., Efficient Electricity Use: Estimate of Maximum Energy

Savings, EPRI CU-6746 (Palo Alto, CA: Electric Power Research Institute, March 1990), p. 3.

t

OTA’s report Energy Technology Choices: institutional, and behavioral barriers that have

Shaping Our Future4 moderate-efficiency sce- hampered full use of cost-effective, energynario assumes adoption of all cost-effective savings opportunities. Under the moderateefficiency measures (defined as measures that efficiency scenario, electricity demand in 2015

repay their added incremental costs with energy would be 25 percent less than the baseline

savings over their lifetimes). The scenario also demand (which assumes some naturally occurassumes adoption of a variety of government ring efficiency improvements, but no significant

policy initiatives to overcome significant market, policy initiatives).5

4 U.S. Congress, Office of Technology Assessment Energy Technology Choices: Shaping Our Future, O’IA-E-493 (Washington DC: U.S.

Gov ernment Printing Office, July 1991), hereafter referred to as OTA, Energy Technology Choices.

5 Ibid., p. 130. See chs, 4 and 5 for details on the scenarios and government policy initiatives.
Chapter 4-Using Electricity More Efficiently: Demand-Side Opportunities I 67

The 1991 National Energy Strategy projects

that electricity consumption in 2010 will be about

12 percent less than the current policy baseline

due to cost-effective energy savings from proposed initiatives to promote utility integrated

resource planning (and associated demand-side

management programs), building and appliance

efficiency standards, and industrial conservation

research and development.6

Other studies on energy efficiency opportunities

in specific sectors or regions have yielded similar estimates of cost-effective savings potential.

There is considerable agreement among the

various energy efficiency potential studies about

the most promising strategies for achieving more

efficient use of electricity. They include:

improvements in the thermal integrity of

building shells and envelopes;

improvements in the efficiency of electric

equipment;

lighting improvements;

net efficiency gains from shifting energy

sources from fossil fuels to electricity (electrification); and

optimization of electricity use through better

energy management control systems, shifts

in time of use, and consumer behavior and

preference changes.

ENERGY-EFFICIENCY OPPORTUNITIES

FOR RESIDENTIAL CUSTOMERS

The residential sector essentially consists of all

private residences including single and multifamily homes, apartments, and mobile homes.

Institutional residences, such as dormitories, military barracks, nursing homes, and hospitals are

included in the commercial sector, About 22

percent of total primary energy consumption in

the United States can be attributed to residential

sector energy demand. Total energy expenditures

by the residential sector in 1990 were $110.5

billion.7

Figure 4-1 shows direct on site energy consumption in the residential sector.8 Electricity at

present supplies about 30 percent of residential

energy needs and this share is expected to grow as

electric heating and appliance loads grow. Natural gas supplies 47 percent of residential energy

use mostly for space and water heating. The

remaining residential energy consumption consists of oil (15 percent), coal ( 1 percent), and other

energy sources (7.6 percent), predominantly firewood. 9

The residential sector accounts for about 34

percent of all U.S. electricity sales. In 1990, total

residential electricity sales (exclusive of conversion and transmission losses) were 924 billion

s National Energy Strategy: Powe+l tdeas for Amen’ca, First Edition 1991i1992 (W’ashingtou DC: U.S. Government Printing Office,

February 1991), app. C, pp. C25-26.

7 U.S. Department of Energy, Energy Information Adrninistratiou ‘‘Energy Preview: Residential Energy Consumption and Expenditures

Preliminary Estimattxs, 1990, Monthiy Energy Review Apn”l 1992, DOE/EIA-O035(92/04) (Washington DC U.S. Government Printing Office,

April 1992), p. 1.

8 Historical energy use statistics of the Energy Information Administration do not separate residential and commercial energy use.

Residential energy use share is based on Gas Research Institute estimates ffom Paul D. Holtberg, Thomas J. Woods, Marie L, Lihn, and Annette

B. Koklauner, Gas Research Insights” 1992 Edition of the GRI Baseline Projection of U.S. Energy Supply and Demand to 2010 (Chicago, IL:

Gas Research Institute, April 1992) hereafter referred to as 1992 GRIBaseZine Projection); and U.S. Department of Energy, Energy Information

Admmistration, Annual Energy Review 199f, DOE/EIA-0384(91) (Washingto~ DC: U.S. GOV ernment Printing Office, June 1992),

table 17.

9 If the residential sector’s share of direct primary energy consumption is augmented by its pro-rate share of primary energy consumed by

electric utilities in the generation, transmission and distribution of electricity for residential customers, eledricity accounts for some 60 percent

of primary energy consumption attributable to the residential sector. The existence of these sizable conversion and delivery losses associated

with end-use electricity consumption means that energy savings at the point of use are magnified in their impacts on utilities and overall primary

energy use.

10 U,S, Dep~ent of EnH~, Energy Information Administration, Electric Power Annuaf 1990, DOE/EIA-0348(90) ~~~ngto~ ~:

U.S. Government Printing Office, January 1992), table 1, p, 16, hereafter referred to as DOE, Efecm”c Power Armuaf 1990.
. . -

68 I Energy Efficiency: Challenges and Opportunities for Electric Utilities

Figure 4-l-Residential On-Site Energy

Consumption by Source, 1990 (quadrillion Btus)

Oil 15%

1 6

Other

F

Other 80/0

0.8

SOURCE: Office of Technology Assessment, 1993, based on data

from the U.S. Department of Energy, Energy Information Administration, and the Gas Research Institute. Figure excludes generation and

transmission losses.

kilowatt-hours (kWh) at a cost of $72 billion.l0

Residential electricity demand growth is driven

by population, climate, number of households,

the number of persons per household, regional

population growth patterns, increased demand for

electricity-intensive services (e.g., air-conditioning, clothes-dryers) and size of residences.11

Among factors that tend to limit growth are the

decline in population growth, the increased efficiency of new housing stock and appliances, and

retrofits of existing housing units.12 Various

forecasts peg expected growth in residential

electricity demand at from 1 to 2 percent per

year.

13

Figure 4-2—Residential Electricity

Use by Application, 1987

Space heating

Dishwashing 19%.

\

Water heating

12“/0

L

.-

reezers

7%

1

“ R%.

Refrigerators ~

~iyr 1111 Iy

4 c 0/

17 ”/0 Cooking 1 a /0

4%

11%

SOURCE: Office of Technology Assessment, 1993, based on data

from the U.S. Department of Energy and the Electric Power Research

Institute.

Figure 4-2 shows household electricity use by

application.

14 Within each of the categories shown

there are a number of attractive and cost-effective

options for cutting household electricity use,

without diminishing the services provided.

EPRI’s analysis of maximum technical potential estimated that residential electricity use in

2000 could be reduced by from 27 to 45 percent

if the most efficient end-use technologies currently available commercially were used to replace the existing stock of electric appliances in

homes. The EPRI study did not include estimates

of total costs for achieving this maximum technical potential, nor any analysis of the costlo u.S. Dep~~t of Energy, Energy hfo~tion~“ ‘ tratiou Electric Power Annua/ 1990, DOWEIA-034S(90) (Washington DC:

Us. GOvernment Printing OffIce, January 1992), table 1, p. 16, hereafter referred to as DOE, Elecm’c Power Annual 1990.

1 I See om, Building Energy Eficiency, supra note 2, at 15 and 1992 GM Baseline Projection, supra note 8.

~z ]992 GRI Baseline Projection, supra note 8, p. 27.

13 U.S. Rpartment of Energy, Energy Information ~“ “stratiow Annual Energy Outlook 1993, DOE/EIA-0383(93 )(WashingtoXL DC:

U.S. Gov ernment Printing Office, January 1993) table 21, p. 78.

14 Em, Eficient Electricity Use, supra note 1, table 1-1, p. 3.
Chapter 4-Using Electricity More Efficiently:

.

Opportunities I 69

effectiveness of replacing working appliances

with more efficient models. Other studies have

included cost-effectiveness considerations in their

analyses and generally found considerable opportunities for electricity savings in the residential

sector at a cost less than that of supplying

electricity .15

H Residential Energy Efficiency

Technologies

There are a variety of technologies available to

cut residential energy use without diminishing the

services provided. Some of these technologies are

listed in table 4-2. The basic strategies for cutting

electricity use in the residential sector are:

■

■

■

Improving residential building shell efficiency through better insulation by cutting

conductive heat losses and gains through

ceilings, walls, and floors; installing storm

doors and windows; and cutting air infiltration by caulking gaps and weatherstripping

around doors, windows, joints and other

spaces.

Choosing more efficient appliances for new

installations and accelerating the retirement

of older less efficient appliances.

Improving the management of residential

energy use through better maintenance, energy management controls, load shifting, and

changes in occupant behavior.

Improving the energy efficiency of existing

buildings is one of the most promising and vital

areas for energy savings. Space heating and

cooling account for 30 percent of residential

electricity use. Improved thermal integrity in new

and existing residential buildings can reduce

heating and cooling loads and save electricity.

Replacement of existing buildings by energyefficient new buildings is slow and expensive;

most of the existing housing stock will continue

in use for the next 30 to 40 years or more. There

are over 90 million residential units in the United

States, and we are adding between 1 and 2 million

units per year. Although by the year 2000 there

will be 10 to 15 million new units, about 90

percent of the units existing in 2000 have already

been built, and by the year 2010 it is estimated

that about 70 percent of homes will consist of

housing stock built before 1985.16

The most cost-effective time to incorporate

energy-saving measures into buildings is when

they are built, remodeled or rehabilitated. In fact,

failure to make accommodation for energysaving technology in material and design choices

at this stage causes lost energy savings opportunities—for example, e.g., using the standard 2-by-4

dimension lumber in exterior walls instead of

2-by-6 construction that allows for more insulation, or not selecting the most energy efficient

windows.

Careful attention to energy efficiency features

in the design, siting, and construction of residential housing can save electricity. Over the past two

decades, because of high energy prices, building

code requirements, and greater attention to energy

15 s= OTA, ~w”~ding Energy ~ficieng, ~pra note z, at pp. 29.30, A s~dy of el~~city me in U.S. residm~s by researchers at Lawrence

Berkeley Laboratories estimated that residential electricity demand in 2010 could be cut by 37 percent from a “frozen” efficiency baseline

(i.e., excluding ‘naturally’ occurring eftlciency gains over the period) by aggressive use of commercially available technologies with a cost

of conserved energy below 7.6 cents/km using a discount rate of 7 percent. See J, Koomey et. al, The PotentiaJjiir Electn”city Eficiency

Improvements in the U.S. Residential Sector, LBL30477 (Berkeley, CA: Lawrence Berkeley Laboratory, July 1991), pp. 35-36. Artother

analysis of possible electricity savings in Michigan found achievable savings of 29 percent in residential electricity use by 2005 at reasonable

cost over a business-as-usual baseline with aggressive conservation programs and commercially available technologies. F. Krause et al., Final

Report: Analysis of Michigan’s DemandWde Electricity Resources in the Residential Sector, vol. 1, Executive Summary, LBL-23025

(Berkeley, CA: Lawrence Berkeley Laboratory, April 1988). Researchers estimated that current residential electricity use in New York State

could be cut 34 percent at a cost below that of supplying electricity-less than 7 cents/kw assuming a 6-percent discount rate. American Council

for an Energy Efficient Economy, The Potential for Energy Conservation in New York State, NYSERDA Report 89-12 (Albany, NY: New

York State Energy Research and Development Authority, September 1989), pp. S-5-6.

IS Oak Ridge Natioti hbomtory, Energy Technology R&D: What Could Make a Difference? vol. 2, p@ 1 of 3, Om6541fV2fPl (O*

Ridge, TN: Oak Ridge National Laboratory, December 1989) pp. 15,45.
70 I Energy Efficiency: Challenges and Opportunities for Electric Utilities

Table 4-2-Selected Energy Efficiency Technology Options for the Residential Sector

Building envelope improvements Alr-conditioners

Cut conductive heat losses/gains; control infiltration Central air-conditioners

. Weatherstripping and caulking ■ More efficient units

, Insulation improvements ■ Frequent cleaning of filters and coils

■ Storm windows and doors

, Design and siting of new structures Room air-conditioners

■ More efficient units

Space heating ■ Frequent cleaning of filters and coils

Use heat pumps instead of resistance heat

Air source heat pumps Refrlgerators and freezers

■ More efficient models Efficient motors and controls

■ Improved technology Improved gaskets and seals

Ground-source heat pumps Improved insulation

Solar heating Improved malntenance

■ Clean coils often

Energy management controls and systems

■ Set-back thermostats Lighting

■ Smart house/smart systems Replace incandescent with fluorescent and compact

. Zoned heat systems fluorescent

Reduced wattage incandescent

Air distribution systems Dimmers, controls, and sensors

= Improved insulation Reflective fixtures

■ Reduced duct leakage

Cooking

Water heating More efficient ovens and stoves

Blanket wrap of existing tanks Alternative cooking devices

More efficient tanks ■ Microwave ovens

increased insulation for tanks and pipes ■ Convection ovens

Low-flow devices . Induction cooktops

Thermal traps

Set-back thermostats Dishwashers

Heat-pump water heaters Energy-saver cycles

Alternative water heating systems No-heat drying

= Heat recovery water heaters Reduced hot water usage

■ Solar water heat systems

Reduced thermostat settings

SOURCE: Office of Technology Assessment, 1993.

efficiency, newer residential buildings make greater

use of energy-efficient features.17 In fact, new

houses built in 1985 were much more energy

efficient than those built in 1973 and were better

insulated and had more energy-efficient windews.l g Design features to take advantage of

passive solar heating and daylighting can also be

incorporated into new units for additional savings.

The rate of replacement of major appliances

with newer, more efficient models has been slow

and will continue to be so in the absence of policy

initiatives or large changes in energy prices.

Major electric appliances such as furnaces, heat

pumps, central air-conditioners, water heaters,

and refrigerators often are in use for 10 to 20 years

or more and are unlikely to be replaced unless

they fail. It could take as long as 20 years to

realize potential savings from currently available

17 OTA, Building Energy E@ciency, Supra note 2.

18 Ibid., p. 18.
———

Chapter 4-Using Electricity More Efficiently: Demand-Side Opportunities I 71

19 Not installing the efficient new equipment.

most energy-efficient model initially creates lost

efficiency opportunities for a decade or more.

Assuring the installation of the most efficient

appliances and accelerating the replacement of

older inefficient appliances offer prospects for

reaping energy savings.

Building shell improvements in existing buildings are effective means of cutting heating and

cooling costs and increasing occupant comfort.

The most common weatherization retrofits include: installing more insulation in ceilings,

walls, and floors; adding storm windows and

doors, and weatherstripping and caulking windows and doors. One study of home retrofits

found variations in savings attributable to climate

and differences in individual building characteristics. Average savings of 12 to 21 percent in

heating energy demand and payback periods of

about 6 years were found for ceiling and wall

insulation. Another intensive experiment in weatherization cut space heating electricity use by

two-thirds. 20 According to DOE surveys many

Americans have already taken some steps to

improve the energy efficiency of their homes.21

Even where some weatherization measures have

been reported it is likely that additional efficiency

upgrades are possible.

SPACE HEATING

About one-quarter of American homes (22

million units) depend on electric heat and each

year more and more electrically heated units are

added. 22 Electric space heating accounts for 19

percent of residential electricity consumption.

There are two basic categories of electric space

heating systems: electric resistance heat systems

(including electric furnaces, baseboard heaters,

Caulking gaps around windows and doors can reduce

infiltration, and thereby reduce energy use for space

heating and cooling.

and portable heaters) and electric heat pumps

(including air-source heat pumps, and groundsource heat pumps). Electric resistance heating

systems are virtually 100 percent efficient, that is

100 percent of the energy delivered to the system

is converted to heat, so that there are few technical

opportunities to improve on their performance.

Electric heat pumps use a reversible vapor

compression refrigeration cycle to transfer heat

from an outside source to warm indoor spaces in

the winter; in summer, the cycle reverses to cool

indoor spaces by removing heat from inside and

discharging it outdoors. The most commonly

used heat pump is the air-source heat pump that

uses the ambient air as its heat source. On average

heat pumps are twice as energy efficient as

electric resistance systems. However, the performance of heat pumps is highly variable and

dependent on sizing, climate, and the rated

performance of the heat pump. At about 23° F,

heat pumps begin to lose their heating capacity

19 O* ~dg~ N~tio~ ~~ratov, ~pra note 16, p. 47 — proj~~g about 30 percent savings in totfd end-use txltigy.

m Ow, Building Energy Eficiency, supra note 2, pp. 45* citing the Hood ~ver ~oJ~t.

21 OTA, ~uj~d~ng Energy Eficzency, Supra note 2, p. 4.6, Cit@ a ~ey by he Us. Department of Energy.

22 u.S. Dqxu-trnent of Energy, Energy hformation ~‘ “stratioq Hm.ring Characteristics 1987 DOE/EIA-0314(87) (Washington, DC:

U.S. Governmexd Printing Office, May 1989), hereaftes referred to as DOE, Housing Characteristics 1987; OTA, Building Energy Eficiency

supra note 2, p. 39 reports that 23 percent of new single family homes are equipped with heat pumps.
72 1

and

Energy Efficiency: Challenges and Opportunities for Electric Utilities

in moderate to cold climates they must have

a backup heat source, usually an electric resistance heater. There is a considerable range in the

performance of residential heat pumps currently

on the market. The typical heat pump has a

heating efficiency (heating season performance

factor, or HSPF) of about 6.9 Btus per watt-hour

and a cooling efficiency (seasonal energy efficiency ratio, or SEER) of about 9.1 Btus per

watt-hour. See box 4-B for a description of

common energy efficiency measures. The best

units currently on the market have efficiencies of

9.2 HSPF and 16.4 SEER.23 Federal minimum

efficiency standards for heat pumps sold after

1992 specify 6.8 HSPF and 10.0 SEER.24

Another variant of the heat pump, the groundsource heat pump uses groundwater, or the

ground itself as the heat source. This technology

offers an advantage over air-source heat pumps,

in that ground temperatures seldom drop below

freezing, thus there is no loss of heating capacity

or resultant need for supplemental resistance heat.

For both heat pump and electric resistance heat

systems, improving the thermal integrity of the

building shell or envelope and insulating and

plugging leaks in air distribution ducts can also

cut heat losses and reduce the heating loads.

EPRI estimated that a combination of envelope

improvements, a shift to electric heat pumps, and

improvements in heat pump efficiencies could

result in savings of 40 to 60 percent in space

heating electricity demand in 2000 over 1987

stock.

SPACE COOLING

Air-conditioning accounts for about 11 percent

of residential energy consumption and this demand is projected to grow as more homes are

air-conditioned. Over two-thirds of U.S. homes

are now air-conditioned; 40 percent have central

air-conditioning and 29 percent have room units.

Over three-quarters of new housing units have

central air-conditioning. But this growth in airconditioning demand has been offset by increases

in the efficiency of both central and room

air-conditioning units.

The most efficient central air units on the

market today have a SEER of 16.9 Btus per

watt-hour 25 and new Federal appliance standards

in effect in 1992 will require a minimum SEER of

10 Btus per watt-hour. Just 10 years ago, the

average efficiency for new central air systems was

7.8 Btus per watt-hour. These gains were due to

more efficient fan motors and compressors, larger

evaporator coils and condensers, and reduced

airflow resistance. EPRI estimated that as of

1987, the stock of central air units in use had an

average SEER of 7 Btus per watt-hour—

considerably below the most efficient systems on

the market. New installations and replacement of

existing units with higher-efficiency central air

units could cut electricity use by central airconditioners in 2000 by 29 to 34 percent or more

according to EPRI.

Room or ‘window’ air-conditioners have also

improved with the addition of more efficient

motors for fans and compressors, better fan blade

design, larger heat exchangers, reduced airflow

path resistance and better low-temperature refrigerant line insulation.26 Efficiencies vary according to model sizes and features, but nevertheless

new units today use about 30 percent less

electricity to operate than units sold in 1972. The

most efficient units available today, with SEERS

of 12 consume half the electricity of 1972 models.

EPRI estimated that the 1987 stock of room

23 ~ncm Comcil for ~ Energy. ~lcient ~nomy, The Most Energy-Eficient Appliances Z989-199(? (Wdi@OQ~: AInericlin

Council for aud Energy-Efficient Economy, 1989), pp. 18-19, hereafter referred to as ACEEE, The Most Energy-Eficient Appliances.

U OTA, Building Energy Eficiency, Supra nOte 2, p. 39.

~ ACEEE, The Most Energy-Eflcient Appliances 1989-90, supra note 23, pp. 16-17.

26 Battelle-colwbus Division ~d Env&_gement & Re-m hc., Ds~ Technology Alternatives, EpRr-EM-5A5T, hlklb Report

(Palo Alto, CA: Electric Power Resea.reh Institute, October 1987); hereafter EPw DSM Technology Alternatives.
—= ——. - — .— ——

Chapter 4-Using Electricity More Efficiently: Demand-Side Opportunities I 73

Box 4-B-Measuring Energy Efficiency

Various measures are used to indicate the energy efficiency of electrical devices. The following are among

the most common measures for residential and commercial equipment

The energy efficiency ratio (EER) Is used to measure the coding performa- of heat pumps and

air-conditioners. EER is expressed as the number of Btus1 of heat removed from the conditioned space per

watt-hour of electricity consumed (i.e., the cooling output divided by the power consumption). Typical EERs for

room air-conditioners are 8.0 to 12.0 Btus per watt-hour. The higher the EER the more efficient the air conditioner.

The seasonal energy efficiency ratio (SEER) is used to measure the seasonal coding efficiency of heat

pumps. SEER is expressed as the number of Btus of heat removed from the conditioned space per watt-hour of

electricity consumed under average U.S. climate conditions. Unlike the EER, the SEER incorporates seasonal

performances under varying outdoor temperatures and losses due to cycling. Typical SEERS are 9.0 to 12.0 Btus

per watt-hour.

The heating seasonal performance factor (HSPF) is a measure of the seasonal heating efficiency of heat

pumps under varying outdoor temperatures, losses due to cycling, defrosting, and backup resistance heat for

average U.S. climate conditions. HSPF is expressed as the number of Btus of heat added to the conditioned space

per watt-hour of electricity consumed. Typical values are 7.0 to 12.0 Btus per watt-hour.

The efficiency factor (EF) is a measure of the energy efficiencyof water heaters based on the energy used

to provide 84 gallons of hot water per day.

The annual energy coat (AEC), required by Federal appliance labeling regulations, reflects the cost of

energy (usually electricity) needed to operate a labeled appliance for 1 year at a specified level of use. The AEC

label provides information on the costs of operating the labeled appliance and similar models over a range of

energy prices (e.g., cents per kilowatthour) to account for variations in local rates.

1 Btu is shorthand for British thermal unit, a basic unit of energy defined as the amount of heat needed to raise

the temperature of 1 pound of water 1° F (at 39.1° F). A Btu is equivalent to 252 calories.

SOURCES: Office of Technology Assessment, 1993, based on U.S. Congress, Office of Technology Assessment Building Energy

Efficiency, OTA-E-518 (Washington, DC: U.S. Government Printing Office, May 1882), p. 68 and American Council for an Energy-Effkient

Economy, The Most Energy-Efficient Appliances, 1989-edition (Washington, DC: American Council for an Energy-Efficient Economy,

1989).

air-conditioners had average SEER of 6.5 Btus efficiency for new heat pumps at 10. Careful

per watt-hour. Using the most efficient room units

for new and replacement installations could cut

room air-conditioner electricity use by 19 to 32

percent by 2000 according to EPRI’s analysis.

Better maintenance of air-conditioners can also

boost efficiency. A dirty filter can cut efficiency

by 10 percent. Cleaning air-conditioner coils and

cleaning or replacing dirty falters can preserve

efficiency.

Heat pumps are also used for space cooling.

Today’s typical heat pump has a SEER of 9, but

commercially available high-efficiency models

have SEERS up to 16.4. New Federal standards

effective in 1992 will set minimum cooling

selection and sizing of heat pumps to match

cooling loads, especially in hot climates, can

increase efficiency.

WATER HEATING

Electric water heating is used in about 37

percent of American homes and makes up about

12 percent of residential electricity consumption.

Electric resistance water heaters are the most

common type of electric water heater in use today

and new units incorporating better tank insulation

and improved heat transfer surfaces, use 10 to 15

percent less electricity than models of 10 years

ago. (On average, larger size hot water tanks are
74 I Energy Efficiency: Challenges and Opportunities for Electric Utilities

less efficient.) Other electricity-saving measures

include wrapping the outside of the hot water tank

with an insulating blanket, insulating hot water

pipes, and installing devices such as low-flow

showerheads, aerators, and self-closing hot water

faucets. EPRI estimated that use of these energysaving measures could cut water heating power

needs by 20 to 30 percent in 2000.

Shifting to alternative electric water heating

systems, such as heat-pump water heaters, heatrecovery water heaters, and solar hot water

systems can achieve efficiencies of up to 70

percent. Overall, EPRI estimated that the range of

efficient electric water heating technologies offered savings of from 40 to 70 percent.

REFRIGERATORS AND FREEZERS

Together, refrigerators and freezers make up

about 24 percent of residential electricity demand. Both technologies have seen substantial

increases in efficiency over the past 20 years, but

opportunities for significant improvements in

performance remain.

The typical refrigerator on the market today

uses just 45 percent of the electricity needed to

run the average 1972 model.27 A combination of

technological gains has produced these savings,

including: more efficient fans, motors, and compressors; better and more compact insulation;

improved door seals and gaskets; and dual

compressors. DOE researchers believe that it is

technically feasible to cut electricity needed to

run today’s average new model almost 50 percent

further. EPRI’s analysis estimates that more

efficient refrigerators could cut energy use about

22 to 48 percent in 2000 over the 1987 stock.

Even more efficient refrigerators are available

today than those assumed in the EPRI report. so

that the maximum potential savings probably

understate the potential.

Freezers account for 7 percent of residential

electricity use and are found in about 34 percent

of U.S. households. Stand alone freezers also

have seen significant efficiency gains over the

past 20 years as a result of advances in refrigeration technology. The typical model sold today

uses half the electricity of the average 1972 model

and as with refrigerators, additional efficiency

gains are probable.

More efficient freezers could save 24 to 32

percent over energy required for the 1987 stock

according to EPRI analyses.

Complicating the drive for more efficient

refrigerators and freezers is the need to find

replacements for the chlorofluorocarbons (CFCS)

used as refrigerants and in insulation that offer

equivalent or improved performance. Box 4-C

describes the ‘‘Golden Carrot’ award program—

a contest sponsored by a consortium of electric

utilities in cooperation with the U.S. Environmental Protection Agency to spur the commercialization of more efficient refrigerators.

As with air-conditioning, maintenance practices can affect the efficient operation of refrigerators and freezers. Cleaning refrigerator coils two

to three times per year can save about 3 percent of

annual refrigerator electricity use at little or no

cost. 28

LIGHTING

About 15 percent of household electricity load

is lighting. As in other sectors, use of more

energy-efficient lighting products can save electricity for residential customers. OTA’s recent

report Building Energy Efficiency estimated that

efficient lighting could cut residential lighting

electricity use by one-third if one-half of all

residential incandescent lights were replaced by

compact fluorescents.29 Assumin g the light is

used 6 hours per day, OTA calculated a payback

27 See OTA, Building Energy Eficiency, supra note 2, pp. 60-61, and Mble 2-13.

28 Stephen Cowetl, Steve Gag, and Jackie Kelly, “Energy Fitness: Canvassing Urban Neighborhoods, ” HOnW Energy, VO1. 9, No. 2

March/April 1992, pp. 27-33, at p. 30.

29 OTA, Building Energy Eficiency, Supra note *, p. 50.
Chapter 4-Using Electricity More Efficiently: Demand-Side Opportunities I 75

Box 4-C-The “Golden CarrotTM” and the Quest for a Super-Efficient Refrigerator

In an innovative effort to overcome market barriers that have slowed the commercialization of more

energy-efficient consumer appliances, 25 U.S. utilities joined to offer a “Golden CarrotTM” in the form of a

$30-miliion award to the winner of a design competition for an advanced, energy-saving refrigerator that is free

of ozone-depleting chlorofluorocarbons (CFCS). The consortium, the Super-Efficient Refrigerator Program, Inc.

(SERP), was formed in collaboration with the U.S. EPA Global Change Division’s green programs, EPRI, and

others. Its member utilities provide electric service to more than one quarter of the Nation’s households. The award

will provide the winning manufacturer with a subsidy of over $100 per refrigerator. In return, the new super-efficient

refrigerator will be delivered in participating utilities’ service areas before it is available to other distributors.

Product Research and

i , - .- -., , .,

den Ca R

I

Mwkel Awd

Wmw

1

-.

Market

Among the disincentives that the SERP program and possible future “Golden CarrotTM” competitions are

intended to counter are consumer reluctance to try new products and the higher first cost of more energy-efficient

or green products. By offering a subsidy for development of the winning design and guaranteed orders for a sizable

initial manufacturing run, SERP hopes to create a market pull for the energy-saving product, lower product

development risks, and allow the manufacturer to achieve economies of scale in production. This should

accelerate commercialization and result in a lower market price for the product than in the absence of the incentive.

It will also help speed the commercialization of replacements of CFCS that are to be phased out of production by

1995.

The competition challenged manufacturers to commit to producing a CFC-free refrigerator at least 25 percent

more efficient than the 1993 Federal energy efficiency standards require and to deliver them to participating

utilities’ service areas in 1994-97. The manufacturer must agree to assemble the refrigerators in North America.

Additional points in the competition could be awarded for achieving greater efficiency levels.

Bids were due in October 1992 and all but 1 of the 15 major U.S. manufacturers entered the competition.

Submittals were reviewed based on a number of key factors including proposed design, efficiency levels, incentive

requested, marketing plans, and technological experience. In December 1992, Whirlpool Corp. and Frigidaire Co.

were selected as finalists to design the new refrigerator.

(Continued on next page)
76 I Energy Efficiency: Challenges and Opportunities for Electric Utilities

Box 4-C--The “Golden CarrotTM” and the Quest for a

Super-Efficient Refrigerator-(Continued)

The winner announced in June 1993 was Whirlpool Corp., which will deliver about 250,000 SERP

refrigerators in various models between 1994 and 1$97. SERP refrigerator will be priced the same as other

models with similar features.

EPA estimates that a super-efficient refrigerator has the potential to save 300 to 400 kWh/year over its its lifetime

and save its owners a total of aout $500 on utility bills. It also is expected to eliminate 9,000 

dioxide emissions compared with current models.

SOURCES: U.S. Enviromental Protection Agency, Office of Atmospheric Programs,1992Accomplishments and Prospec for 1993, vol.

1 :Global Change Division, EPA 430-K_92-031 , November 1992, PP. 11-12. Gary Fermnstrom, "Buildinq a Better Refreigerator,’ Environment,

September/October 1992, p. 27; “24 Utilities Sponsoring ‘Super-Fridge’ Contest to Get an Edge in Marketing,’ Electric Utility Week, July

5, 1993, p. 4.

period of 1.7 years for a $20 compact fluorescent

bulb.30 Compact fluorescent also last 10 to 13

times longer than standard incandescent bulbs.

EPRI estimated maximum potential lighting related savings at from 20 to 40 percent in 2000.

Depending on applications, compact fluorescent bulbs can cut energy use per bulb by

two-thirds over standard fluorescent. Even standard fluorescent offer energy savings over incandescent bulbs for equivalent lighting output. But

consumers often find fluorescent lighting unacceptable or unattractive for some purposes. The

extent to which energy-efficient lighting can cut

electricity demand in the residential sector is

highly uncertain and depends on consumer preferences and applications. Manufacturers of compact fluorescent continue to make progress on

adapting these lamps for more common residential fixtures and to improve the quality of light

provided, which may hasten acceptance by residential customers.

Other options such as lower-wattage “energysaver’ incandescent, reflector fixtures, task

lighting, dimmers, and automatic lighting controls can also shave lighting energy use. Increased

use of daylighting through windows, skylights,

and clerestories can also reduce the need for

interior lighting.

COOKING

Electric ranges and ovens account for 4 percent

of household electricity demand. Newer models,

particularly self-cleaning ovens are more efficient

than current stock owing to a number of changes:

more insulation, better seals, improved heating

elements and reflective pans, reduced thermal

mass, reduced contact resistance, and better

controls. The penetration of microwave ovens,

convection ovens, and induction cooktops also

offer energy savings. It is uncertain whether

microwave ovens, which cook food with onethird the electricity required for standard electric

ranges and ovens, will actually result in reduced

cooking loads as consumers may tend to use them

more as an adjunct to conventional appliances.

EPRI estimates that replacement of the 1987

stock of ranges and ovens with more efficient

models could produce savings of 10 to 20 percent

in electricity demand for cooking in 2000.

DISHWASHERS

Dishwashers account for about 2 percent of

household electricity use and are found in 43

percent of households. Energy-saving features

such as better insulation, water temperature

boosters, water saver cycles, and air drying cycles

can cut electricity consumption. Total savings are

dependent on the customers use of energy-saving

~ mid., p. s3. AISO assuming electricity at 7.8 cents/kWIL O kbor ~sts.
Chapter 4-Using Electricity More Efficiently: Demand-Side Opportunities I 77

cycles. EPRI estimates that improved dishwashers could cut dishwasher electricity demand in

2000 by 10 to 30 percent over 1987 stock.

OTHER APPLIANCES

The remaining household electric appliances,

such as clothes washers and dryers, televisions,

stereos and other electronic equipment, vacuums,

small household appliances, power tools, and

home computers account for about 13 percent of

present residential electricity use. This portion of

household electricity demand is expected to grow

with greater saturation of clothes washers and

electronic equipment. Newer models will be more

energy efficient, and EPRI estimate, that this

trend is expected to result in electricity consumption that is 10 to 20 percent less than equivalent

1987 models by 2000.

Estimating net efficiency gains from more

efficient appliances is difficult, however, because

energy services are growing, and households may

use the energy savings to buy larger appliances or

increase the utilization of the equipment.

1 Obstacles to Residential

Energy Efficiency

Total residential energy use in 1990 was over

1 quad less than it was in 1978, even as the

number of households grew from 77 million to 94

million, reflecting a steady improvement in residential energy efficiency.

31Over this period the

energy intensity of new living space has decreased and many older units were retrofitted with

a variety of energy-saving measures. Major household appliances use significantly less electricity

to operate than comparable models of 20 years

ago.

Household electricity use also has grown from

24 percent of residential energy use in 1978 to 30

percent in 1990, but growth in residential electricity demand has been less than it might have been

without energy efficiency gains. These gains are

attributable to several factors in addition to

evolutionary efficiency gains: higher energy prices

during the 1970s and early 1980s; energy efficiency requirements in building codes; appliance

labeling and efficiency standards; government

and utility energy education efforts; utility conservation programs; and more awareness of energy efficiency by consumers, equipment vendors, and building professionals and tradespeople.

Even with the admirable gains that have been

made in energy efficiency since the 1970s, there

remains a sizable gap between the most energyefficient products on the market to day and the

products in use in American homes. More efficient options exist for almost all of the major

electricity uses at home. The potential energy and

cost savings from residential energy-efficiency

investments are significant according to many

efficiency proponents. For many measures the

energy savings over the lifetime of the investment

would exceed the initial cost, in some cases

offering payback periods of 2 years or less.

If energy efficiency investments are such

attractive investments, why then haven’t they

been enthusiastically embraced by American

consumers? Analysts commonly cite a host of

disincentives that have tended to dampen the pace

and extent of efficiency savings. These include a

number of institutional, economic, behavioral,

and practical matters.

OTA’s report Building Energy Efficiency found

a confluence of factors resulted in underinvestment in residential energy efficiency. Decisionmaking affecting household energy efficiency is

fragmented among: residents (homeowners and

renters); architects; developers; builders; equipment manufacturers and vendors; and a host of

Federal, State, and local government agencies.

For all of these decisionmakers, energy efficiency

is only one of many attributes considered in

making choices that affect home energy use and

31 u.S. Dep~ent of Energy, Ener~j Information ~“ “stratioq Annual Energy Review 1991, DOE/EL4-0384(91) (WashingtorL DC:

U.S. Government Printing Office, June 1992), tables 17 and 21, hereafter referred to as DOE, Annual Energy Rew”ew 1991.
78 I Energy Efficiency: Challenges and Opportunities for Electric Utilities

it competes against such characteristics as lower

first cost, appearance, convenience, features, and

hassle-avoidance. For most decisionmakers, energy efficiency has not been a high priority. In all

too many instances, residential consumers are

effectively precluded from energy efficiency

opportunities because design and major equipment choices are made by others-by architects,

builders, and developers for new housing, and by

landlords for the one-third of residential units that

are rented.

Although energy-efficient residences and highefficiency appliances offer electricity savings and

lower life-cycle costs over less efficient versions,

these potential cost savings provide only weak

financial incentives for several reasons.

First, residential electricity prices seem to have

only a weak influence on energy choices for most

ratepayers, and almost no influence on third-party

decisionmakers (developers, builders, equipment

vendors and manufacturers, and landlords and

tenants who do not pay monthly electric bills).

Residential electricity prices have declined steadily in real terms over the past decade. Moreover,

residential rates usually do not reflect the higher

costs of using electricity at times of peak demand,

nor the social and environmental costs (externalities) of generating electricity.

Future savings from energy-efficiency investments are heavily discounted. Studies have found

that residential consumers demand a short payback period for efficiency investments-2 years

or less for home appliances, for example.

Many decisionmakers are driven by the desire

to keep first-costs low; few pursue the goal of

minimizing life-cycle costs (the sum of capital

and operating costs over the life of the equipment—

or e.g., the initial purchase cost of an appliance

plus the cost of annual electric bills, maintenance

and repairs), This so-called first-cost bias is

especially strong when energy-efficient equipment costs more and others (home purchasers or

tenants) will reap the benefits of lower electric

bills. First-cost bias is also strong for low-income

consumers who lack either the cash or access to

credit to pay for the more efficient and expensive

equipment.

Reliable, understandable information on energy use and costs is often lacking or hard to use.

Consumers that would like to give greater weight

to energy efficiency in their decisions—whether

motivated by lower life-cycle costs, environmental concern, technological fascination-have

few alternatives. Government and private programs for energy-efficiency ratings of homes and

apartments are only just beginning. The effectiveness of federally required labeling for major

appliances is uncertain and has not been adequately assessed.32

Energy efficiency is often misperceived as

requiring discomfort or sacrifice, rather than as

providing equivalent services with less energy.

The poor popular image of home energy efficiency as meaning cold showers, darkrooms, and

warm beers hampers consumer acceptance and

diminishes incentives for housing developers and

equipment manufacturers to make efficiency a

selling point for their products. Without a market

pull for efficiency, equipment manufacturers and

building suppliers give less emphasis to efficiency in product design and research.

The typical low turnover rate in the housing

stock and slow rate of replacement of major

appliances mean that efficiency improvements in

the residential sector will significantly lag behind

technical potential. Without aggressive efforts in

response to government policy and/or an energy

crisis, this lagging response will continue.33

From a somewhat different analytical perspective, the Bush Administration also found progress

in residential energy efficiency unacceptably

slow. President Bush’s National Energy Strategy

32 See diswssiom in OTA, Building Energy Eficiency, supra note 2, ch. 4 and U.S. Congress, OffIce of Rdnology Assessmen4 changing

by Degrees: Steps to Reduce Greenhouse Gases, OTA-O-482 (Washington, DC: U.S. Government Printing Offke, February 1992), ch. 4.

33 0~, Building Energy Eflciency, supra note 2, p. 85.
——

Chapter 4-Using Electricity More Efficiently: Demand-Side Opportunities I 79

(NES) found that “a number of institutional and

market barriers’ limited consumer responses to

the higher energy prices of the 1970s and early

1980s. Strongly reflecting the economic policy

framework of its analysis, the NES concluded that

“Our stock of housing and appliances is still far

less energy efficient than would be economically

optimal.’ ’34 Among the ‘‘significant market barriers’ in the residential sector identified by the

NES were:

■

✘

■

■

■

■

■

Traditional energy price regulation and ratesetting that do not reflect the full costs to society

of energy use, thus causing individual consumers to undervalue energy-efficiency investments and renewable resources.

Failure of market mechanisms to induce

adoption of economical energy-saving measures by residential customers, particularly in

situations where those who must pay for

such devices cannot expect any economic

benefits.

First-cost bias tendency of buyers (especially

builders and homebuyers) to minimize

upfront costs of residential property and

major appliances.

Mortgage lending practices that fail to consider the lower total cost of energy-saving

homes in calculating mortgage eligibility.

Low incomes of some energy users that often

make them unable to finance energyefficiency improvements no matter what the

payback period is.

Absence of credible data on reliability and

cost of energy-saving technologies for builders, architects, utility programs, mortgage

lenders, and individual consumers.

Fragmented and cyclical nature of homebuilding industry that contributes to a reluctance

to try innovative energy-saving designs,

products, and construction techniques and

■

9

9

makes concerted industry-led efficiency initiatives unlikely.

Inadequate implementation and enforcement

of energy building codes because of lack of

resources to check actual plans and construction sites and to educate builders.

Inadequate energy-efficiency investment in

public sector housing because many local

housing authorities lack funds and management incentives to improve efficiency.

Slow turnover of residential structures and

long lifetimes of heating and cooling systems.

The premise of institutional and market barriers to energy efficiency has wide acceptance

among energy analysts, government policymakers,

State regulators and utility executives. There are

others, generally economists of the classical and

neoclassical persuasions, who reject this conclusion of market failure, however. They adhere to a

belief that present energy efficiency characteristics represent the informed decisions of knowledgeable consumers who have compared alternative investment opportunities and selected energy

conservation that offers equal or better returns. 35

As will be seen in the following sections,

Federal, State, and utility programs have attempted to counter these constraints with varying

degrees of success. Reducing these disincentives

to energy efficiency will be key in attaining

energy efficiency goals.

ENERGY EFFICIENCY OPPORTUNITIES

IN THE COMMERCIAL SECTOR

The commercial sector consists of all businesses that are not engaged in transportation or

industrial activity and includes, for example,

offices; retail stores; wholesalers; warehouses;

hotels; restaurants; religious, social, educational

and healthcare institutions; and Federal, State,

34 National Energv Strategy: Powerful Ideas for Amen’ca, supra note 6, p. 42.

.

35 See tie di~ussion of ftiue of classic~ model to explain eftlciency gap or consumer behavior as noted in Florentin Kraus ~d Joseph

Eto, Lzast-Cost Utility Planning: A Handbook for Public Utility Commissioners: Volume 2, The Demand Side Conceptual andh4ethodological

Issues (Washington, DC: National Association of Regulatory Utility Commissioners, December 1988),
80 I Energy Efficiency: Challenges and Opportunities for Electric Utilities

Figure 4-3--Commerciai Sector On-site Energy

Consumption, by Source, 1990 (quadrillion Btus)

Electtr

15%

1

Coal 1 0/0

0.1

Natural gas 420/o

2.8

SOURCE: Office of Technology Assessment, 1993, based on data

from the U.S. Department of Energy, Energy Information Adminlstratlon, and the Gas Research Institute.

and local governments. In 1990 the commercial

sector accounted for about 14 percent of total

primary energy use.36 Figure 4-3 shows energy

consumption (excluding electricity conversion

and transmission losses) in the commercial sector. Electricity and natural gas each supply about

42 percent of commercial sector energy needs,

with oil (15 percent) and coal (1 percent) supplying the remainder.37

In 1990 the commercial sector consumed about

751 billion kWh of electricity at cost of $55

billion. 38 Commercial establishments made up

about 28 percent of total electric utility retail sales

in 1990. In addition to purchased electricity, a

growing number of commercial facilities have

resorted to cogeneration or self-generation to

meet some or all of their electricity demand; this

output is not included in commercial sector

electricity consumption estimates, but fuels used

to produce this power axe included in overall

commercial energy consumption.39

Figure 4-4 shows commercial electricity use by

application. Heating, ventilating, and airconditioning (HVAC) dominates, comprising 37

percent of commercial electricity use (space

heating, percent; cooling, percent; and ventilation, percent). Water heating accounts for an

additional 3 percent. Lighting accounts for an

estimated 29 percent of commercial load.40 Refrigeration (7 percent); cooking (2 percent), and

miscellaneous equipment including elevators,

escalators, office computers, printers, telephone

systems, and other commercial equipment (21

percent). Sixty percent of electricity use in

commercial establishments is for nonspace heating purposes. These nonspace conditioning applications are projected to grow faster than commercial square footage to over 65 percent of electric

load by 2010.41 The heat generated by rniscellaneous equipment add to demands for cooling, but

lowers space heating loads.

Electricity demand in the commercial sector is

driven by the growth in square footage in

commercial buildings and the intensity of service

demand-for space cooling, lighting, and office

361992 GIU B~eline Projection, supra note 8.

37 ~m~ for ~onver~ion ~d d~~~tion los~s of utifities for ~1-v@ ~mme~~ loafi, electricity WXOmtd for 69 pCm~t of total

-

energy eo nsumption by the commercial sector. O’UL Building Energy Eficiency, supra note 2, p. 24, note 37.

N DOE, Elecm”c Power Annual 1990, SUpra note 9.

w -y~o-rc~ fwi~ties ~~ogmem~~~~ ~SI ~tie most Wmrnon fiel. Opportunities to combine km~d or Ixwl@

plants with power generation abound in large institutions, and concentrated urban commercial areas. Cogeneration can add to overall efficiency

of energy use in the sector, but in part means a shift of primary energy eonsumption from the electric utility sector.

@ Es~tes of ~omme~~ ii@@ el~~~ty w VW, ~me ~~tes p~ l@~g at 40 Pennt of co~fia IOd fi@2ti31g b high

p==n~ge Of figh- 10* iJI office ~d~s. For pvses of @ @YSiS we ~ve tioP@d b estimates used in EPRI’S analysis.

41 GN 1992 B~e[ine Projection, supra note 8 and EPRI, E~cient Electrh”ty USe, SU~ note 1.
Chapter 4-Using Electricity More Efficiently: Demand-Side Opportunities I 81

42 On average, office, equipment, for example.

health care, and food service establishments are

the most energy-intensive commercial buildings.

Between 1970 and 1989, the amount of commercial square footage and electricity use each grew

by 45 percent.

43 Even so, newer commercia l

buildings have tended to be more energy efficient

incorporating more insulation, better windows,

lighting and more efficient space-conditioning

equipment, thus tempering the growth in electricity demand.

Commercial building energy intensity (i.e.,

energy use per square foot) has remained flat for

the past two decades, even as demand fo r

air-conditioning, computers and other equipment

grew. Complicating this trend has been the

growth in commercial electricity demand due to

a shift from on-site use of primary fuels-oil, gas,

and coal—to electricity. Thus primary fuel use

transferred from the commercial sector to the

utility sector, and may even have resulted in a net

increase in primary energy consumption, because

of the losses involved in electricity generation

and delivery.

At present there are over 4.5 million commercial buildings in the United States with a total of

over 61 billion square feet. 44 Each year about 1

billion square feet of new commercial space is

added—10 to 15 billion total square feet will b e

added this decade. There is great diversity in the

size and energy using characteristics of these

commercial buildings. Smaller commercial building energy systems are similar to those in houses

and small apartment buildings. Larger buildings,

however, have complex HVAC systems an d

activities inside the building-lighting, occupancy, electric and other equipment-can add to

energy demand and determine equipment choices.

Buildings larger than 10,000 square feet make up

Figure 44-Commercial Sector Electricity

Use by Application, 1987

Ventilation

9Y0

Heating

v

i

9%

Refrigeration

7

Wate

,/’

/’Off Ice equip

7% —..

Cooking

2%

r heating

30/0

ment and

miscellaneous

21 “/0

SOURCE: Office of Technology Assessment, 1993, based on data

from the Electric Power Research Institute and U.S. Department of

Energy.

almost 80 percent of building square footage and

offer many opportunities for electricity savings.

9 Energy Efficiency Technologies for the

Commercial Sector

Space-conditioning, lighting, and building shell

weatherization are primary targets for improving

energy efficiency and saving electricity in the

commercial sector. In addition, large commercial

buildings are suitable targets for utility load

management programs designed to shift energy

use away from peak hours, but not necessarily

resulting in lower overall energy demand, through

installation of technologies such as storage heating and cooling systems. There are also potential

energy savings in other commercial applications.

See table 4-3.

42 S= Ow, Building Energy Efficiency, SUPtZt note 2, at p. 21.

43 ME, Ann~l Energy Review 199], Supra nOte 31.

44 u.S. Depment of Energy, Ener~ Information ~“ “stratiom Commercial Building Characteristics 1989, DOE/EIA-0246(89)

(washingto~ DC: U.S. GOV ernment printing Office, January 191) table 61, p. 122; hereafter DOE, Cornmerciaf Building Characten”stics

1989,
82 I Energy Efficiency: Challenges and Opportunities for Electric Utilities

Table 4-3-Selected Energy Efficiency Technology Options for the Commercial Sector

Heating, ventilation, and alr-condltlonlng (HVAC) systems

Building envelope efficiency improvements

~ Weatherstripping and caulking

■ Insulation

~ Storm windows and doors

■ Window treatments

Space heating

improved commercial heat pumps

Air-source heat pumps

■ More efficient models

= Improved technology

Ground-source heat pumps

Heat recovery systems

Energy management controls and systems

■ Set-back thermostats

■ Smart buildings and smart systems

■ Zoned heat systems

Thermal storage systems

Cogeneration systems

District heating systems

Space cooling

More efficient cooling systems

Cool storage systems

District cooling systems

Vent//at/on

Air distribution systems

D Improved insulation

■ Reduced duct and damper leakage

= Separate make up airflows for cooling exhaust systems

■ Economizer controls

Improved HVAC maintenance

Integrated HVAC systems

WaterheatIng

Blanket wrap for water tanks

Commercial heat pump water heaters

Integrated heating and hot water systems

Heat recovery water heat systems

Increased insulation of tanks and pipes

Flow restrictors

Service/point of use water heaters

Commercial lighting

Delamping

Lighting fixture retrofits

Electronic ballasts for fluorescent

High-effidency lamps

Reflectors

Increased use of daylighting

High-intermit y lighting applications

Increased use of task lighting

Compact fluorescent

(LED) signs

Lighting control systems: timers, occupancy sensors,

photocells, dimmers

Commercial refrigerators and freezers

Efficient motors and controls

Improved insulation and seals

Commercial cooking

Energy+efficient commercial electric ranges, stoves, fryers,

ovens and broilers

Microwave cooking

Convection cooking

Induction cooking

Miscellaneous electrical equipment and office machines

More efficient motors and drives for elevators, escalators,

and other building systems

Improved hardware and software for office equipment

Integrated building energy management and control

systems

SOURCE: Office of Technology Assessment, 1993.

Analysis of potential efficiency opportunities

by EPRI found that commercially available electric equipment could reduce commercial electricity in year 2000 by 22 to 49 percent from what

consumption would be without the use of these

technologies if efficiency were frozen at 1987

levels. Commercial applications with the most

significant savings potential in the EPRI analysis

were lighting, cooling, and miscellaneous electric

equipment.

IMPROVEMENTS IN COMMERCIAL BUILDING

EFFICIENCY

Turnover of commercial building space is more

rapid than residential, but it is evident that a large

portion of commercial space in use for the next

few decades is already in place. Analysts estimate
Chapter 4–Using Electricity More Efficiently: Demand-Side Opportunities I 83

that one-half of the commercial space in 2010 has

already been built, and 80 percent of the existing

stock of commercial buildings will still be in use

for the next 30 years.45

The pace of new commercial construction

provides opportunities for efficiency gains in both

building shell, equipment, and appliances. Measures to increase the efficiency of commercial

buildings include improved design, siting, and

construction techniques, better insulation, and

more efficient equipment choices.

The remodeling and rehabilitation of commercial space offers additional opportunities. There is

considerable potential for energy-efficiency improvements in existing commercial buildings.

According to DOE surveys, while 84 percent of

buildings are reported to have installed building

shell conservation features, there remains a considerable pool of buildings that have not installed

basic measures. The most frequently reported

measure is ceiling insulation, 67.5 percent, weatherstripping or caulking, 61 percent, and wall

insulation, 47 percent. Storm windows and multipleglazing were reported in 32 percent of buildings,

and shades and awnings and reflective shading

glass or films were reported for 21 percent of

buildings. %

HEATING, VENTILATION, AND AIR-CONDITIONING

Space Heating. Just under one-quarter of

commercial buildings rely on electric heating

systems. 47 Most of these buildings are located in

the South and West.

Installation of more efficient electric heating

equipment, such as heat pumps instead of resistance heat, coupled with a combination of measures such as building shell improvements, window treatments, heat recovery, and improved

maintenance practices can cut electricity demand

for space heating. Further savings are possible

with integrated heat pump systems that provide

heating, cooling and water heating. These potential savings are offset by the expected increase in

heating load attributable to reduced internal

heating gains from installation of energy-efficient

lighting measures. Use of the best available

energy efficiency measures could reduce space

heating electricity demand in 2000 by 20 to 30

percent from what would be required from the

1987 stock of commercial buildings and equipment, according to EPRI.

District heat, in which a central plant provides

heat, and often hot water for all buildings within

a complex or downtown area, also offers efficiency opportunities, particularly if coupled with

cogeneration. 48

Cooling. Commercial cooling loads are the

biggest component of summer peak load for most

utility systems. Over 70 percent of commercial

buildings have cooling systems and 96 percent of

these systems are electric. Common commercial

cooling equipment includes packaged cooling

system, individual air-conditioners, central chillers, and heat pumps. Often these systems are

integrated with the building ventilation and air

transport systems. Commercial cooling load is

driven by building size, external temperature, and

internal heat gains from electric and other equipment and occupants. Over 6 percent of commercial buildings maintain separate cooling systems

for computer areas.49

Energy-efficient cooling options for commercial buildings include more efficient airconditioners, heat pumps, high-efficiency chillers, chiller capacity modulation and downsizing,

window treatments, radiant barriers, energy management control systems, and improved operation

and maintenance. Reduced internal heat gain

45 O& Wdge National Laboratory, supra note 16, p. 45.

46 ME, Comrcial Building Characteristics 1989, supra note 44, table 103, pp. 198-199.

47 fiid., table 66, p. 132.

48 See dismsion of disrnct hmt in OTA Building Energy Eficiency, Sllpm IIOte z, p. @.

49 ME, c’o~rcial Bu&.fhg Characteristics 1989, supra note 44, table %, p. 183.
84 I Energy Efficiency: Challenges and Opportunities for Electric Utilities

from installing efficient lighting systems also cuts

cooling load. Excluding lighting-related savings,

EPRI estimated that cooling requirements can be

reduced by 30 percent or more in commercial

buildings. Including lighting efficiency packages

with cooling system improvements could provide

total savings of over 80 percent according to EPRI

estimates. However, the need to find replacements for CFCS now used in cooling systems

could result in newer cooling technologies that

may reduce some possible efficiency gains. EPRI

therefore estimates maximum potential electricity

savings in commercial space cooling in 2000 to

be from 30 to 70 percent over 1987 performance

levels. 50

Another energy efficiency strategy for commercial cooling that may not always result in a net

reduction in electricity demand is the use of cool

storage systems that shift all or part of a buildings’ air-conditioning electricity demand from

peak to off-peak hours. Typically, ice or chilled

water is produced in a refrigeration system at

night and used to meet some or all of the next

day’s air-conditioning needs. Cool storage systems offer financial savings for customers

through lower off-peak rates and peak reduction

for utilities.51

Ventilation. Air transport and ventilation systems are a critical component of modern large

commercial buildings. Improving the energy

efficiency of ventilation and air transport systems

can be attained through a variety of measures:

viable air volume systems; low-fiction air distribution designs; high-efficiency electric motors;

variable speed drives; heating, cooling, and lighting improvements; and improved operation and

maintenance practices. EPRI estimates that ventilation electricity use can be reduced by 30 to 50

percent through a comprehensive package of

measures.

Compact fluorescents, which use 75 percent less

energy than standard incandescent lamps, are

available in a variety of designs.

LIGHTING

About 29 percent of commercial electricity

consumption is for lighting. Commercial lighting

requirements are met with a combination of

incandescent, fluorescent, and high-intensity discharge lamps and most commercial buildings

have a mixture of these fixtures. Fluorescent

lamps are already extensively used in the commercial sector. About 78 percent of commercial

floorspace is lit with fluorescent and highefficiency ballasts have been installed in about 40

percent of this space.52

A range of cost-effective technologies is available to cut lighting loads. Ready savings can be

achieved in many commercial buildings by delamping to lower lighting levels, using lower

wattage fluorescent, and replacing incandescent

with more efficient fluorescent or compact fluorescent lamps where appropriate. More advanced

lighting system efficiency upgrades include installation of high-efficiency electronic ballasts,

aluminum and silver film reflectors, daylight

dimming, occupancy sensors, use of high-

~ EPIU, Eflcieru Elecrn”city Use, sup~ IIOk 1, P. 50.

51 EPRI, DSM Technology Alterw”ves, supra note 26, pp. B-394.

52 ME, Co~rcia/Bui~ing Characteristics f989, supra note 44, table 101, p. 195, It is not repod whether the h@-efflCieIKY -G

have been installed in all fluorescent fmtures lighting these spaces.
Chapter 4-Using Electricity More Efficiently: Demand-Side Opportunities I 85

pressure sodium lamps instead of mercury vapor

lamps in high-intensity discharge fixtures. In new

construction and remodeling, better lighting system design and greater use of daylighting can also

cut lighting requirements.

Estimates of lighting savings involve interactions among package components and are not

necessarily the sum total of individual measures.

Building characteristics also influence potential

savings. In addition lighting upgrades can cut

cooling costs by reducing internal heat gain, but

add to heating loads. EPRI estimates potential

electricity savings from more efficient commercial lighting in 2000 to range from 30 to 60

percent over 1987 stock.53

COMMERCIAL REFRIGERATION SYSTEMS

Commercial refrigeration in retail stores, restaurants, and institutions can be a significant load.

About 20 percent of commercial buildings are,

equipped with commercial refrigeration systems;

about 16 percent have commercial freezers. EPRI

estimates that commercial refrigeration electricity use can be cut by 20 to 40 percent from 1987

performance levels by combining a variety of

efficiency improvements. Examples include: more

efficient fan motors and compressors, multiplex

unequal parallel compressors, advanced compressor cycles, variable speed controls, evaporatively

cooled condensers, floating head pressure systems, air barriers, food case enclosures, electronic

controls, and improved maintenance practices.

Electricity savings are highly site specific and

depend on previous saturation of these technologies.

WATER HEATING

About 48 percent of commercial buildings with

hot water systems54 use electricity as the sole or

supplemental water heat source. Hot water heatElectronic ballasts can cut fluorescent lighting energy

use by 20 to 25 percent.

ing accounts for about 3 percent of commercial

electricity use.

There are a number of efficiency measures for

commercial hot water systems on the market.

These measures include many also used in

residential applications, such as water heater

wraps, low flow devices, hot water pipe insulation, and installation of valves that reduce convection loses. Commercial heat-pump water heaters and heat recovery systems can provide energy

savings of one-third or more over conventional

resistance systems. Integrated heat pumps can

provide heating, cooling, and hot water for

commercial buildings. Lowering the hot water

thermostat can reduce electricity use while still

providing adequate water temperatures for most

uses. EPRI estimates potential savings in water

heating electricity use in 2000 of 40 to 60 percent

over 1987 stock.55

COOKING

Commercial cooking equipment accounts for

about 2 percent of commercial sector electricity

use. Microwaves, convection ovens, and magS3 Om, BuilA”ng Energy Eficiency, supra note 2, p. 50, for eStkWw Of SWklgS ti *C Co~emM smtor.

~ ME, Comrcial Building Characteristics 1989, supm note 44, table 76, p. 1%.

55 EPRI, Eficient Electricity Use, SUpm note 1, p. 51.
86 I Energy Efficiency: Challenges and Opportunities for Electric Utilities

netic induction cooktops can cook food with less

time and energy than more conventional electric

stoves and ovens and are seeing greater use in

commercial establishments. A range of technological improvements are available to cut electricity use in commercial ranges, ovens, broilers,

griddles, and fryers. Examples include: increased

insulation, better heating elements, more precise

temperature controls, reflective pans, reduced

thermal mass, and less contact resistance. EPRI

estimates that by incorporating a combination of

efficiency measures, electricity use by commercial electric stoves and ovens in 2000 could be

from 20 to 30 percent less than that required for

1987 stock.56

MISCELLANEOUS COMMERCIAL SYSTEMS

AND EQUIPMENT

Residual electric systems and equipment (e.g.

elevators, escalators, telephone systems, office

machines, food preparation and other equipment)

account for 21 percent of commercial sector

electricity use and will continue to grow.

EPRI estimates that overall savings from expected efficiency advances in miscellaneous commercial sector equipment will range from 10 to 30

percent. Expected improvements in hardware,

software, and system operations could offer

maximum potential savings of up to 50 percent

for office equipment in 2000. EPRI also calculates maximum potential savings of up to 35

percent in 2000 from the use of high-efficiency

motors and adjustable-speed drives in elevators

and escalators.57

The Federal Government, through the Environmental Protection Agency’s green programs and

Federal procurement policies, is seeking to overcome some of the market barriers to more

energy-efficient computer equipment. (See box

4-D.)

I Barriers to Energy Efficiency in the

Commercial Sector

There remains a significant gap between the

electricity-using characteristics of the present

stock of commercial buildings and equipment and

the energy-saving potential of the most efficient

buildings and equipment marketed today. As with

the residential sector, many economic, institutional, and behavior influences hamper greater

commercial sector investment in energy efficiency.

Some influences are shared with other sectors.

The normally slow turnover in commercial buildings and major equipment, albeit more rapid than

in the residential sector, means that actual efficiency savings lag considerably behind technical

potential. Relatively low energy prices that do not

reflect all societal and environmental costs of

energy production and use also lead to undervaluing of energy and underinvestment in efficiency

by commercial consumers. (This persists even

though commercial customers are in general more

price-sensitive than residential customers, and

utility bills for commercial establishments can be

quite large.) Choices affecting commercial energy demand are made by a large number of

decisionmakers — architects, designers, developers, building owners, tenants, equipment manufacturers and vendors, and local building authorities. The plethora of decisionmakers and the

absence of any direct economic benefit in efficiency for many of them lessens the impact of

existing weak financial incentives and fragrnents

the potential constituency for efficiency improvements.

Several factors contribute to limited financial

incentives to invest in efficiency. Energy costs of

buildings can often be a small fraction of total

business expenses and thus gain little management attention as a means of saving money .58

56 Ibid.

57 Ibid., p. 52.

56 ficor~g to some estimates, for large office buildings and retail space energy ‘osts are less than 5 per~nt Of total mud operatig costs

per square foot and are dwarfed by other business costs. OTA, Building Energy E@ciency, supra note 2, pp. 81-82,
. . .

Chapter 4-Using Electricity More Efficiently: Demand-Side Opportunities 187

Box 4-D-EPA and Green Computers

Computer equipment and other electric office machines are among the fastest growing components of

commercial energy consumption. They now total about 5 percent and are expected to total 10 percent by 2000.

Surveys have determined that most personal computers are left turned on when not in use during the day,

overnight and on weekends. Desktop computers typically have been designed with Iittle consideration for energy

efficiency, unlike portable or laptop models that incorporate a number of energy-saving measures to save battery

power. if desktops were equipped with technologies that allowed them to “nap” or shutdown when not in use and

return quickly to full power capability when needed, EPA estimated that such computers could save 50 percent

of the energy used to run them. Green computers thus became one of the first commercial consumer products

targeted by EPA’s pollution prevention programs to increase consumer and manufacturer awareness of energy

efficiency benefits, and to create a new market for energy-efficient equipment.

Using a model similar to the Green Lights Program (see chapter 7), EPA entered into discussions with

manufacturers of computers, peripherals, and microprocessors. Manufacturers agree to produce products that

meet certain efficiency improvements and sign a mernorandum of understanding with EPA. The manufactures are

then eligible to use the “Energy StarTM-

EPA Pollution Preventer” logo in the

marketing and displaying of the products. For example, personal computers

with the capability of switching to a low

power mode of 30 watts or less (about

75 percent less than current models)

qualify for the EPA logo that identifies

new high efficiency equipment. EPA is

expanding the use of such voluntary

agreements for related computer products including printers, monitors and

other pieces of office equipment.

By May 1993 EPA had reached

agreement with an impressive array of

companies producing personal computers and related products. Charter

partners in EPA’s Energy StarTM computer program represent 60 percent of

Energy Star Computers could save enough electricity each

year to power Vermont and New Hampshire, cut electricity

bills by $1 billion, and reduce CO2 pollution equivalent to

emissions from 2.5 million autos.

the U.S. market for computers and monitors, and 60 percent of the laser printer market. An Energy StarTM allies

program has been established enlisting agreements from components and software makers. Intel Corporation,

one of the world’s major microprocessor manufacturer, has committed to incorporating energy-saving technologies

into all future microprocessors. The first products bearing the Energy Star logo will be available in 1993.

The widespread penetration of energy-saving computer technologies offers significant benefits to

consumers, the economy, and the environment. The cost of operating a typical 150-watt personal computer 24

hours per day year round can be $105/year (assuming electricity costs at $0.08/kWh) and uses 1,314 kWh/yr.

Turning the machine off at night reduces the operating cost to $35/year and cuts energy consumption to 433

kWh/year. Using technology that conserves power when the machine is not active during the day could cut costs

to $1 7/year for 216 kWh/year. EPA estimates that green computers could save a total off $1.5 to $2 billion in annual

electricity bills and avoid emissions of 20 million tons of carbon dioxide, 140,000 tons of sulfur dioxide, and 75,000

tons of nitrogen dioxide by 2000.

SOURCES: U.S. Environmental Protection Agency, Office of Atmospheric Programs, 7992 Accomplishments and Prospecft for 1993, vol.

1: Global Change Division, EPA 430-K-92-031, November 1992, pp. 9-10. Brian J. Johnson and Catherine R. Zoi, “El% Energy Star

Computers: The Next Generation of Office Equipment,” in American Council for an Energy-Efficient Economy, ACEEE 1992 Surnmer Study

on Energy Efficiency in Buildings, vol. 6 (Washington DC: American Council for an Energy-Efficient Economy, 1992), pp. 6.107-6.114.

330-075 : QL 3 0 - 93 - 4
88 I Energy Efficiency: Challenges and Opportunities for Electric Utilities

Energy efficiency is only one consideration in

decisions affecting energy use--first-cost, appearance, comfort, and other performance features may overshadow potential lifecycle cost

savings from efficiency. Building owners and

tenants tend to place greater emphasis on occupant comfort and productivity and may be reluctant to make any changes that might affect

building operations. One-quarter of commercial

space is leased and lower energy bills offer no

incentives for building landlords when the tenants

are responsible for paying electric bills. Where

landlords pay utility bills and energy prices are

included in rent, building occupants may have

little financial incentive to choose high-efficiency

equipment or to invest in energy-savings maintenance.

59

When efficiency investments are considered,

commercial sector decisionmakers also tend to

require short payback periods of 1 to 3 years. Lack

of resources or access to capital can discourage

some possible commercial sector efficiency investments, particularly for nonprofit institutions

and small businesses. Cost-effective, low-risk

measures that could cut operating costs are often

given low priority in government facility management. Even when government facility managers

are aware of potential savings, budgetary and

procurement constraints limit investments in

efficiency for government owned or occupied

facilities. 60

The energy efficiency industry is still in its

infancy and the small pool of trained vendors,

installers, and auditors available to serve commercial establishments and utility programs can

limit achievable energy savings at least in the

short term. The relative newness of the industry

and absence of a proven track record of delivering

savings may make many in the commercial sector

reluctant to make significant investments in

energy efficiency. Indeed, savings from early

building retrofit investments have been less than

expected on average, and unpredictable for individual buildings, adding to the perceived riskiness of the investment.61

Nevertheless, the commercial sector remains a

prime and potentially profitable target for utility,

private sector and government efforts at improving energy efficiency.

ENERGY EFFICIENCY OPPORTUNITIES

IN THE INDUSTRIAL SECTOR

The industrial sector includes both manufacturing enterprises (i.e., businesses that convert raw

materials into intermediate or finished products)

and nonmanufacturing enterprises, such as agriculture, forestry, fishing, construction, mining,

and oil and gas production. The industrial sector

is characterized by the diversity of energy uses,

equipment, and processes and is the largest

energy sector, consuming 37 percent of U.S. total

primary energy use in 1990. Patterns of industrial

energy use are further complicated by the use of

oil, gas, and coal as feedstocks and for cogeneration. Figure 4-5 shows industrial energy use for

fuel and power only.

Industrial energy use is variable, reflecting

economic conditions, structural changes, interfuel competition, and rate of investment. Patterns

of industrial energy use and energy intensity of

industry also vary significantly by region. Price is

the major determinant in most industrial energy

choices, and head-to-head competition among

fossil fuels is intense. Price however is not the

sole consideration—availability, reliability, and

quality also drive industrial energy decisions.

Another trend is the growth in industrial cogeneration, which is generally viewed as a positive

development for efficiency, but, which in effect

transfers demand and losses between industrial

59 lbici., p. 54.

60 U.S. Congess, office of ‘fkChnOIOW Assessment Energy Eficiency in the Federal Government: Government by Good Example?

OTA-E492 (Washington DC: U.S. Government Printing OffIce, May 1991).

61 OW Mdge Natiod Laboratory, supra nOte 16, pp. 45-46.
Chapter 4-Using Electricity More Efficiently: Demand-Side Opportunities I 89

sector and utilities. Moreover there has been a

general trend toward electrifying many process

technologies and a shift in energy and electric

intensity of manufacturing. The relationship of

efficiency gains and structural changes in U.S.

industry was examined in detail in an OTA

background paper, Energy Use and the U.S.

Economy.

62 

A companion new OTA report,

Industrial Energy Efficiency, was published in

summer 1993.

There are five major fuel and power demands

in the industrial sector: process steam and power

generation (36 percent), process heat (29 percent),

machine drive (14 percent), electrical services(4

percent), and other (including off-highway transportation, lease and plant fuel use, and mining)

(16 percent).63 The industrial sector derives 40

percent of its fuel and power needs from natural

gas, 25 percent from oil, 15 percent from purchased electricity, 9 percent from coal, and the

remaining 9 percent from waste fuels and other

sources. Electricity competes with other fuels,

particularly natural gas, for direct heat applications. 64 For other uses, purchased electricity

competes with the options of self-generation or

cogeneration. It is estimated that in 1989, the

industrial sector produced about 153,270 gigawatthours of electricity on-site. Surplus electricity

production was sold to local utilities.65 To avoid

doublecounting, fuel used for industrial selfgeneration or cogeneration is usually attributed to

primary fuels.

In 1990 industrial consumers purchased 946

billion kWh from electric utilities at a cost of $45

billion.66 Sales to industrial users accounted for

35 percent of electric utility revenues from sales

to end-users/ultimate customers. Electricity consumption in the industrial sector is divided among

Figure 4-5--industrial Energy Use for Fuel and

Power, 1989 (quadrillion Btus)

Natural gas 39%

Ott

14%

\ /

2.8

Electricity 160/!

3.1

SOURCES: Office of Technology Assessment, 1993, based on data

from the Gas Research Institute.

the manufacturing enterprises (87 percent); agriculture (5 percent) and construction and mining (8

percent).

The major industrial electricity uses are motor

drive, electrolytic, process heat, and lighting (see

figure 4-6). Table 4-4summarizes EPRI estimates

of 1987 industrial energy consumption for these

applications by industrial subsectors (SIC codes),

manufacturing loads and nonmanufacturing loads.

The most electricity-intensive manufacturing

activities (including on-site generation) are chemical products, primary metals, pulp and paper,

food, and petroleum refining, together accounting

for more than half of manufacturing electricity

use. The pulp and paper and chemical products

62 us. Conwess, ~lce of~~olon Aswssment, Energy Use and the U.S. Economy, OTA-Bp-E-57 ~~~wo~ ~: us@ve-ent

Printing Olllcz, June 1990).

6J 1992 Gw Baseline Projection, supni note 8, P. 36.

a Ibid, p. 41.

65 fiid.

66 DOE, Electric power Annual 1990, supra note 10, table 1.
90 I Energy Efficiency: Challenges and Opportunities for Electric Utilities

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Chapter 4-Using Electricity More Efficiently: Demand-Side Opportunities 191

subsectors have significant cogeneration capacity-mostly freed by waste fuels.

Figure 4-8-industrial Electricity Use

by Application, 1987

9 Efficient Industrial Technologies

There are several strategies for improving

energy efficiency in the industrial sector, including making existing electricity applications more

efficient, shifting industrial processes from fossil

fuel to electrotechnologies for net energy savings,

and using more industrial cogeneration for net

energy savings over purchased electricity.

EPRI estimates that application of more efficient industrial equipment and processes offers

potential savings of from 24 to 38 percent of their

projected base-case electricity use in 2000.67 The

most promising targets for potential efficiency

gains are high efficiency electric motors and

variable speed drives, improved electrolytic processes, industrial process waste heat recovery, and

more efficient lighting technologies. (See table

4-5.) All but electrolytic technologies have a wide

and diverse range of potential applications across

the industrial sector.

ENERGY-EFFICIENT ELECTRIC

MOTORS AND DRIVES

There is great diversity in industrial applications of electric motors and drives: pumps, fans,

compressors, conveyors, machine tools, and other

industrial equipment. Motor drive end-uses account for an estimated 70 percent of electricity

load in

motors

(ASDS)

tential.

manufacturing. High-efficiency electric

combined with adjustable-speed drives

offer significant electricity savings poctrolytlcs

12%

I -/0 Lighting Process heat

10“/0 10“/0

SOURCE: Office of Technology Assessment,

from the Electric Power Research Institute.

Electric motors are available

1993, based on data

in standard and

high-efficiency models and energy efficiency of

both vary according to size. In general, larger

motors are more efficient than smaller ones in

both standard and high efficiency models. The

high-efficiency models cost from 10 to 30 percent

more than the standard versions,68 but have

efficiency increases of 8 percent for smaller

motors and 3 percent for larger motors.69 Energyefficient motors typically have longer operating

life than standard motors. The initial capital costs

of electric motors are usually only a fraction of

their operating costs. For example, annual energy

costs for an electric motor might run as much as

10 times its initial capital cost; increasing its

efficiency from 90 to 95 percent could mean

67 EpW, Eficient Electn”ciry Use, suprs flOte 1, p. 61.

68 ~efica Comcll for ~ Energ.mlclent ~onomy ~d New York State Energy OffIce, The fihievable conservation Potentiaf in New

York Statefiom Utility Demand-Side Management Programs, final repo~ Energy Authority Report 90-18 (Albany, NY: New York State

Energy Resmch and Development Authority, November 1990), p. 48.

@ EPRI, DL5’M Technology Alternatives, supra note 26, P. e~l.
92 I Energy Efficiency: Challenges and Opportunities for Electric Utilities

Table 4-5-Selected Energy Efficiency Technology

Options for the Industrial Sector

Electric motors and drives

. High-efficiency motors

■ Variable speed drives

. Optimal sizing of motors and loads, serial motors

Waste heat recovery systems

■ Industrial process heat pumps

. Industrial heat exchangers

, Vapor recompression systems

Electrolytic processing

Chlor-alkali production

■ Improved membrane and diaphram cells for chlor-alkali

production

Aluminum smelting

, Improved efficiency in Hall-Heroult smelting process

■ Alternative aluminum reduction technologies

industrial Lighting

Delamping

Lighting fixture retrofits

Electronic ballasts for fluorescents

High-efficiency lamps

Reflectors

Increased use of daylighting

High-intensity lighting applications

increased use of task lighting

Compact fluorescents

LED signs

Lighting control systems-timers, occupancy sensors,

photocells, dimmers

industrial eiectro-technologies

Plasma processing

Electric arc furnaces

Induction heating

industrial process heat pumps

Freeze separation

Ultraviolet processing/curing

industrial cogeneration systems

High-efficiency industrial boilers

Integrated process heat/steam and power production

SOURCE: Office of Technology Assessment, 1993.

savings of 50 to 60 percent of its capital costs in

a single year.70

Many industrial motors are often run at less

than maximum power because of varying loads.

Electronic adjustable speed drives allows an

electric motor to operate at reduced speed when

maximum power is not needed, saving energy.

ASDS are appropriate in applications with high

operating hours where motors are often operated

at less than full load.

There are three targets for displacing standardefficiency motors with high-efficiency motors:

selecting new or replacement motors, rewinding

of existing motors, and retrofitting of existing

motors that do not need repair or replacement.

High-efficiency variable-speed motors offer

tremendous potential for efficiency. Various studies have yielded estimates of potential savings of

20 to 50 percent depending on circumstances for

application of ASDS. Use of high-efficiency

electric motors can provide savings of an additional 3 to 10 percent. Overall efficiency improvements in motor drive of 35 to 50 percent over

1987 equipment were assumed in EPRI’s analy -

sis.71 Motor drive improvements offered nearly

80 percent of estimated savings in their analysis,

with over 90 percent of these savings in just a few

industry categories.

WASTE HEAT RECOVERY

Waste heat recovery systems improve energy

efficiency by using heat from fuel combustion or

excess thermal energy from a process steam

product. An estimated one quarter to one-half of

the process heat used by industry is discharged as

hot gases or liquids. 72 There are various approaches to capturing energy from these sources

of waste heat. The choice depends on characteristics of the heat source, process needs, and

economics. Heat exchangers are used to transfer

heat from a high-temperature waste exhaust

source, such as combustion gases, to a cooler

supply stream such as steam for lower temperature uses. Low-temperature waste heat streams

70 U.S. con~ess, C)ffke of lkchnology Assessment, Indusm”a/ Energy Use, OTA-B 198 (Washington, DC: U.S. Government Printiw

OffIce, June 1983) p. 50. (Available from the National ‘lkclmical Information Service, Sprin@leld, VA, NTIS Order #PB83-240606.)

71 EPFU, Eficient Electricity U.$e, supra nOte 1, p. 59.

72 Em, DSM Technology Alternatives, supra note 26, p. c-8.
Chapter 4–Using Electricity More Efficiently: Demand-Side Opportunities 193

can be upgraded to supply heat for highe r

temperature processes via industrial heat pumps

or vapor recompression systems, Analyses for

EPRI found that installation of heat recovery

devices can reduce a plant’s overall energy

requirements by at least 5 percent with paybacks

of less than 2 years. The most cost-effective time

to incorporate the systems is during new construction or modernization projects and most applications have been custom designed. Heat recovery

devices displace conventional energy sources

(such as purchased electricity) and are used in

processes requiring a constant heat source. Hence

they are attractive to utilities as means to reduce

base loads and peak loads,

Waste heat recovery in industrial process heat

systems can provide electricity savings of 5 to 25

percent according to EPRI estimates. Very little

waste heat recovery currently exists, so there is

potential for significant improvement. EPRI assumed an average of 10 to 15 percent savings.

ELECTROLYSIS

An estimated 12 percent of industrial electricity use is used for electrolysis. Electrolysis is a

method for separating and synthesizing chemicals

or metals by using electricity to produce chemical

reactions in aqueous solutions or molten salts. At

present the two largest industrial applications of

electrolysis are aluminum reduction in the primary metals processing industry and the production of chlorine and caustic soda from salt brines

in the chemical products industry.

Electricity is the most costly material in

aluminum production. In the century-old HallHeroult process alumina refined from bauxite ore

is reduced via electrolysis to molten aluminum, 73

The smelting process is continuous. Alumina is

dissolved in a molten electrolytic bath in carbon

lined steel cells or pots, In each pot a direct

current is passed from an carbon anode suspended

in the cell through the bath to the carbon lining of

the cell producing a chemical reaction. Molten

aluminum is siphoned from the bottom of the pots

and is then formed into aluminum ingots or

further refined and/or alloyed into fabricating

ingot. A single potline can consist of from 50 to

200 cells with a total voltage of 1,000 volts at

currents of 50,000 to 250,000 amperes. U.S.

smelters use from 6 to 8 kWh to produce each

pound of aluminum.

The efficiency of aluminum production has

improved steadily. Following World War II about

12 kWh of electricity was needed to produce one

pound of aluminum; today, through greater economies of scale and process controls, the most

efficient smelters use half that electricity per

pound.74 Further efficiency gains are promised by

advanced electrolytic reduction methods including bipolar cells, inert anodes, and wettable

cathodes. None of these technologies, however is

currently installed, but EPRI estimates that they

could potentially yield efficiency savings by year

2000 of some 30 to 50 percent over current

methods. These improvements are highly attractive given the high electric intensity of aluminum

production and are significant for regions where

such production is concentrated, such as the

Pacific Northwest.

Chlor-alkali production is second to aluminum

in terms of electricity consumption and uses

about 30 percent of electric power used for

electrochemical production .75 Chlorine and caustic soda (sodium hydroxide) are produced from

salt brine by electrolysis in either the diaphragm

or mercury cell. Mercury cells account for about

20 percent of U.S. capacity. Throughout this

century economies of scale have produced steady

efficiency gains in chlor-alkali production as

newer and larger cells required less energy to

73 U.S. Congress, Office of Tmhnology Assessment, Nonferrous Metals: Industry Structure: Background Paper, OTA-BP-E-62

(Washington, DC: U.S. Government Printing Office, September 1990), pp. 25-26.

74 Ibid.

75 EPRI, D.$14 Techno[o~v Alternatives, supra note 26, pp. c-5-c-6.
94 I Energy Efficiency: Challenges and Opportunities for Electric Utilities

drive the chemical reactions.76 In the membrane

cell, different constituents of the solution are

separated by selective diffusion through the

membranes. EPRI analyses estimated that use of

membrane cells to replace diaphragm cells could

save 10 percent of electricity used in chlor-alkali

production. Other analyses have estimated savings of up to 25 percent over current methods.

Adaptation and improvement of electrolytic

separation methods, including electrodialysis which

uses electric current to accelerate membrane

separation, for other inorganic and organic processes also can yield efficiency gains over conventional methods.

LIGHTING

Lighting accounts for about 10 percent of

electricity use in the industrial sector. As in the

commercial and residential sectors, more efficient

lighting technologies offer promises of electricity

savings across the industrial sector too, Industrial

lighting efficiency upgrades such as delamping,

reduced wattage fluorescent, high-efficiency ballasts, reflective fixtures, occupancy sensors, replacing incandescent lamps with compact fluorescent, and greater use of daylighting. EPRI

analyses estimate that lighting efficiency packages offer savings of from 36 to 49 percent.

Lighting upgrades can also lower cooling loads,

but increase heating loads.

ELECTRIFICATION OF INDUSTRIAL PROCESSES

Electrification offers the potential for net

savings in fossil fuel use even as it increases

electricity demand in the industrial sector. There

has been a continuing trend toward electrification

of many industrial processes and end-uses. Cost

has been a major factor, but increasingly, reliability, flexibility, and reduced environmental impacts on-site have made electrification an attractive option for improving industrial productivity.

There are a variety of electrotechnologies that

could boost industrial electricity use over the next

several decades, while providing net savings in

fossil fuel consumption. EPRI looked at the

possible net energy savings from five such

technologies.

Freeze concentration uses refrigeration processes to separate and concentrate constituents

from mixed dilute streams. Separation of constituents from process streams is a major energy use

in the industrial sector and many techniques such

as distillation rely on high temperatures produced

by burning fossil fuels. It takes less energy (about

150 Btu) to freeze a pound of water than the 1,000

Btu needed to boil it.77 Shifting to freeze separation could cut overall energy consumption and

displace industrial fossil fuel use. More energyefficient refrigeration technologies add to the

attractiveness of freeze concentration as an alternative separation technique. Currently used for

treating hazardous wastes, concentrating fruit

juices, and purifying organic chemicals, the

technique is being investigated for broader industrial application.

Industrial process heat pumps can replace

indirect resistance heating for certain low temperature applications (below 280 to 3000 F) in

lumber, pulp and paper, food, chemical, and

petroleum subsectors.

Electric arc furnaces allow direct melting of

raw steel and uses less energy than fossil-freed

furnaces. Electric arc furnaces have already

gained a significant foothold in the steel industry

accounting for an estimated 34 percent of steel

produced in 1985. Continuation of this trend to 56

percent or more by 2000 was projected. Electric

arc furnace foundries are also used to produce

steel castings and increased use of this technology

also promises net fossil fuel savings.

Plasma processing uses a high intensity electric arc to generate ionized gases at temperatures

up to 10,000° F and more, far exceeding the

76 om, I~~m”aI Ener~ Use, supra note 70, p. 123-124.

77 O* ~dge Natio~ Laboratory, supra note 16, p. 71.
Chapter 4-Using Electricity More Efficiently: Demand-Side Opportunities 195

2,8000 F practical limit for fossil fuel combustion.78 The technology offers high energy density

and temperature capability, controllability, and

fuel flexibility compared with conventional combustion technologies. Plasma processing can be

expanded in already established uses for cutting,

welding, heat treating, and burning and into

promising new applications in electric arc furnace

dust processing, cupola refits with plasma torches,

ferroalloy production, and ore reduction. Use for

chemical production also is said to have future

commercial potential.

Ultraviolet curing uses ultraviolet radiation

produced by ionizing gases in an electrical arc or

discharge, such as in a high-pressure mercury

vapor lamp, to change the molecular structure of

a coating to make it a solid. UV curing offers large

energy and cost savings compared with thermal

curing and is expected to gain increasing market

penetration especially in quickcuring applications. An additional and significant environmental and health benefit is the elimination of

solvents in the curing process.

Potential Savings. EPRI estimates that all

these technologies offer strategic load growth to

electric utilities, while resulting in net savings in

fossil fuel use overall. Maximum application of

these technologies could add 319 trillion Btu of

fossil fuel in electric utility generation, but at the

same time yield a net savings of 290 trillion Btus

in these industrial processes.

COGENERATION

Cogeneration is the simultaneous or sequential

production of both electrical or mechanical power

and thermal energy from a single energy source.79

On-site industrial cogeneration has grown significantly since the late 1970s as a result of higher

energy prices, volatile energy prices, and uncertainty over energy supplies. Implementation of

the Public Utility Regulatory Policies Act of 1978

(PURPA), which required electric utilities to

provide interconnections and backup power for

qualifying cogeneration facilities and to purchase

their excess power at the utilities’ avoided cost,

reduced institutional barriers to the expansion of

cogeneration. PURPA was intended to promote

industrial cogeneration as a means of improving

efficiency especially in the use of premium fossil

fuels (gas and oil) and encouraging the use of

waste fuels.

In most industrial cogeneration systems, fuel is

burned frost to produce steam that is then used to

produce mechanical energy at the turbine shaft or

to turn the shaft of a generator to produce

electricity. The steam leaving the turbine is then

used to provide process heat or drive machines

throughout the host industrial plant and related

facilities. From an energy policy perspective, the

attraction of cogeneration is the ability to improve

fuel efficiency. Cogeneration systems achieve

overall fuel efficiencies 10 to 30 percent higher

than if power and heat were provided by separate

conventional energy conversion systems, i.e., less

energy than if the fossil fuel were burned in an

industrial boiler to provide process heat and at an

off-site utility power plant to generate electricity

to be transmitted to the industrial site. (This

aspect of cogeneration efficiency depends on the

fuel that is burned to produce electricity) Cogeneration can also be attractive as a means of

quickly adding electric generating capacity at

sites where thermal energy is already being

produced.

Industrial cogeneration is concentrated in the

pulp and paper, chemicals, steel, and petroleum

refining industries. Often the industrial cogenerators can take advantage of waste fuels to fire their

boilers for heat and power. Natural gas has been

the fuel of choice for many qualifying cogeneration plants under PURPA.

Cogeneration does not always provide significant efficiency advantages, however. Almost the

entire output of newer combined-cycle, natural

78 EPFU, DSM Technology Alternatives, supra nOte 26, p. C-21-22.

79 OTA, Energy Technology Choices, Supra note 4, p. 39.
96 I Energy Efficiency: Challenges and Opportunities for Electric Utilities

gas-fired cogeneration systems is electric power

generation with little steam for process applications. In this case, there is a much smaller

efficiency gain from cogeneration and a net shift

in primary fuel demand from the utility sector to

the industrial sector. Thermal conversion losses

in electric utility and industrial combined cycle

generating units are similar, there are some small

savings in avoided transmission and distribution

losses. If a significant portion of the cogenerated

power is sold to the local electric utility, these

transmission and distribution gains would largely

disappear.

Industrial cogeneration makes up the overwhelming bulk of the explosive growth of so

called independent power producers in the past

decade. While cogeneration was initially viewed

by many utilities as a threat to their market share.

It is increasingly accepted as an alternative power

source and has been integrated into some utilities

load management and resource plans. In fact a

number of utility companies have independent

power subsidiaries or affiliates that are partners in

industrial cogeneration projects.

In 1989, Edison Electric Institute estimated

that cogeneration accounted for about 73 percent

of the operating capacity of nonutility power

plants. 80

Industrial cogeneration plants will benefit from

many of the same efficiency improvements as

utility generation as many use the identical

technologies. In addition, better integration of

industrial cogeneration and utility system operations through planning and dispatch offers net

improvements to system efficiencies.

1 Constraints on

Industrial Sector

There have been

Efficiency Gains in the

significant energy efficiency

gains in the industrial sector over the past two

decades. Industrial energy use per unit of output

(energy intensity) has been declining since 1970.

At the same time, more and more industrial

processes have been electrified. Even so, OTA

found that opportunities for further gains in

energy efficiency have by no means been exhausted. 81

The industrial sector faces some of the same

constraints as other sectors: low energy prices,

failure of energy prices to reflect societal and

environmental costs, multiplicity of decisionmakers, and reluctance to adopt unproven new

technologies. Energy efficiency choices tend to

be made in new investments and when equipment

must be repaired or replaced which creates a

normal lag time between the development of new

electricity-saving technologies and their dispersion throughout industry. But certain barriers are

less applicable-for example, the disconnect

between those who pay for energy-efficient improvements and those who benefit is rarely

present. Of all sectors, the industrial sector is

probably the most responsive to price signals, so

that the argument that there are market failures

resulting in an underinvestment in energy efficiency here (from the perspective of myriad

industrial consumers) is hardest to make. Nevertheless, certain characteristics of industrial decisionmaking about energy choices can result in

lower adoption rates for energy-efficient equipment than might be desirable from a societal or

utility perspective.82

~ ~on Electric lnsti~te, 1989 Capacity and Generation of Non-Utility Sources of Energy, Washington ~, Ap~ 1991, P. 29.

131 om, Energy Technology Choices, SUP nOte 4, P. 38.

82 o~ ~ e.d industrial energy investment decisionmaking in a number of reports. The most ream effort is in a forthcoming report

Indu.rm”alEnergy Eflciency, to be published in summer 1993. Other OTA reports include IndWrialEnergy Use (1983), supra note 70, Energy

Technology Choices, supra note 79; and U.S. Congress, Office of TeeImology Assessmen4 Industrial and Commercial Cogeneration,

OTA-E-192 (Washington DC: U.S. Government Printing OffIce, February, 1983). (Available from the National ‘Ikchnical Information

Service, NTIS Order #PB83-180457.)
Chapter 4-Using Electricity More Efficiently: Demand-Side Opportunities I 97

Economic considerations dominate investment

decisions in the industrial sector. For most

industries energy costs and electricity costs are

only a small part of operating costs and thus may

not enjoy a high priority. Industries that are highly

energy and electricity intensive have a stronger

incentive to invest in efficiency, while others do

not even though there may be substantial and cost

effective opportunities. Most firms regard energy

efficiency in the context of larger strategic

planning purposes. Investments are evaluated and

ranked according to a variety of factors: product

demand, competition, cost of capital, labor, and

energy. Energy-related projects are not treated

differently from other potential investments and

must contribute to increased corporate profitability and enhanced competitive position. As a result

incentives aimed at reducing energy demand

growth or improving efficiency in the industrial

sector must compete with other strategic factors

and therefore have to be substantial to make a

significant impact.

In addition to lack of strong financial incentives and management indifference, industrial

energy efficiency gains are also hampered by lack

of information, and shortages of skilled designers,

installers, and auditors. Highly specialized and

plant- or application-specific analyses are often

required to identify optimal and appropriate

energy savings improvements because of the

diversity of industrial processes, equipment, and

energy applications. President Bush’s National

Energy Strategy report found that the industrial

sector tended to underfund investment in energy

efficiency R&D because of the belief that competitors could quickly adopt process or technology

advances, thus minimizing any potential competitive advantage.83

overall, in past studies OTA has found that the

best way to improve energy efficiency in the

industrial sector is to promote general corporate

investment in new plant and equipment-newer

generally means more energy-efficient.

83 National Energy Strategy: Powerful Ideas for Amen”ca, supra note 6, P. 56.
Utility

Energy

Efficiency

Programs and m

Experience 3

w

ith ample untapped opportunities to save electricity,

demand rising but long-term growth rates uncertain,

and powerplant construction costs soaring, it is not

surprising that energy efficiency has become the

bywor for cost-conscious consumers, regulators, and utilities

seeking new ways to hedge future strategies. The potential of

energy efficiency as a means to lessen the environmental impacts

of energy use has also attracted the interest of conservationists.

The prospective new business opportunities have garnered the

attention of energy service companies and equipment manufacturers and vendors, as well as utilities.

This chapter looks at utility programs to influence customer

energy use and how they are incorporated in utility resource

options. State government efforts and regulatory treatment of

utility-sponsored conservation and efficiency programs are

discussed in chapter 6.

SCOPE OF UTILITY ENERGY EFFICIENCY PROGRAMS

U.S. utilities and State regulators have now had more than a :

---- ~>. *

#i

decade’s worth of experience with utility-sponsored energy

efficiency programs. Broadly speaking, energy efficiency programs are aimed at reducing the energy used by specific end-use

devices and systems without degrading the services provided.

Such savings are generally achieved by substituting technically

more advanced equipment to produce the same level of energy

services (e.g., lighting or warmth) with less electricity.1 Energy

efficiency programs are sometimes referred to as energy conservation programs. However, because to some people the term

1 Eric Hirst and Carol Sabo, Electn”c Utility DSM Programs: Terminology and

Reporting Formats, ORNL/CON-337 (Oak Ridge, TN: Oak Ridge National Laboratory,

October 1991).

I 99
—

100 I Energy Efficiency: Challenges and Opportunities for Electric Utilities

conservation implies an overall reduction in

electricity use and energy services, many industry

analysts prefer to use the more neutral and

inclusive term energy efficiency. Energy conservation measures can be included in efficiency

programs.

Demand-side management (DSM) programs

are organized utility activities intended to affect

the amount and timing of customer electricity use.

In theory, successful DSM programs can reduce

the need to build powerplants by controlling

demand for electricity and thereby creating room

for expansion without providing additional supply resources.

Utility load management programs are closely

related to energy efficiency DSM programs. Load

management programs refer to utility programs

intended to influence customer demand through

economic or technical measures usually with the

objectives of reducing demand during peak periods, and/or encouraging demand during off-peak

periods). 2 In pursuit of the frost goal, load

management programs can include many of the

same technologies and measures used for overall

reductions in electricity use. Load management

programs usually employ a combination of load

management incentives, metering to measure the

time and quantity of customer electricity use, and

load control equipment. Because of the timeshifting aspect of load management programs,

they may be targeted at peak loads and not

necessarily at an overall reduction in electricity

consumption. Load management programs can

also be directed at retaining load or customers,

and expanding customer loads. Box 5-A shows

common utility load management strategies and

their load shape objectives. These same load

shape objectives are used for utility DSM programs.

Electric utilities have used load control measures for more than 50 years, but interest in these

measures increased significantly in the 1970s and

1980s. Over this period, interest in load control

was high among utilities that purchase most of

their power from others (primarily municipal

utilities and rural cooperatives) because load

control offered an additional means to reduce

wholesale power costs.3

Utilities can have many goals for DSM and

load management programs. Maximizing energy

savings is one. Others, and perhaps more important to different utilities, are maximizing customer satisfaction, minimizing lost revenues (utility revenues lost when consumers reduce electricity use), mininizing free riders, or minimizing the

cost per kilowatt (kW) or kilowatt-hour (kWh)

saved.

The development of utility energy efficiency

programs coincides with the trend toward adoption of integrated resource planning (IRP) processes by electric utilities. IRP involves a comprehensive and open utility planning process that

includes greater consideration of potential demandside measures on a par with generation and other

supply-side additions in order to meet projected

loads. The prospect of greater reliance on demandside measures to delay the need for new powerplant construction requires that potential energy

savings be estimated with greater certainty and

that actual savings be validated. Adoption of IRP

has created new challenges for electric utilities

planners and their regulators in incorporating

rapidly expanding DSM programs into the resource mix.

INFLUENCING CUSTOMER BEHAVIOR

Electric utilities, with the approval and encouragement of State regulatory bodies, have adopted

a variety of mechanisms to influence customer

electricity use: load controls, differential or incentive rates, rebates, loans, grants, sharedsavings agreements, energy audits, technical as2 U.S. Congress, Ofilce of ‘Ikclmology Assessment New Elecm”c Power Technologies: Problems and Prospects for the 1990s, OTA-E-246

(Washingto@ DC: U.S. Government Printing Office, July 1985), p. 142.

3 Ibid., p. 148.
Chapter 5-Utility Energy Efficiency Programs and Experience I 101

Box 5-A-Load Shape Objectives

PEAK CLIPPING, or the reduction of the system peak loads, embodies one of the classic

forms of bad management. Peak dipping is generally consider ‘ ed as the reduction of peak

bad by using direct bad control. Direct Ioad control is most commonly practiced by direct

utility control of customers’ appliances. While many utilities consider this as a means to

reduce peaking capacity or capacity purchases and consider control only during the most

probable days of system peak, direct load control can be used to reduce operating cost

and dependence on critical fuels by economic dispatch.

VALLEY FILLING is the second classic form of bad management. Valley filling

encompasses building off-peak loads. This may be particularly desirable where the

brig-run incremental cost is less than the average price of electricity. Adding properly

priced off-peak bad under those circumstances decreases the average price, Valley filling

can be accomplished in several ways, one of the most popular of which is new thermal

energy storage (water heating and/or space heating) that displaces loads served by fossil

fuels.

LOAD SHIFTING is the last classic form of load management. This involves shifting load

from on-peak to off-peak periods. Popular applications include use of storage water

heating, storage space heating, coolness storage, and customer load shifts. In this case,

the bad shift from storage devices involves displacing what would have been

conventional appliances served by electricity.

STRATEGIC CONSERVATION is the load shape change that results from utilitystimulated programs directed at end-use consumption. Not normally considered load

management, the change reflects a modification of the bad shape involving a reduction

in sales as well as a change in the pattern of use. In employing energy conservation, the

utility planner must consider what conservation actions would occur naturally and then

evaluate the cost effectiveness of possible intended utility programs to accelerate or

stimulate those actions. Examples include weatherization and appliance efficiency

improvement.

STRATEGIC LOAD GROWTH is the bad shape change that refers to a general increase

in sales beyond the valley filling described previously. Load growth may involve increased

market share of loads that are, or can be, served by competing fuels, as well as area

development. in the future, load growth may include electrification. Electrification is the

term currently being employed to describe the new emerging electric technologies

surrounding electric vehicles, industrial process heating, and automation. These have a

potential for increasing the electric energy intensity of the U.S. industrial sector. This rise

m intensity maybe motivated by reduction in the use of fossil fuels and raw materials

resulting in improved overall productivity.

FLEXIBLE LOAD SHAPE is a concept related to reliability, a planning constraint. Once

the anticipated load shape, including demand-side activities, is forecast over the

corporate planning horizon, the power supply planner studies the final optimum

supply-side options. Among the many criteria used is reliability, Load shape can be

flexible-if customers are presented with options as to the variations in quality of service

that they are willing to allow in exchange for various incentives. The programs involved

can be variations of interruptible or curtailable bad; concepts of pooled, integrated energy

management systems; or individual customer load control devices offering service

constraints.

PEAK

CLIPPING

A

$

VALLEY

LOAD

““7%

SHIFTING

STRATEGIC

-n

CONSERVATION

STRATEGIC

LOAD

GROWTH

A

FLEXIBLE

LOAD

n

● * ● * ● SHAPE ● ● ● ● “* ● ** ● * ●

● ● ● * ● ● ● ● . ● * ● ● ● ● *. ,ba. ● .** ● *** . . . ● . “.

● ● , .-** ● - . ● ● ● . . . . .*

SOURCE: U.S. Congress, Office of Technology Assessment, 1993, adapted from Battalle-Columbus Division and Synergic Resources

Corp., Demand-Side Management, Volume 3:Technology Alternatives and Market Impkmmntatkm Methods, EPRI EAVEM-3597 (Palo Alto,

CA: Electric Power Research Institute, 1984 ).
102 I Energy Efficiency: Challenges and Opportunities for Electric Utilities

sistance, direct equipment installation and replacement, comprehensive energy management

programs, and so forth. Many of these programs

are of recent vintage and limited in scope, but

overall the initial savings have been promising

even though not as high as expected. Certain

issues have recurred in the design, implementation, and evaluation of these programs, including:

cost-effectiveness determinations, choice of effectiveness tests, free riders, measurement of

savings, persistence of savings, customer participation rates, utility cost recovery, and financial

incentives.

All utility DSM programs fit into one or both

of the following programs: 1) those affecting the

way energy-using equipment is operated, and 2)

those that focus on the installation of efficient

technologies. Utilities typically operate separate

programs for commercial, residential, and industrial customers.

Load control measures differ based on the

degree of control and input exercised by the utility

and the customer. They range from programs in

which the utility asks customers to reduce load

and the customer individually decides which

appliances to turn off, to direct load control

systems that are highly automated and have little

customer input.

Direct control systems are by far the most

common form of load control. They typically

consist of a communications system that links the

customer’s equipment with the utility and a

decision logic system (i.e., a computer program)

that dispatches commands to the customer equipment in response to information on utility and/or

customer loads. In a residential load management

program, equipment might be installed to allow

the utility to cycle participating home airconditioners and water heaters on and off briefly

during times of peak load with little or no

disruption to the customer. With widespread

participation, this represents a critical strategic

tool for utilities to shave peak load. Typically the

customer enters into an agreement with the utility

that gives them either lower rates and/or a small

monthly payment for participation in the program. For example, Potomac Electric Power

Company (PEPCO) offers a credit of $110 to

households that join its “Kilowatchers Plus

Club” and allow the company to shutoff their air

conditioning for short periods of time to offset

summer peak loads if needed. Some 100,000

members of PEPCO’S “Kilowatchers Club”

receive a $45 credit for allowing the utility to

cycle their compressors off and on for brief

periods. PEPCO estimates that by 1995, cycling

will pare 170 megawatts from its summer loads.4

Utilities and regulators have experimented

with various incentive rates in an attempt to

encourage greater efficiency in electricity use.

They have instituted variations in rates by charging more for peak load and higher volume usage

to reflect the increased costs of providing such

service. There has been a great deal of activity

involving time of use rates for large industrial and

commercial customers, but only limited experience with time of use rates for residential

customers. Participation in time of use rates

generally requires installation of meters that

allow measurement of both the quantity and time

of customer electricity use.

Information programs are intended to alert

customers about potential electricity savings measures. Examples include informational advertising

campaigns, energy audits, and bill enclosures.

According to an analysis of utility DSM programs

prepared by the American Council for an EnergyEfficient Economy (ACEEE) for New York State,

information-only programs that provide customers with general information about energy efficiency opportunities and/or combine information

with energy audits have low participation rates

d “Utilities Field Peak Power D~d witi Incentives for Homeowners,” Wall Street Journal, June 6, 1991, p. Al.
Chapter 5-Utility Energy Efficiency Programs and Experience 1103

and low energy savings5 The most effective are

the free energy audits coupled with post-audit

followup. According to ACEEE, the programs

can achieve high participation rates (60 to 90

percent) and energy savings among participating

customers of 6 to 8 percent.6 Revamped information programs are reported to be achieving greater

levels of participation.

Rebate programs provide money to customers, contractors, homebuilders, vendors, or others

who make equipment choices to help defray some

or all of the cost of DSM measures. Rebate

programs are the most common utility program

offered. The form of rebate mechanism can be

cash, discount coupons, or bill credits. ACEEE

found that the most successful rebate programs in

their survey reached about 10 percent of eligible

customers (and about 25 percent of the larger

customers with peak demand of 100 to 500 kW)

over a period of 3 to 7 years. The most successful

programs cut electricity use by 5 percent at utility

costs of $0.01/kWh saved. The most effective

targets have been lighting and heating, ventilation, and air conditioning (HVAC) equipment

improvements. Rebate programs have not historically been very effective at promoting system

improvements-those involving the interaction

of many pieces of equipment. Generally, participation levels are moderate, as are energy savings.

They effectively cut utility peak demand and

electricity sales by about 1 percent/year in successful cases surveyed in the ACEEE study.

Some analyses indicate that participation drops

off after several years of aggressive program

promotion; however, more analysis is needed of

this possible pattern according to ACEEE’S

study.

The “Super Good Cents” Program, sponsored by the

Bonneville Power Administration and northwestern

utilities, provides certification for new residential

buildings and manufactured homes that meet stringent

energy efficiency standards. The program qualifies the

buyers for rebates from participating utilities.

Loan programs provide cash to finance energysavings investments and are attractive for customers who lack cash. The program may allow the

customer to repay energy efficiency investments

on the monthly utility bill, often at a low interest

rate. They are offered by only a few utilities.

Studies of consumer loan programs found that

customers offered a choice of rebates or lowinterest loans have generally opted for the rebates. 7

Increasingly, utility programs bundle various

DSM approaches into a single package. For

example, the City of Fort Collins Light and Power

offers residents of Fort Collins the Energy Score

Home Energy Rating Service that combines

information, audit, building efficiency standards,

rebates, loans, and eligibility for energy efficient

5 aticm COwCiI for an mern Mlcient ~onomy, 12ssons Learned: A Review of Utility Experience with Conservation and bd

Management Programs for Commercial and Industrial Customers Final Repo@ Energy Authority Report 90-8 (New York, NY: New York

State Energy Research and Development A&mm“ “stratio% April 1990). Hereinafter refcmed to as Lessons Learned. This report provides an

analysis of utility industrial and commercial conservation and load management programs, including energy-savings, participation rates, costs,

etc. The analysis covered some 200 utility commercial and industrial programs from 58 utilities and was based on comprehensive sumeys and

interview conducted circa 1987.

6 Ibid.

~ ~~som ~arned, supra note 5* P“ 5-5”
104 I Energy Efficiency: Challenges and Opportunities for Electric Utilities

mortages. Homeowners, builders, sellers, or purchasers of new or existing homes can contact an

independent utility-certified rater to inspect and

report on a home. The rater provides a comprehensive home energy efficiency analysis covering

the orientation of the lot, insulation, windows,

doors, air leakage, heating and hot water systems,

and other factors influencing energy use. The

house is given a rating from O to 100, with 100

being the most efficient. The cost of the rating is

$100 to $175 and the city utility picks up $50 of

the cost. Homes with higher energy efficiency

ratings (G-70 for gas-heated homes, and G-65 for

electric heated homes) may be eligible for a 2

percent ratio increase on an energy efficient

mortgage from participating lenders, increasing

the purchaser’s buying power. The rating also

identifies opportunities for efficiency improvements and may qualify the homeowner for the

utility’s zero-interest “Zilch” home improvement loan to finance the upgrades.

Performance contracting programs offer payments based on the amount of energy saved as a

result of efficiency improvements. They generally rely on energy service companies (ESCOS) or

other vendors to recommend, install, and finance

efficiency measures. Utilities can also contract

directly with large customers. According to the

ACEEE study, the most successful of these

programs have included high incentives, but have

achieved significant savings. On the whole these

programs have been more costly than some other

types of programs. Experience has indicated that

ESCOS have tended to focus on the largest

customers and the most lucrative measures (especially lighting and cogeneration) to achieve

savings. ESCO contracts provide one mechanism

for reaching some of the most cost-effective,

energy-efficient opportunities with significant

economies of scale. Other approaches can target

and achieve these same savings opportunities.

Initial experience with performance contracting

and ESCOS has been mixed. Many utilities are

substantially revising their performance contracting programs or are complementing them with

other types of programs. Performance contracting

with ESCOs or with large customers still remains

an attractive alternative for financing and installing energy-saving technologies.

Comprehensive programs combine regular

personal contacts with customers, comprehensive

site-specific technical assistance, and financial

incentives that pay the majority of the installation

costs of efficiency measures. According to the

ACEEE study, these programs were highly successful, but also tended to be among the most

expensive at a typical cost of $0.03/kwh saved.

There is little experience with large-scale programs over time. The analysis suggests that this

type of program maybe particularly appropriate

for serving small customers and for new construction (where there is a one-time opportunity to

capture substantial savings at only the marginal

cost of efficient equipment over standard equipment).

r

<

, / --

I r

Lighting Design Lab in Seattle. This resource center is

supported by a consortium of Federal and State

agencies, electric utilities, and conservation groups. It

aids commercial designers, architects, engineers,

contractors, facilities managers, and others in the

design and selection of efficient lighting applications.

Request for proposal (RFP) and bidding

programs have been in operation for several

years. Under these programs, the utility issues a

request for proposals to provide demand-side
Chapter 5-Utility Energy Efficiency Programs and Experience 1105

resources and receives and evaluates proposals

from ESCOS and customers. After evaluating the

bids, the utility negotiates contracts with the

winning bidders for specific energy savings and

load reductions. Based on preliminary results

analyzed for the ACEEE New York study, these

programs offer the promise of significant savings

(up to 1.5 percent of peak demand after 2 years).

The success has been tied to reaching large

customers directly or through ESCOS who participate in the process. The programs generally are

less than utility avoided cost, but a tendency has

been noted for bids to approach utility avoided

costs. Much of the initial experience with DSM

bidding programs was in Maine and New York.

As utility competitive resource procurements

have expanded, so too have the number of bidders

offering demand-side installations. Moreover,

these demand-side bids are proving to have a

higher success rate in winning bids than conventional supply options.8

Fuel switching programs involve incentives

to utility customers to reduce load by switching to

an alternative energy source for all or some of the

service provided by electricity. Examples include

the installation of a gas-powered air conditioning

system in a large commercial office complex or

switching from an electric resistance to a gas

water heater. Fuel switching and electrification

measures generally involve complicated sitespecific tradeoffs, and no generalizations can as

yet be made about their overall performances and

costs.

MEASURING ENERGY SAVINGS AND

EVALUATING EFFECTIVENESS

There has been over a decade of experience

with utility load management and DSM programs

around the country. Substantial dollar and energy

savings have been claimed, but much remains to

be learned.

To be successful from the perspective of

least-cost planning objectives, the program

should achieve maximum long-term, costeffective net energy and demand savings (net of

what would be required in absence of the utility

program). Generally this means a long-term

strategy aimed at serving the most customers

(including all but the very smallest). This is to

assure maximum savings and to minimize equity

issues of cross-subsidization. In addition, the

strategy should promote efficiency/load management measures that customers are unlikely to

install without utility efforts in the short term and

for longer-term measures with long-Lives or that

have a high probability of replacement.

The ACEEE study found that utility DSM

programs as a whole had not yet had a dramatic

impact. The programs surveyed were reaching

less than 5 percent of target customers on a

cumulative basis and were reducing their energy

use by less than 10 percent. As of 1989-90, it was

estimated that utility peak demand had been

reduced by less than 1 percent. They did find a

number of highly successful programs, however.

A few reached 70 percent or more of eligible

customers—with customer energy savings of 10

to 30 percent, and reductions in utility peak

demand of up to 5 percent. Many of the most

successful programs, however, were still in pilotor small-scale programs and had yet to be applied

on a large-scale basis. The good news is that all of

the energy savings reported came at a cost to

utilities of less than $0.04/kWh saved even

including free riders. These reported costs were

less than many utilities’ avoided costs to generate

new power, making it likely that the programs

would prove cost-effective using the utility cost

test.9

Since the ACEEE study was published, utility

DSM programs have continued to grow, and

many utilities are now projecting significant

savings from their efforts. A recent analysis by

8 See discussion of bidding programs in ch. 6.

9 Cost-effectiveness tests are described in ch. 6 of this report.
106 I Energy Efficiency: Challenges and Opportunities for Electric Utilities

Oak Ridge National Laboratory, based on reports

to the Energy Information Administration, found

that existing utility programs are projected to

offset 14 percent of the growth in electricity

demand by the year 2000.10

D Measuring Swings

The savings from a DSM program are estimated by comparing energy demand both before

and after the program is implemented. Evaluating

the success of utility DSM programs is difficult

both on a local and a national basis. Most savings

estimates reflect engineering estimates, and more

sophisticated measured and validated estimates

of savings are rare. Engineering estimates generally rely on simple rules of thumb calculations

using manufacturers data, or engineering simulations. Engineering estimates can be fairly accurate for some simple DSM actions (e.g., domestic

water heater wraps). However, in practice, engineering estimates have been found to overestimate actual electricity savings.11 As experience

with DSM programs increases, and energy savings are subjected to more rigorous impact

evaluation, it should be possible to develop other

techniques, or at least more accurate engineering

rules of thumb, to support reliance on this

technique to estimate potential savings. Until

then, such estimates should be viewed with

caution.

In order to show the effectiveness of efficiency

measures, it must be determined how muc h

electricity use is actually reduced over what it

would be in the absence of the measure. Depending on the goal of the program, monitoring usage

by the time of use (on-peak vs. off-peak) will also

be important to determine impacts on load shape.

There are several means of measuring (collecting data on) electricity use and the impacts of

efficiency improvements: monthly customer bills,

spot metering (either on a short-term before and

after retrofit or permanent basis), whole building

load research monitoring, and end-use load research monitoring. See box 5-B.

Measuring exact savings is not necessary in all

cases and could become prohibitively complex as

the number and extent of DSM programs increase. For simple measures, where there is

substantial experience (more efficient residential

refrigerators, for example), past measurements

and engineering estimates may suffice to calculate savings for the program. For more complex

and site-specific DSM measures (e.g., retrofitting

and relamping a large commercial building),

detailed site-specific measurements of specific

load shapes may be needed to estimate savings.

Comparison of customer billing data is the

most straightforward and least expensive method

for many applications, but is not adequate for new

construction or for large and complex installations. In the former case, bill data will be absent,

thus engineering calculations or comparisons

with similar buildings for which data are available

might be used. In the latter case, normal fluctuations in energy use could mask the effects of

efficiency improvements and so specific end-use

metering that tracks the time and quantity of

electricity may be required.

Once total end-use savings have been determined, the impacts on utility load shape and

supply must be calculated. In general, because of

transmission and distribution losses, the actual

kilowatts saved at the powerplant from customer

efficiency measures are about 8 percent higher

than that saved on site. Kilowatts saved by the

customer may also reduce utility reserve margins,

i.e., customer savings plus the reserve margin

percentage (allowance for powerplant downlo Wc mg Elec~ic utili~ DSM-Program Costs and Effects: 1991-2001, ORNL/CON-364 (OdC Ridge, TN: CM Ridge Natio~

Laboratory, May 1993).

11 S.M. Nadel and KM. Rx@, ‘‘Engineering INimates vs. Impact Evaluation Results: How b They COmp~e and why,’ Energy

Program Evaluation: Uses, Methods, and Results, Rwedings of the 1991 International Energy Program Evaluation Conference,

CONF-91OSO7, August 1991, cited in H.irst and Sabo, supra note 1, pp. 24-33.
Chapter &Utility Energy Efficiency Programs and Experience I 107

Box 5-B-Methods Used to Measure Electricity Consumption

Approach Explanation Advantages Disadvantages

Monthly electricity bills Obtain electrtcity bills for a Measures actual changes in Provides no estimate of deyear before and a year after electricity use, permits ad- mand (kW) reductions unparticipation, adjust annual justment for changews in weather less customers face demand

electricity use for weather and other factors, and re- charges. Analysis of monthly

and other relevant factors, quires little primary data col- billing data can yield ambigand compute the difference lection. uous results. Estimates of

between pre- and post- kWh savings affected by

participation use in kWh/ changes in facility use unreyear. lated to devices installed.

spot metering of Monitor electricity use be- Measures electricitysavings Could yield estimates of savelectricity use fore and after participation (both kWh and kW) for well- ings not realized if measfor short times (e.g., a few defined, short time periods. urernents taken incorrectly

days); also measure other Modest cost. or at atypical times, or if

relevant factors (e.g., oper- building use changes. Diffiating hours for equipment cult to apply to devioes that

and heating degree days) are season-or weatherfor a longer time (e.g., up to dependent.

a year).

whole-building load- Monitor electrlcity use of facil- Measures actual electricity Expensive and time conresearch monitoring ity to record kW demand use and demand (kWh and suming. Large amounts of

before and after participation. kW), Can be combined with data produced. Results may

other data to adjust for be affected by changes in

changes in weather and facili

factors. ment installed.

End-use, load-research Monitor specific circuits af- Measures actual electricity Most expensive and time

monitoring fected by new systems to use and demand (kWh and consuming method. Large

record kW demand before kW) for specific end uses amounts of data require soand after participation. affected by program. Can be sophisticated computer programs

combined with other data to and analysts to interpret.

adjust for changes in weather Results may be affected by

and other factors. changes in facility use unrelated to equipment installed.

SOURCE: Eric Hlrst and Carol Sabo, Electric Utility DSM Programs: Terminology and Reporting Formats,ORNL/CON-7(Oak Ridge,

TN: Oak Ridge National laboratory, October 1991), p. 36.

time). Improved measurement and monitoring of Tracking the persistence of energy savings

end-use efficiency savings and documentation of from efficiency measures is also important. Some

actual reductions in utility-generating demand measures may prove to be fairly reliable and

over time may contribute to less uncertainty about long-lived (for example building insulation that

demand-side measures in utility resource plan- the customer is unlikely to remove). But other

ning. measures may be affected by declines in the
108 I Energy Efficiency: Challenges and Opportunities for Electric Utilities

technical performance of equipment, the lifetime

of the measure, user replacement of measures

when they wear out, changes in operating conditions induced by the DSM program, or marketrelated changes in electricity use. 12 The energysavings benefits of a compact fluorescent light

may disappear, if when it is worn out, the user

replaces it with a standard incandescent lamp.

Similarly, an occupant might be induced to raise

thermostat settings to take advantage of improved

building insulation or an efficient space heating

system, thus, at least partially offsetting the

efficiency gain. This phenomenon of losses in

efficiency gains because of customer behavior is

often referred to as takeback.

M Participation Rates

The success of DSM programs often hinges on

the number of customers and/or trade allies

(businesses that sell or influence choices of

energy using equipment such as architects, designers, builders, appliance dealers) that participate in the program. Participation rates are the

ratio of the number of participants to the number

of eligible customers. In many cases, determination of the pool of potential participants is fairly

straightforward and based on information a utility

readily has at hand (e.g., commercial office

buildings, all residential customers). However,

for more specialized programs, additional market

research may be needed to identify potential

participants, for example, homes with electric

resistance heat, or industrial motor applications.

As a practical matter, most estimates of DSM

program participation rates generally include free

riders. Free riders are customers who participate

in a program, but would have undertaken the same

conservation actions even if the program were not

offered. 13 (Some discussions also brand as free

riders ratepayers who benefit from conservation

programs, but do not participate; however in this

report we include only program participants.) The

presence of free riders tends to overstate program

results. Some economists maintain that free riders

should not be eligible for program incentives and

will drive up program costs and ratepayer impacts

to an unacceptable degree.14

The presence of free riders, setting aside the

issue of whether they should be eligible for

financial incentives, complicates evaluations of

the effectiveness of utility DSM programs. In

determining g whether the program has actually

had an impact on customer energy use, the focus

must be on net savings-calculated by determining the share of free ridership and excluding the

associated savings.

But the presence of a high portion of free riders

in a program is not necessarily an indication that

the program is not effective for several reasons.

First, one should expect a high degree of free

riders early in the program and then as the

program becomes more successful and participation increases, the free rider share should approach a floor defined by the penetration of the

efficiency measure in the market place or the

market share of efficient devices versus standard

devices in absence of the program.l5

Second, many estimates of free ridership are

based on self-identification by those who say they

would have adopted the measure anyway, thus

tending to overestimate actual free ridership. The

bias problems with surveys are well documented

and show a tendency of respondents to give the

perceived “right” answer to the interviewer

12 Mt and Sabo, supra note 1, p. 34.

13 Ibid.

M Convemely, anoth~ complication is the gener~ exclusion from participation rates of free drivers. Free drivers are customers who tie

DSM prograrn-wcommended actions, but do not participate directly in the program (i.e., claim rebates). The absence of fkee drivers will result

in understating the program’s effectiveness.

IS ~$som~arned, ~pmnote 5, pp. t3tS, 167.170, (various utility programs estimated he riders at 5 to lo percent fOrrepl=aent Of working

motors and 5 to 35 percent for new motors).
Chapter 5-Utility Energy Efficiency Programs and Experience I 109

rather than the ‘‘true’ answer. Additionally,

while a participant might be favorably disposed to

installation of the efficiency measure in the

absence of the program, it is difficult to estimate

with any accuracy how many of the self-identified

free riders would actually have installed the

measure without the program or the extent to

which the existence of the program accelerated

their actions.

I Costs of DSM Programs

Monitoring and estimating the costs to utilities

and customers is necessary to determine whether

the costs of efficiency programs are outweighed

by their benefits, and to provide for adequate cost

recovery in regulatory proceedings.

For newly authorized programs, very little

actual cost data may be available, but as experience increases, costs should be calculated with

greater accuracy. The ACEEE review of 58

existing utility DSM programs found that reported cost figures per kilowatt and kilowatt-hour

for efficiency measures were only approximate,

and often ignored customer costs, and sometimes

relying on rough estimates of indirect utility

costs. The lack of accurate cost data is troubling

when one considers that over $2 billion was

invested in utility energy efficiency programs in

1991 and that by the end of the decade some

experts estimate that DSM could be a $30

billion/year industry.

16 Moreover, more reliable

and detailed cost data are needed for DSM

resources to be more fully integrated into utility

resource planning processes.

9 Determining Cost-Effectiveness

There is a wide variation in how different

utilities and State regulators calculate the costeffectiveness and costs of DSM programs. The

cost-effectiveness of DSM measures is commonly estimated from either the utility, customer,

or the societal perspective. For more on costeffectiveness tests, see chapter 6 of this report.

The utility perspective considers the utility’s

costs and benefits for program, including rebate

and other costs, avoided energy and capacity

benefits. It excludes customer costs and the value

of revenues lost by the utility because of energy

savings.

The total resource cost perspective (adopted in

New York State) includes money paid by program participants for materials, installation, and

maintenance (including credits for reducing customer costs, such as reduced maintenance costs in

addition to factors considered from the utility

perspective). In practice, the total resource cost

test suffers from the fact that extensive data on

customer costs are not generally collected by

utilities.

There are several alternative units used in

estimating cost-effectiveness. Cost per kilowatthour saved simply uses program expenses divided

by kilowatt-hours saved). Other measures calculate levelized cost per kWh saved (discounting the

cost over time) to provide a long-term cost

estimate. More rigorous approaches involve calculation of total levelized costs of the program

and comparison with avoided total costs of the

energy saved (avoided energy costs plus levelized

value of annual capacity cost divided by 8,760

hours/year).

1 Evaluation of DSM Programs

Evaluation is the systematic measurement of

the operations and performance of DSM programs and should rely to the extent possible on

objective measurements and well-defined and

executed research methods. Program and impact

evaluations of DSM and load management programs are critical components of both utility and

government assessments of the cost-effectiveness

and success of efficiency measures. Program

evaluation is a rapidly evolving specialty that

16 fic Hirst and Jolm Reed @is.), Handbook of Eva/uution of Utiliry DSM Programs, ORNL/CON-336 (Oak Mdge, ~: O* ~dge

National Laboratory, December 1991).
110 I Energy Efficiency: Challenges and Opportunities for Electric Utilities

relies on social-science research methods and

technical data to provide valid and reliable

documentation and quantification of program

results and costs and to analyze their usefulness.

Good impact evaluation efforts are not cheap or

easy to perform, and yet are an indispensable

element of any expansion of efficiency programs.

Adequate funding of evaluation and monitoring

can amount to 10 percent of the costs of utility

programs. As the costs, extent, and expectations

of utility energy efficiency programs grow, the

resources devoted to monitoring and evaluation

will have to expand and the evaluation techniques

must also become more technically sophisticated

and reliable.

MIXED RESULTS FROM UTILITY

ENERGY EFFICIENCY PROGRAMS

While there are clearly successful utility energy efficiency programs with demonstrable energy savings, experience so far indicates that the

energy savings achieved fall far short of the full

technical potential that is cost-effective to end

users.

The ACEEE review of 58 utility programs

found evidence for this conclusion in low participation rates and in actual savings well below

cost-effective technical potential.17 programs with

the highest participation rates reached only 10 to

70 percent of eligible customers. Among participating customers, the programs with the highest

energy savings were found to yield only 20 to 60

percent of the cost-effective technical potential.

Cost-effective technical potential was defined as

measures having equipment and installation costs

less than $0.05 kWh saved, i.e., less than the retail

commercial and industrial electricity rates and/or

utilities’ long-run avoided costs. The gap between

technical potential and actual savings was large

for the best programs and larger still for typical

programs.

Low participation and savings rates are typical

of the startup stage of most programs, and many

programs were still limited in scale and had only

a few years experience. However, other utility

programs have been operating for some time and

it is reasonable to expect better performance.

No utility operates state-of-the-art programs in

all areas. The largest commercial and industrial

efficiency programs were found to have reduced

kilowatt-hour sales by only 2 to 14 percent-far

less than the estimated 35 percent cost-effective

savings potential (from the consumer perspective) found in the ACEEE study of New York

State potential.18 These performance shortfalls

raise questions about the viability of ambitious

State and utility efficiency goals.

Some economic analysts are challenging utilities and regulators cost-benefit equations and

questioning the claimed successes of DSM programs. One controversial analysis performed for

the U.S. Environmental Protection Agency discarded the more commonly used cost-benefit tests

and applied an alternative cost-benefit measure to

DSM program savings calculated by two utilities.

The report examined a total of 16 separate DSM

programs operated by the two utilities and concluded that none of the programs passed its

‘‘conventional’ economic cost-benefit test if

environmental benefits were excluded from the

calculations .19

The New York State Energy Plan sets a goal for

utility conservation and load management programs to reduce electricity use and demand by 15

17 ~ssom krned, SUpra note 5, pp. 181-196.

IS ~e~cm CoUciI for an Eneru-wlcient Economy, and the New York State Energy OfiIce, The Achievable Conserwm”on PotentiaJ in

New York State from Utility Demand-Side Management Programs, Energy Authority Report 9018 (Albany, NY: New York State Energy

Research and Development &lrmm“ “stratioq November 1990).

19 wkrt L. Nichols, Esti~ting the Net Benefits ofDemand-Side Management Programs Based on &“??U”ttdI@~tion, (Cambridge, MA:

National Economic Research Associates, Inc., Jan. 25, 1993), p, 34, cited in Kemedy Maize and John McCaughey, “DSM at Mid-Passage:

A Discussion of the State of the Art and Science of Demand-Side Management in Electric Utilities,’ The Quad Report, Special Repo~ Spring

1993.
Chapter &Utility Energy Efficiency Programs and Experience I 111

percent by 2008. To do this, ACEEE estimates

that DSM programs will have to reach 50 to 70

percent of customers and achieve savings among

participants of 20 to 30 percent.

Nevertheless, many utilities have now enthusiastically embraced DSM programs. The New

England Electric System (NEES) has been an

early leader in utility DSM programs, spurred in

part by financial incentives adopted by State

regulators in Massachusetts, New Hampshire and

Rhode Island. For 1990, NEES reported that

potential system profits from DSM programs

were $10 million. Estimated savings were a total

of 194,300 megawatt-hours saved and 116.5

megawatts of demand reduced.20

NEES’S third resource plan adopted in 1991

relies on DSM programs to displace a total of 850

megawatts by 2000, constituting more than 12

percent of the utility’s capacity resources. NEES

resource plan will also achieve a 45 percent

reduction in net air emissions by 2000 through its

resource strategies including DSM, converting/

repowering an existing plant to natural gas,

accelerating environmental compliance, power

purchases from nonutility generators and Canadian hydroelectric facilities, and various initiatives to offset greenhouse gas emissions.21

Pacific Gas & Electric Company, the Nation’s

largest utility, also has long experience in DSM

programs. PG&E plans to spend about $2 billion

on customer energy efficiency in the 1990s and

cut their energy growth by half and peak demand

by 75 percent (2,500 megawatts). PG&E projects

that these savings can be achieved at a cost of

from $0.03 to $0.04/kilowatt-hour-less than half

the cost of building new fossil generation.22

H Elements of Successful Programs

Even though no utility was found to perform at

state-of-the-art levels in all of its efficiency

programs, a number had demonstrated notable

success.

23 They shared certain program elements

that are believed to contribute to above-average

participation and savings:

Marketing strategies that use multiple approaches (direct mail, media, etc.) combined

with personal contacts with the target audience. Particularly successful are those that

develop regular, person-to-person contacts

and followup contacts after installation to

assure that the measures are working properly and to promote additional measures.

Targeting of program approaches and marketing strategies to different audiences (customers, architects, equipment dealers, engineers, developers) and for different types of

investment decisions (new construction, remodeling, replacement, retrofitting). Including target audiences in program design is

especially successful in producing a program

that meets consumer needs.

Technical assistance to help targeted customers assess efficiency opportunities and

identify and implement DSM measures. Assistance might include energy audits, advice

on equipment, contractors, computer modeling of possible savings alternatives, information on new state-of-the-art technologies.

Detailed technical assistance is generally

only cost-effective when coupled with incentive programs that induce high levels of

customer participation and savings.

Simple program procedures and materials

that make it easier for the customer to

m As=iation of Dem~d-Side Mmgement Professionals, ‘NEES Credits Regulatory hlCf211tiV12S III ‘Overwhelming’ 1990 DSM SUcc~s,

Strategies, vol. 2, No. 2, Spring 1991.

21 “New Engl~d utili~ Outlines Plans to Cut Greenhouse Emissions by 4570, ” Energy Conservation Digest, Dec. 23, 1991, p.1.

u ~st and Sabo, supra note 1, p. 1.

23 Revlm~ of utili~ efficiency ad ~mewation pro~~ ~dicate tit some Utiities comistenfly do a kfier job tkII others h operating

these programs. Among the most successful cited in the 1990 ACEEE study were: the City of Palo Alto, CA; Central Maine POWW, New

England Electric System; Pacific Gas and Electric; Southern California Edison; and Wisconsin Electric. See Lessons Learned, supra note 5.
112 I Energy Efficiency: Challenges and Opportunities for Electric Utilities

g,.-

fn

.a—

*..

An energy audit team makes a site visit to a Pacific Northwest lumber mill to study operations to help development

of an industrial energy efficiency program.

understand program potential and to participate. Examples are one-step application

procedures, assistance in filling out forms,

packaged rebate programs.

Financial incentives that attract custome r

attention and reduce first costs of imple -

mentin,q DSM measures. Analyses of the

effects of varying incentive rates are scanty.

But initial results indicate that offering free

measures produces the highest participation

rate. High incentives (50 percent or more of

a measure cost) generally appear to produce higher participation rates than moderate

incentives (one-third of a measure’s cost).

Moderate incentives may not produce higher

participation rates than low incentives, however.

Multiple measures available for customers

to choose from that increase the likelihood

that customers will find a measure or - pro -

gram that is appropriate for their need s

and/or to implement more than one measure

and gain more savings. There are a plethora

of programs limited solely to lamps and air

conditioners, Including additional HVAC,

efficient lighting, and motor measures and

allowing customers to propose their own

qualifying measures tend to boost participation rates and savings,

Programs promoting new technologies not

yet widely adopted in the marketplace, These

programs for high-efficiency technologies

tend to reduce free riders and achieve higher

savings than available through first generation technologies. A high percentage of free

riders (about 30 percent) have been found

with <time technologies, especially when

rebates are provided for products that are

already being purchased by many customers,

such as, reduced wattage lamps and moder-
Chapter 5-Utility Energy Efficiency Programs and Experience [ 113

ate efficiency air conditioners. Because customers may be unfamiliar with and wary of

new, advanced energy-saving technologies,

programs that focus on them may require

substantial marketing efforts to boost typical

low initial participation rates.

Additional factors that contributed to the

success of utility DSM programs were: top

management commitment to energy efficiency measures, staff and organizational

commitment, skills, support, creativity, and

flexibility. Personal contact marketing and

followup by utility personnel are also key to

successful programs. Lastly, the most successful utility programs have been those

where utilities are offered incentives for

successful programs.

I Problem Areas

The ACEEE study identified several problem

areas that must be addressed if DSM programs are

to have a significant effect.

Most utility commercial and industrial DSM

programs have had only a limited focus. The

programs must expand beyond lighting and small

HVAC improvements to include advanced lighting and motor technologies and comprehensive

industrial system improvements. There is no

one-size-fits-all comprehensive demand-side program. Regulators and utilities must develop

packages of programs tailored for the utility, load,

and customer characteristics if the initiative is to

be a success. Many utilities in an effort to

structure their services to enhance customer

values are examining ways to provide more

comprehensive energy efficiency services,

Participation rates have been low. Marketing

efforts must be expanded to reach and persuade

more customers to participate.

More data and research are needed to support

DSM program development and evaluation. Program design and evaluation is hampered by the

lack of credible data on energy use and target

populations (building characteristics, motors and

other equipment), and by the lack of accessible

and useful documentation and evaluation of

existing programs. Information on actual percentage reductions in energy use is rarely collected

and yet would be of invaluable assistance to

utilities, regulators, and consumers.

Additionally, because energy and load management efforts have been limited in scope and

long-term experience is lacking, mistakes will be

made. But utilities may fear to publicize mistakes

and shortcomings for fear that regulators will

punish them. There is, however, much to be

learned from mistakes. Therefore unsuccessful

program experiences should be investigated and

the results publicized so that others might avoid

these pitfalls.

1 Need for Complementary

State and Federal Efforts

Even the best DSM programs cannot achieve

all the cost-effective savings. Some customers

won’t participate, no matter what incentives

utilities offer. Many will not adopt all costeffective measures. Because of this tendency,

utility programs need complementary approaches--

e.g., building codes and appliance and equipment

efficiency standards-in order to maximize the

overall adoption of energy-efficient technologies.

The California Energy Commission analysis of

the effectiveness of utility DSM measures in 1983

found the reduced peak demand of 2,718 megawatts was due 45 percent to utility programs, 37

percent to building code requirements, and 16

percent to various appliance efficiency standards.24 Federal and State efficiency initiatives can

also boost the availability of energy efficiency

products in the marketplace. See chapters 6 and 7

for discussion of these efforts.

24 California Energy Coremission, Conservation Report (Sacramento, CA: 1986), p. II-11.
114 I Energy Efficiency: Challenges and Opportunities for Electric Utilities

INCORPORATING ENERGY EFFICIENCY INTO

UTILITY OPERATIONS-THE ROLE OF IRP

IRP has become the main process through

which utilities incorporate DSM measures into

their mid-and long-term resource planning. As a

planning tool, IRP allows a utility to incorporate

a variety of information about load, system

characteristics, demand growth, resource options,

and corporate goals into an analysis that explicitly

evaluates supply- and demand-side resources in a

consistent manner and expressly confronts the

uncertainties inherent in utility planning to produce a flexible resource plan for meeting customer needs at least-cost. IRP also generally

includes opportunities for public involvement

and regulatory review, as well as consideration of

environmental and other social impacts of utility

resource alternatives.

By mid-1993 utilities in at least 41 States were

actively involved in some sort of IRP process. At

least 33 States require IRP or least-cost planning

by their utilities. Under Federal law, utilities that

purchase power from the Bonneville Power

Administration, the Western Area Power Administration, and the Tennessee Valley Authority also

must adopt IRP planning principles as a condition

of their power contracts. Information on State and

Federal IRP initiatives may be found in chapters

6 and 7 of this report.

Resource planning is an integral part of utility

operations and is driven by the three fundamental

goals-serving customer load reliably, minimizing customer costs, and maintaining the financial

stability of the utility (see chapter 3). Today’s IRP

process evolved from traditional utility planning,

which focused narrowly on supply-side resource

additions to meet ever-growing customer demand. With experience, IRP planning processes

are continuously evolving in both theory and

application. Each utility’s IRP process is different—

reflecting its system characteristics and planning

needs, corporate culture and organization, and

regulatory environment. However, every IRP

process follows a general framework in evaluating a broad range of resource options to develop

along-term resource plan typically covering 20 to

30 years, and an action plan covering from two to

five years. New or revised integrated resource

plans are prepared on average every two to five

years. Figure 5-1 shows a simplified IRP process.

The process typically begins with preparation

of long-term load forecasts projecting both energy sales (megawatt-hours) and peak demand

(megawatts) over the planning period. The forecasts are based on historical consumption data,

weather, population, and economic data, and

electric equipment use. The load forecasts must

also take into account expected load growth and

potential changes in energy consumption patterns

due to new technologies, DSM programs, and

other conservation measures. The detailed forecasts are used for financia1 and resource planning

to identify an appropriate mix of generation,

transmission, distribution, power purchase, and

energy efficiency options to meet system needs

under a range of alternative future scenarios.

Using the initial load forecasts, utility planners

then survey potential demand- and supply-side

resource options to identify appropriate measures

for inclusion in the integrated resource planning

portfolio.

For supply-side options, planners will consider

existing generation, transmission and distribution

resources, utility generating plant additions, life

extensions and efficiency upgrades, plant retirements, power purchases, and improvements to

transmission and distribution facilities. During

this initial evaluation, planners will compare the

resources on considerations of: load profiles,

reliability and dispatch capabilities; capital, fuel,

operating, and maintenance costs; environmental

and siting requirements; and capital availability.

The result will be a supply-side resource stack.

Demand-side options will be identified based

on considerations of existing customer use patterns, availability of energy-efficient technologies, demographic data, and evaluations of existing utility DSM programs. Planners will estimate
Chapter 5-Utility Energy Efficiency Programs and Experience I 115

Figure 5-1-Simpl

Supply side

Supply-side

options

F

L!W!S!!!!!L

ified Integrated Resource Planning Framework

Demand side

[ 1

4

Load forecasting

L k

A

v

I Resource

planning ~

nDetailed

analysis

I

A

rlIntegrated

resource plan

Action plan ~

1

v

I

1

Demand-side

options

A

I 4

Implementation

and 1

evaluation ~

SOURCE: Office of Technology Assessment, 1993.

costs, load impacts, and participation rates to

produce an initial stack of demand-side resources.

The IRP process then proceeds to detailed and

iterative evaluation of the potential resource

options to identify the best resource mix taking

into consideration the utility’s strategic goals,

load profile impacts, production and capital costs,

revenue requirements, rate impacts, environmental and other regulatory requirements, and

other planning uncertainties. Planning uncertainties related to demand-side resources include

participation rates, and the costs, effectiveness,

durability, and verification of efficiency measures. For supply resources, uncertainties include

construction time and costs, regulatory approvals,

fuel availability and costs, operating and maintenance costs, and public attitudes towards the

technology and the specific facility proposed.

Overall uncertainties complicating resource planning affecting load growth and costs include

impacts of inflation and interest rates, changing

economic conditions, availability of purchased

power, and changes in environmental and economic regulatory policies. During the process,

resources may be added or removed from the

portfolio based on the initial evaluation.

The typical IRP process includes opportunities

for participation by the public and by regulators.

The extent and type of participation vary. Some

utilities have relied upon a collaborative consultation with interested parties over the entire course

of plan preparation. Others may prepare a draft

plan and then solicit public and regulatory comment before preparing a final plan.

The costs and benefits of alternative resource

options are compared individually and in combination and they are ranked according to the

appropriate cost-effectiveness test and planning

goals. This cost-benefit ranking may be conducted under a number of separate scenarios with

different assumptions about factors affecting

energy demand, financial conditions, or regula-
. . . . .

116 I Energy Efficiency: Challenges and Opportunities for Electric Utilities

tory requirements. In selecting a final integrated

resource stack, planners must balance many

different and sometimes competing goals and

expectations about the future. Because resource

planning involves many qualitative and strategic

judgments, a least-cost plan will not always be the

option that minimizes power production costs.

Considerations of reliability, flexibility, resource

diversity, and business strategy/policy may outweigh options that are the cheapest alternatives at

the time the plan is developed.

The integrated resource plan lays out the

utility’s least-cost long-term strategy. It is coupled with a short- to mid-term action plan that

details the specific actions and resource additions

that the utility will take to carry out the plan

objectives. Based on the plan, the utility, with any

necessary regulatory approvals, will proceed to

plan and acquire the preferred supply- and demandside resources to meet customer loads. During

implementation of the plan, adjustments can be

made to reflect changing conditions using the

plan as a guide. The utility’s experience in

implementing the action plan and evaluating its

results are then used in the next round of the IRP

process.
State

Energy

Efficiency

Initiatives 6

I

n the past decade many States and utilities have experimented with changes to the utility regulatory environment

that have brought energy efficiency to the forefront. Under

the traditional rate-of-return regulation, State regulatory

bodies set the price of electricity to include the costs of providing

service and a fair return on investment. This approach has been

criticized as creating a strong disincentive to energy-saving

investments. To counter this tendency, States have adopted a

variety of incentives to foster energy efficiency. Utilities have a

critical role in implementing these emerging policies as they can

help overcome the barriers that have hampered many energy

efficiency improvements at low cost. However, the incorporation

of demand-side investment into the utility portfolio presents new

challenges for both utilities and regulators.

This chapter provides an overview of State energy efficiency

initiatives relating to resource planning and demand-side management (DSM). It provides a review of various State energy

plans and current integrated resource planning (IRP) programs.

The economic cost tests commonly used to define the costs and

benefits of demand-side resource options are presented. The

chapter concludes with an examination of State regulatory

commission efforts to authorize recovery of DSM program costs

and lost revenues, and create performance incentives that reward

utilities for above-average efficiency programs.

PLANNING FOR FUTURE ELECTRICITY NEEDS

Long-term resource planning that projects future demand and

assesses options for meeting customer needs is an integral part of

utility operations. Utility resource plans have long been submitted to State regulatory commissions, often in conjunction with

rate cases. For decades as electricity demand enjoyed robust

I 117
118 I Energy Efficiency: Challenges

growth, utility resource planning

and Opportunities for Electric Utilities

focused on

supply resources to meet the ever growing electricity demand. Generally, this meant building

new generating capacity and adding transmission

lines and other supply-side technologies. To the

extent that these plans included consideration of

demand-side efficiency, it was usually for contingency measures or in response to pressure from

regulators.

The turbulence in energy markets in the 1970s

prompted changes in how both utilities and

commissions view planning. The resource planning process came to be seen as a tool for

integrating the many factors affecting electricity

demand into the consideration of future resource

additions and as an opportunity for regulators and

others to influence utility choices. Among the

trends precipitating this shift to a more flexible

and open planning perspective were: a slowing in

demand growth, inflation in construction costs,

overbuilding of capacity, troublesome nuclear

programs, cost recovery disallowances, steep rate

hikes, and new environmental requirements. Increasingly, States are requiring one or a combination of the following elements in utility long-term

resource plans:

■ Public hearings to review the plan before

final adoption,

■ Formal regulatory body approval of the plan,

and

■ Regulatory certification of the need for

powerplants linked to the resource plan.1

H State Energy Plans

A number of States prepare comprehensive

State energy plans that go beyond the utility realm

to cover all aspects of energy use in the state. The

utility companies perform only a portion of the

actions necessary to implement a statewide plan.

States vary in the level of detail of prescribed

action in their plans. Utility responsibility to State

plans range from fulfilling stated requirements to

following general guidelines. State plans from

New York, California, and Texas illustrate the

variety of approaches. Table 6-1 shows States

with energy planning requirements.

NEW YORK

New York State’s energy plan sets the framework for State energy decision-making and its

utilities have concrete recommendations to consider. The general objectives are to promote

energy efficiency, stimulate competition among

energy services, and promote long-term growth in

an environmentally prudent manner. Specifically,

the plan’s goal for electric power is a 8 to 10

percent reduction in peak demand by 2000, to be

followed by a 15 percent reduction in 2008.

Recommendations to utilities include:

Energy efficiency programs to capture lost

opportunities for savings in new construction,

Expanded delivery systems for DSM programs,

Use of evaluation results for better design of

DSM programs,

Standard formats for DSM evaluations,

Development of long-run avoided costs estimates appropriate for DSM program evaluation,

Development of strategies to obtain conservation emissions allowances under the Clean

Air Act Amendments of 1990,

Increased research and development on enduse renewable energy technologies, and

Encouragement for an increase in capital

budgets to implement cost-effective powerplant efficiency.2

The New York plan details actions for utilities

to follow if they are to comply with the statewide

plan.

1 Edison Electric Institute, Rate Regulation Department lntegrafedllesource Planning in the States: 1992 Sourcebook (Washingto% DC:

Edison Electric Institute, June 1992), pp. Xxxvi-xxxvii,

z New York State Energy Plan, Volume II: PIMI RWO~ Fe- 1~21 PP. 49-52.
Chapter 6-State Energy Efficiency Initiatives I 119

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330-075 : QL 3 0 - 93 - 5
Table 6-l-State Resource Planning Requirements-(Continued)

Statewide Source of State Public

energy Utility IRP IRP approval of hearing on Plant

State plan? required? requirement IRP plan? IRP plan? certlflcatlon? Notes

North Dakota. . . . . . . . . . .

Ohio. . . . . . . . . . . . . . . . . . .

Oklahoma. . . . . . . . . . . . . .

Oregon. . . . . . . . . . . . . . . .

Pennsylvania. . . . . . . . . . .

Rhode Island. . . . . . . . . . .

South Carolina. . . . . . . . . .

South Dakota. . . . . . . . . . .

Tennessee. . . . . . . . . . . . .

Texas. . . . . . . . . . . . . . . . .

Utah. . . . . . . . . . . . . . . . . . .

Vermont. . . . . . . . . . . . . . .

Virginia. ...,.... . . . . . . .

Washington . . . . . . . . . . . . .

West Virginia. . . . . . . . . . . .

Wisconsin . . . . . . . . . . . . . .

Wyoming . . . . . . . . . . . . . . .

N

Y

Y

Y

Y

Y

N

N

N

Y

Y

Y

N

N

N

Y

N

N

Y

R

Y

Y

R

Y

N

N

Y

Y

Y

Y

Y

N

Y

N

N

Regs

Regs

Regs

Regs

N

Regs

N

N

Both

Regs

Both

Rags

Both

N

Both

N

Y

N—

N

N

—

Y

—

N

—

N

N

Y

—

Y

—

N

N—

N

N

—

N

—

—

N

—

N

N

N—

N

—

Y IRP submittal ordered in one case.

Y

—

N

N—

N

.

—

N

—

Y

Y

Y

—

Y

— IRPconsideredon utility by utility

basis.

IRP imposed in rate cases.

a’

KEY: Statewide plan: Y = State has a statewide energy plan, Y*= plan in development, and N = no plan. IRP requirement: Y = State requires utility to prepare integrated resource plan, R =

IRP rules under review, and N. no requirement. Source of IRP requirement: Lag. . State legislature has authorized/required utility IRP, Both = IRP required by both statute and regulatory

action, Regs = State regulatory commission action. State Approval: Y = State regulators formally approve utility resource plans and N= no approval required. Public Hearing: Y= Public hearing

required in IRP process and N . no public hearing required. Plant Certification . Proposed supply additions require commission approval.

SOURCES: Office of Technology Assessment, 1993, based on data from Edison Electric Institute, Integrated Resource Plarnning in the States; 1992 Sourcebook (Washington, DC: Edison

Electric Institute, 1992); Martin Schweitzer, Eric Hirst, and Lawrence Hill, Demand-Side Management and Plannjng: Findings from a Survey of 24 Electric Utilities, ORNL/CON-31 4 (Oak Ridge,

TN: Oak Ridge National Laboratory, February 1991); National Association of Regulatory Utility Commissioners,Incentives for Demand-Side Management 2d edition (Washington, DC:National

Association of Regulatory utility Commissioners, January 1993); and Office of Technology Assessment staff research.
Chapter 6--State Energy Efficiency Initiatives I 121

CALIFORNIA

California’s eighth State energy plan was

released in 1992 and was approved by the

Governor to be the State’s official energy policy.

The plan is supported by five technical reports

created after extensive public review. The 1992-

93 plan includes 12 policy recommendations and

66 specific actions. The policy recommendations

affecting utilities are:

■ Increased efficiency should supply most of

California’s new energy needs.

■ California should continue to capture energy

savings in new buildings and appliances as

cost-effective technology and design improvements occur.

■ California should promote building retrofit

programs.

■ The State should require the most costeffective and efficient operation of its existing electricity generation, transmission, and

distribution systems.

■ California should continue to pursue diverse

energy supplies and the commercialization

of new technologies to improve energy

security and environmental quality.3

Other policy recommendations were directed

at the State and local governments, the transportation sector, and the marketplace. The plan is

comprehensive, covering many aspects of energy

use. The utility sector’s role is detailed in the

specific actions that accompany the recommendations.

TEXAS

Although Texas has a statewide energy plan, it

does not make specific recommendations for

electric utilities. Instead, the commission reviews

a utility plan’s compatibility with the State plan

before approving a certificate of need for a new

generation facility. Box 6-A highlights several

State plans.

1 Collaborative Planning Efforts

The collaborative process allows traditionally

adversarial groups an opportunity to reach consensus and avoid litigation. Several States have

explored the use of DSM collaborative to

develop suitable DSM policies and programs.

Collaborative groups have brought together parties representing industrial customers, utilities,

environmental organizations, energy conservation groups, consumer advocates, and State government agencies. The number of parties involved

in collaborative efforts has ranged from 2 to 28.

The length of the process has also varied significantly--from 6 months to several years to

ongoing. The cost has proved to be significant.

Through 1991, nine major collaborative efforts

spent an estimated total of $12 million to cover

the technical expenses of nonutility parties and

staff time for both utilities and the nonutility

parties. Utilities usually provide the funds for

nonutility parties to hire technical consultants.

“DSM collaborative are resource-intensive but

promise to save time and money in the long-term

and lead to outcomes that are qualitatively

superior to the expected results of litigation. ’

Frequently, States turned to collaborative

after litigation on DSM or other issues had

occurred. Nearly all the collaborative took place

in States where public utility commissions had

aggressively promoted DSM prior to the collaborative. Common components of collaborative

have been:

■ A focus on designing DSM programs and

resolving related policy issues,

■ A proactive approach to planning to avoid

litigation,

3 California Energy Commission The 1992-1993 California Energy Plan, P10&91-001 (Sacramento, CA: California Energy Commission+

1992).

4 Jonathan Raab and Martin Schweitzer, Public Involvement in Integrated Resource Planning: A Study of DSM Collaborative,

ORNLJCON-344 (Oak Ridge, TN: Oak Ridge National Laborato~, February 1992), p. vi.
122 I Energy Efficiency: Challenges and Opportunities for Electric Utilities

Box 6-A--State Energy Plan Highlights

New York

The New York State energy plan calls for a 2.5 percent annual reduction in energy consumed per dollar of

gross State product. To reach this goal, the State has focused on energy efficiency. Actions include requiring

investor-owned utilities to obtain 300 megawatts of renewable resources by 1998 so that renewable are part of

long-term resource contribution. Utilities have also been requested to meet new energy needs through

demand-side management and competitive bidding.

California

The California energy plan covers all sources of energy, from transportation to electricity generation. Using

a series of recommendations supported by action steps, the State’s comprehensive energy plan reflects three

policy goals:

w Using energy efficiently;

● Using energy diversity and competition as key elements in evaluating new energy supply options, technologies,

and fuel sources; and

● Using market forces in balancing economic health and environmental quality.

Actions for utilities include modernization or decommissioning of inefficient powerplants when economically justifiable,

demonstration and promotion of cost-effective, high-efficiency gas turbines fitted with pollution controls, installation of

technologies to maximize the load-carrying capacity of the system, and coordinating transmission systems to optimize

use.

SOURCES: Office of Technology Assesment, 1903, from New York State Energy Plan, vol. 1, February 1992, a nd Callforn ia Energy

Commlsslon, The 1992-1993 California Energy Plan, P106-91-001, 1992.

■ Formalizing consensus as a defined goal, and able. An example of the collaborative process is

■ Utility funding of technical expertise for presented in box 6-B.

other parties.5

One study of the major collaborative efforts IRP REQUIREMENTS

through 1991 concluded that the process was

successful along a broad array of criteria. The

study also points out that there some issues that

the process is more adept at handling, such as

technical issues surrounding program design and

application of DSM policies. At the other end,

issues that collaborative have shied away from

include fuel switching and consideration of externalities.

6

Collaboratives, though resource intensive, have

proven to be a viable alternative to litigation. The

fact that only two rulings on collaborative plans

have been appealed to courts is an indicator that

the diverse parties have found the process acceptIRP is a planning process used by utilities and

regulators to assess alternative supply and demand resources to assist them with optimal

resource selection. As currently defined, IRP is a

refinement of longstanding utility and regulatory

practices and requirements. By early 1993 at least

33 States had passed legislation or initiated

regulations to promote IRP. Figure 6-1 shows the

progress of IRP implementation across the States.

State IRP requirements vary but the essential

elements include:

■ Consideration of both supply- and demandside resources in a consistent manner that

minimizes long-run costs,

5 Ibid., pp. 17-27.

6 Ibid., pp. 27-31.
Chapter 6-State Energy Efficiency Initiatives I 123

Box 6-B-The Massachusetts Collaborative

The Department of Public Utilities (DPU) in Massachusetts initiated one of the first collaborative planning

efforts in August 1966 after extensive intervention in demand-side management (DSM) proceedings. The

collaborative participants included seven utilities and four nonutility parties. Before the collaborative’s formation,

the utilities involved had been criticized by interveners and penalized by the DPU for poor DSM program

performance.

Phase I gave the parties 6 months to come to an agreement on the design of DSM programs adaptable to

each utility. The DPU, while not participating in the collaborative, did rule on issues that threatened its progress.

By ruling on cost-effectiveness tests and cost recovery issues, the DPU allowed the collaborative to proceed with

its other objectives within the set timeframe.1 The utilities paid dose to $400,000 to hire technical consultants for

the nonutility parties. Paying for outside consultants was considered necessary to avoid a significant disparity in

technical expertise betwen the utilities and the nonutility parties. The nonutility participants formed a coalition that

remained stable during the course of many important issues, Phase I concluded in December 1966 with a

consensus that detailed 25 different generic program designs. The time constraints were a useful tool to ensure

that the collaborative wasn’t stalled by excessive delays. DSM expenditures in Massachusetts increased 4 to 15

percent with the filing of the collaborative agreement.

Phase II was structured differently. Interested utilities voluntarily formed a Phase II collaborative with the

nonutility partidpants on an individual basis. Again, the nonutility parties received $2 million foroutside consultants.

Five different phase II collaboratives were initiated by utilities and the coalition of nonutility parties. Since the DPU

did not participate in the collaborative process, the agreement failed to address the regulators’ concerns and major

changes were made to the initial proposals. Two of the utilities decided to use the process on an ongoing basis,

but the remaining phase II collaboratives were terminated after the initial objectives were met.

1 The DPU ruled that utilities were permitted to choose between expensing or capitalizing their DSM

expenditures. DPU also required use of the societal test for determining cost-effectiveness instead of the ratepayer

impact measure.

SOURCE: Office of Technology Assesment 1993, from Jonathan Raab and Martin Schweitzer, Public Involvement in Integrate d

Resource Panning: A Study of Demand-SideManagement Collaboratives,ORNL/CON-344 (Oak Ridge, TN: Oak Rldge National

Laboratory, 1992).

■ Incorporation of environmental factors, new resources is allowed or required. Box 6-C

■ An open process that includes public partici- and figure 6-2 show details.

pation in the development and review of A review of utilities’ IRP plans by researchers

plans, and at Oak Ridge National Laboratory found similarities in the content of the plans. The majority of

■ Increased attention to uncertainty and

risk.7 plans included:

, Forecasts of energy and demand,

State resource planning requirements are usu- ■ Discussion of demand-side resources,

ally coupled with incentives for DSM investment. ■ Presentation of an integrated resource plan or

Acquisition of supply-side resources has also plans,

changed. Increasingly, competitive bidding for ■ Discussion of uncertainty analysis, and

7 Edison Electric Institute, Rate Regulation Departmen~ Stare Regulato~ Developments in Integrated Resource Planm”ng (Washingto%

DC: Edison Electric Institute, September 1990), p. 1.
124 I Energy Efficiency: Challenges and Opportunities

Figure 6-l-Status of IRP Implementation

for Electric Utilities

Across the States, 1992

—

, 0

Eic!s Level of IRP implementation

U Not under active consideration

U Under consideration

Efil Program under development

= Program in implementation

B IRP requirements in practice

SOURCE: Office of Technology Assesment, 1993, based on data from National Association of Regulatory Utility

Commissioners, Incentives for Demand-Side Management (Washington, DC: National Association of Regulatory Utility

Commissioners, January 1992).

■ Descriptions of computer models used in

plan preparation.8

1 What Makes a Least-Cost Plan?

The fundamental goal of utility planning processes is the development of resource plans that

provide reliable service and minimize costs while

preserving financial stability. However, with the

inclusion of demand-side resources, the diversity

of options has increased multifold. Cost, equity

and customer participation are key determinants

in selecting the resource mix, yet the definition of

cost reflects policy as well as economic choices.

The “lowest-cost’ resource mix is heavily influenced by the selection of a cost-effectiveness test

as well as how the resources are compared on

other characteristics. To some, lowest-cost means

minimizing the price of electricity, while to others

it is minimizing cost of energy services.

Regulators have prescribed the tests utilities

must use to determine the cost-effectiveness of

their resource plans in order to have a consistent

method for evaluating the costs and benefits of

resource options. Table 6-2 shows the prescribed

tests for utility resource plans in selected States.

There is controversy over the appropriate economic tests to use when evaluating DSM programs that improve customer energy efficiency

and therefore reduce electricity purchases. The

desirability of a demand-side option is often

8 Martin Schweitzer, Evelin YourStone, and Eric H@ Key Issues in Elecm”c Utility Integrated Resource Planm”ng: Fin&”ngs from a

Nationwide Sfudy, ORNLJCON-300 (Oak Ridge, TN: Oak Ridge National Laboratory, April 1990), p. 41.
— —

Chapter 6--State Energy Efficiency Initiatives I 125

Box 6-C-Competitive Bidding for New Utility Resources

Competitive bidding for utility resources additions has been growing since 1984. Both supply-and

demand-side resource options have been put up for bid. By August 1993, utilities had issued more than 124

requests for proposals (RFPs) for new resource additions. These RFPs elicited over 3,500 proposals for over

250,000 megawatts (MW) of power. Of these, 702 bids were for demand-side resources totaling 1,935 MW.

Increasingly, a wide diversity of technoiogies are being proposed and winning bids. With the growing adoption of

integrated resource planning, the trend toward competitive procurement is likely to accelerate as utilities specify

which technologies interest them.

According to an analysis of bid competitions, through May natural gas projects and coal projects dominated

the winning bids, with natural gas totaling 47 percent of winning bids. Proposals for repowering existing

powerplants, municipal waste-to energy plans, geothermal, and energy conservation are faring increasingly well.

Between 1991 and 1992, existing plant capacity bids increased from 1,616 megawatts to 5,219 megawatts, just

slightly behind coal.

Energy conservation proposals doubled between 1991 and 1992 and winning bids, primarily bids

emphasizing commercial and industrial measures, increased 21 percent the same year. In 1993 winning bids for

DSM measures were up by 63 percent over 1992 results. There have been many fears about bidding for

demand-side resources. For instance, the fear that demand-side projects will fail without enough time for utilities

to develop economically viable alternatives seems to be unfounded. To date canceled conservation projects were

terminated before power purchase contract was signed so utilities were not stranded for power. In 1992-93,

however, utilities cancelled 88 MW of DSM projects primarily because of changes in economies.

SOURCE: Office of Technology Assessment 1993, Robertson’s Current Competition, vol. 3, No. 2, May 1992 and vol. 4, No. 3, August

1993.

contingent on the economic test selected. The cost measure, and the societal cost measure (see

application of cost-effectiveness tests to demandside resources is more complex than for supply-

-side resources for two reasons. First, many

energy-saving demand-side measures belong to

customers, not the utility. As a result, the costs

and benefits are distributed differently for demandside measures than supply-side measures. Second, demand-side resources exhibit different

operating characteristics, system impacts and

availability than traditional supply-side resources.9

ECONOMIC TESTS FOR EVALUATING

DSM PROGRAMS

There are four commonly applied perspectives

used for assessing the relative costs and benefits

of resource options. The perspectives are the total

resource cost, the rate-impact measure, the utility

box 6-D). Several other tests are available, but are

applied less frequently.

Total Resource Cost Test

The total resource cost test (TRC) measures the

net benefits of a program from the point of view

of the utility and its ratepayers as a whole in order

to maximize welfare. The test determines whether

the program being evaluated will increase or

decrease the total costs of meeting the customers

service needs. Programs that pass this test minimize total cost of electric energy services. More

DSM programs will pass the TRC test than the

rate impact measure (see below) because it is not

restricted by possible adverse rate impacts. Critics of this test argue that the utility is put at

competitive risk should implemented programs

g Florentin Krause and Joseph Eto, hwrence Berkeley Laboratory, Lzast-Cost Utility Planning Handbook @ Public Utility

Commissioners, vol. 2, prepared for the National Association of Regulatory Comissioners, December 1988, p. III-1. Hereafter referred to

as Krause and Eto, Least-Cost Utility Plamu”ng Handbook.
126 I Energy Efficiency: Challenges and Opportunities for Electric Utilities

Figure 6-2-States with Competitive Bidding for Utility Resource Additions 1992

, 0

\

—

n%

h} / I I i 1

01 .

‘m

.’4

f

.3

SOURCE: Office of Technology Assessment, 1993, based on information from Hope Robertson, Robertson’s Current

Competition, voi. 3, No. 2, May 1992.

Table 6-2—DSM Cost-Effectiveness Tests Mandated by

Selected Public Utility Commissions

Ratepayer Total

Impact resource Societal Utility

State measure cost test cost test cost test

Arizona. . . . . . . . . . . . . . . . . . . . . .

California. . . . . . . . . . . . . . . . . . . .

District of Columbia. . . . . . . . . . . .

Hawaii. . . . . . . . . . . . . . . . . . . . . . .

Maine. . . . . . . . . . . . . . . . . . . . . . .

Maryland. . . . . . . . . . . . . . . . . . . . .

Massachusetts. . . . . . . . . . . . . . .

New Jersey. . . . . . . . . . . . . . . . . . .

—

Y

N

Y

Y

—

N—

—

Y

Y

Y

Y

Y

Y

Y

Y

—

Y

Y

—

—

Y

—

Y

Y

—

NOTES: Blank space indicates state commission has not ruled on the cost test.

SOURCE: Edison Electric Institute, Rate Regulation Department, Integrated Resource Planning in the States.’ 7992

Sourcebook (Washington, DC: Edison Electric institute, 1992), p. xii.
Chapter 6-State Energy Efficiency Initiatives I 127

Box 6-D--Overview of Cost-Effectiveness Tests for DSM Programs

Total Resources Cost Test/All Ratepayers Test

Perspective

Measure of the total net resource expenditures of a DSM program from the point of view of the utility and the

ratepayers as a whale. Measures the change in the average cost of energy services across ail customers.

Resource costs are defined to include changes in costs to supply, utility and participants.

Beneflts measured

Avoided supply costs of anticipated reduction in energy load.

Costs measured

Utility program costs, including incentive payments to customers and customer direct costs.

Ratepayer Impact Measure (RIM)

Perspective

Measure of the difference between the change in the total revenues paid to a utility and the change in total

costs to a utility resulting from the DSM program if the change in revenues is larger or smaller than the change

in total costs, then the rate levels may have to change because of the program

Benefits measured

Utility avoided costs.

Costs measured

Total program costs, including customer bill savings and incentive payments to customers.

Utility Cost Test

Perspective

Measure of the change in total costs to the utility that is caused by a DSM program, i.e., the change in revenue

requirements. Also measures the change in average energy bills across all customers.

Benefits measured

Utility avoided costs.

Costs measured

Program costs, including incentive payments to customers and custorner direct costs.

Societal Test

Perspective

Measure of the net benefits of a DSM program fromthe point of view of society as a whole. Attempts to capture

all the benefits and costs of a DSM program, including externalities, by using societal discount rate rather than

utility specific rate.

SOURCE: Office of Technology Assemessment 1993.
128 I Energy Efficiency: Challenges and Opportunities for Electric Utilities

increase rates. Additionally the TRC test does not

consider whether the programs will result in

cross-subsidization of customer classes.l0 At least

seven States have designated the TRC test for

cost-effectiveness and four rely on it exclusively.11

Ratepayer Impact Measure

The ratepayer impact measure (RIM), also

known as the nonparticipant test or the “no

losers” test, focuses on the impacts a program

would have on nonparticipating utility ratepayers

and thereby minimizes electricity prices. The test

evaluates programs based on whether rates are

increased for nonparticipating customers by the

proposed program because of additional revenue

requirements. A program is deemed costeffective only if it reduces revenue requirements.

It fails the test when its adoption would create a

revenue deficit for the utility that would be

recovered through a rate increase. Adoption of

programs that fail the RIM require that nonparticipants subsidize the participants’ acceptance of

the program. This test is considered comparatively restrictive for DSM programs compared

with the other three tests. Opponents of RIM

argue that its use increases overall costs of electric

energy services. They also argue that the test

results in the uneven treatment of investments,

and shifts spending away from DSM. For instance

all customers are participants in supply-side

investments by the nature of the investment,

whereas demand-side investments will have fewer

participants.

12 Utilities in eight States are currently applying this test, and three regulatory

commissions require its use in conjunction with

other tests. Other States have specifically rejected

the test to screen DSM programs, or given it a

secondary role.13

Utility Cost Test

The utility cost test is an accounting measure

for utilities’ costs. It measures the difference

between the utility’s avoided cost and the cost of

program implementation to the utility and does

not incorporate the cost to the ratepayers. As such,

many DSM programs pass this test since part of

the program cost assumed by the ratepayer is not

included. However, supply-side measures evaluated under this test will be at a disadvantage

because the full cost of supply measures is borne

by the utility .14 California, Hawaii and Maine use

this test in conjunction with other perspectives.15

Societal Cost Test

The societal cost test is similar to the TRC;

however, it incorporates environmental externalities when evaluating the costs and benefits of a

program. The other distinction from the TRC test

is that the societal test uses a societal discount rate

rather than an utility specific one. Arizona,

Hawaii, and Maine have each specified use of the

societal test.l6

Cost Test Comparisons

Some States request that programs are evaluated with more than one test. For instance, if a

program narrowly fails the nonparticipant test,

10 mid., pp. III-8-9 and Eleefric power Research Institute, Ed-Use Technical Amassment GIU”dk, VOI. 4, HCU-7222S @fdO Mto, CA

Electric power Research bstitute, Au~st 1987) pp. 1-14-16.

1 I EEI, ]~reg~ute~ Resource Planning in the States: 1992 Soucebook, sup note 1, pp. x-fi.

12 time ~d Et~, ~mt<o~t u~”li~ Planning Ha~book, supm note $), pp. ~-5-c ~d WM, End-use Technical Assessment Guide, SUpm

note 10, pp. 1-17-19.

13 ~, Integrated Re80wce planning in the states: ]P$)z sourceboo&, SUpm DOk 1, pp. x-xii d EEI state Regulato~ Developments in

Integrated Resource Planning, supra note 7, pp. 14-16.

14 muse ~dEto, fiat-cost utili~ planning Handbook, ~p~ note g, p. ~-7 ~d ~~, End-use Technical Assessment Guide, supra note

10, pp. 1-20-22.

15 EEI, Integrated Resource Pianm”ng in the States: 1992 Sourcebook, SUp~ note 1, pp. X-M.

16 Ibid.
the State may require that the utility run the TRC

test. If it passes the second test, the utility maybe

able to adopt the program after making adjustments to minimize rate impact and crosssubsidization. The Maine Public Utility Commission stated that a DSM program that:

. . . is reasonably 1ikely to satisfy the All

Ratepayers Test [the TRC] is cost effective

.$.Any program that is reasonably likely to

satisfy the All Ratepayers test and to fail the Rate

Impact Test [nonparticipant test], but only to the

extent that the utility’s present value of revenue

requirements per kilowatt-hour (kWh) do not

increase by more than 1 percent over the duration

of the program, maybe continued or implemented

without prior program specific Commission approval. 17

California, Florida, Nevada, New York, Ohio,

and Vermont also use combinations of tests to

evaluate proposed programs.

Chapter 6-State Energy Efficiency Initiatives I 129

STATE INCENTIVES FOR

UTILITY DSM INVESTMENTS

Advocates of least-cost planning believe utilities should pursue efficiency options because they

are often less expensive than supply-side alternatives. However, utilities do not necessarily view

cheaper as better unless it also results in greater

profits, A 1990 survey of utility management and

State regulators found that the two generally

agree on the reasons for DSM incentives. Both

agreed that there is a need for incentives to

provide a bonus to stimulate DSM, to get utility

management to focus on DSM, and to overcome

the lost revenue problem. Utility representatives

also considered compensation for lost profit a

priority, while regulators emphasized a level

playing field.18

States have authorized a variety of rate mechanisms to overcome constraints to investments in

customer energy efficiency via DSM programs.

Regulators are not the only parties to propose

these rate mechanisms. Utilities themselves as

well as intervener parties have also been involved. The most active promoters have adopted

several mechanisms that work together not only

to remove the disincentives to DSM, but also to

make DSM desirable by using a reward component. Innovative rate designs have included:

Decoupling mechanisms that separate sales

and rate of return,

Cost recovery mechanisms to overcome the

lag in recovering DSM program expenses,

Last revenue mechanisms to compensate for

DSM program impacts on profitability, and

Performance incentives to improve performance of DSM programs.

1 Decoupling

Decoupling removes the disincentive of promoting energy efficiency when it directly reduces

utility profitability. Decoupling mechanisms separate the fixed cost recovery from kilowatt-hour

sales. Traditionally, electricity sales are measured

over a test year, or forecast if a future test year is

used, and then the estimated sales level is used to

design rates. Once established, the sales assumption remains fixed until the next rate case. The

rates provide for recovery of freed costs and a

return on investment. Aggressive DSM can subsequently reduce sales below the level assumed in

the rate case resulting in under-recovery of fixed

costs and a reduction in shareholder return.

A number of States are using or experimenting

with various degrees of decoupling. The first

approach, applied in California and Maine, is

17 WC ~st, ‘‘De~tjon ad Tradeoffs: cost-l?ffectiveness of Utility DSM ~OgfllmS,’ ACEEE ~W2 S ummer Study on Energy Eficiency

ofBuil&”ngs, vol. 8 (Washington, DC: i%nerican Council for an Energy-Efficient lkonomy, 1992), p. 8.89. Quote is from Ma.ine Fublic Utilities

Commission ‘‘Rule Concerning Cost-Effectiveness of Utility Energy Efficiency Investments and Programs,’ (chapter 38), DocketNo.86-81,

1987.

la MjcMel W. Reid, Barakat ~d -berm ~c., “Hot lbpic Survey: Regulato~ Incentives for DS~” prepared for Edison Electric

Institute, December 1990.
130 I Energy Efficiency: Challenges and Opportunities for Electric Utilities

intended to eliminate the utility’s incentive to

increase sales, preventing sales fluctuations from

impacting on a utility opportunity to earn its rate

of return. The intent is revenue neutrality, i.e. to

provide no financial incentive to increase or

decrease sales. The other approach combines an

incentive for investment in cost-effective DSM

with a disincentive when sales increase.19 Additional States adopting decoupling are Connecticut, New York, and Washington. Colorado and

Virginia are investigating the option.

California’s ERAM (Electric Revenue Adjustment Mechanism) is the most well known decoupling mechanism of this type. ERAM eliminates

sales fluctuations as a factor in determining

realized profits. It accounts for many factors

affecting electricity sales other than DSM programs, including weather and general business

conditions. The mechanism reconciles actual and

forecast net revenues, based on future test year

used in rate design. To accomplish its goal,

ERAM periodically adjusts rates in order to

restore the balance established by the rate case.

Proponents of this mechanism argue that it

encourages the financial health of the utility by

reducing the risk exposure in sales fluctuations.

Other justifications include eliminating the disincentive to conservation and the incentive to

underforecast sales in a rate case.20 Washington

has also adopted an ERAM-type mechanism for

one of its utilities.

However, ERAM also has some disadvantages.

The incentive to underspend on conservation

measures remains. Spending less than budgeted

on a program will in turn increase earnings.21 For

the utility, the risk is the potential increase in

customer “bypass.” In the case of a bypass, a

large energy consumer, such as a major industrial

facility, removes itself from the customer base by

supplying its own power-bypassing the local

utility. If there is a significant ERAM deficit in a

given year, the following year’s rates would rise

which would increase the likelihood that the

customer might seek an alternate source of power.

The end result of bypass for the utility is

underutilized capacity, fewer customers, and

higher rates to recover freed costs from the

customers that remain. If load reductions are

significant enough, the utility may be forced to

remove unused facilities from its rate base and

lose its opportunity to recover a portion of its

capital investment. However, evidence to date has

not shown that ERAM has enough impact on rates

to induce appreciable bypass.22

The Maine commission has approved a 3-year

experiment with a lost revenue mechanism similar to ERAM for one utility in the State. The

experimental approach makes an adjustment for

revenue attrition rising from higher than expected

DSM program savings. It has also changed the

accounting rules for the fuel revenue account by

setting the nonfuel revenues from marginal wales

at zero. As a result, any incremental sales do not

add to profits.23

Connecticut has allowed one utility a “partial

sales adjustment clause’ that collects margins

associated with sales falling below the test year

forecast or returns profits to ratepayers if they are

higher than expected sales. However, the partial

adjustment does not insulate the utility from the

19 David MoskoVi@ Profits and Progress through Least-Cost Planning (Washington, DC: National A.$sOChtiOn of RWd@OrY u~u

Commissioners, November 1989), p. 13.

m c my~ GA. Coma, &zw&”ng for conservation: The Call~ornia ERAM experience, LBL-28019 (Berkeley, CA: hwnce

Berkeley I.Aoratories, March 1990), pp 3-4. This report also notes that an additional motivation for California’s ERAM was to bolster the

financial health of utilities.

21 Ibid. p. 35.

22 Ibid., pp. 16-21.

23 David Moskovi~ supra note 19, p. 13.
Chapter 6-State Energy Efficiency Initiatives I 131

normal risks of doing business such as economic

cycles, weather, and competition.24

New York has added a decoupling mechanism

for three of its utilities. Consolidated Edison will

determine net lost revenues based on studies of

sales reductions during the program implementation year. The company estimates freed costs that

will not be recovered due to DSM programs,

which are then retrieved in the fuel adjustment

clause. The studies take into account the effects of

free-riders and will be used to reconcile DSM

program results with sales forecast.25

1 Recovering Demand-Side Energy

Efficiency Investments

As DSM expenditures grow, utilities and

regulatory bodies are faced with the issue of how

to recover costs. When DSM was in its infancy,

expenditures could easily be expanded annually

without adversely impacting the financial wellbeing of the utility. However, with aggregate

utility DSM expenditures having escalated to

over $2 billion a year in 1991, the manner and

extent to which DSM costs are recovered has

become a priority. DSM program costs include

administrative and operating costs, customer

rebates, and other customer incentives. Utility

DSM expenditures are not fully recovered in rates

when DSM programs surpass the budget amount

set in the ratemaking test. It is important to note

that cost recovery mechanisms do not overcome

the utilities’ incentive to sell maximum amounts

of kilowatt-hours and earn a return on the amount

sold. However, the combination of recovered

DSM expenses and compensation for lost revenue

removes the risk that successful DSM programs

will threaten profits.

Most operating costs in the utility industry are

recovered as expenses in the year that they are

incurred. Expenses are simply passed through to

customers and do not earn a rate of return. A

simpler accounting method than the alternative

ratebasing, expensing results in lower costs with

certain discount rates and tax treatments. It also

allows for a faster cash flow and removes the

uncertainty over which costs will be included in

the rate base. When DSM programs were small,

outlays were easily handled though expensing.

However, many now argue that expensing is no

longer appropriate and the DSM expenditures

should be ratebased. Expensing does not provide

enough security for the utility to develop programs, as the risk of penalty for disallowing costs

is stronger than the incentive. As many of the

DSM programs include long-lived measures that

are expected to provide savings for many years,

proponents of ratebasing believe the programs

should be accorded equal treatment with supply-

-side options in the ratebase. There are three

recovery methods in use by the States for DSM

expenditures:

Deferment to rate case—variations not accounted for in rates are deferred until the next

rate case.

Flow through to rates-expenditures not

accounted for flow through to rates via a fuel

clause, surcharge, rider or other adjustment

mechanism to rates.

Ratebased recovery expenses including general and administrative costs associated with

plarnning and managing DSM programs are

added to ratebase.

DEFERMENT TO RATE CASE

The cost recovery problem is partially addressed if States allow utilities to defer the

amount above the budget until the next rate case

where it will be considered for the following rate

period. However, if no carrying charges are

allowed, the utility loses any adjustment for the

time value of money. Additionally, the possibility

of cost disallowances remains.

~ EEI, Integrated Resource Planning in the States: 1992 Sourcebook, supra nOte 1, p. XXX.

~ Natio@ Ass~~tion of Re~bto~ l,ltjli~ commissioners, Incentives for Denumd-Side Munugemenr ~z3ti&@4 DC: NatiO@

Association of Regulatory Utility Commissioners, January 1992), pp. 155-160.
132 ! Energy Efficiency: Challenges and Opportunities for Electric Utilities

FLOW THROUGH TO RATES

Some States have responded by instituting a

balancing account where the utilities recover the

outlays from DSM. The account provides a

mechanism for the utility to collect from its

ratepayers the actual DSM expenditures, with

interest. The accounting may be done through

either the fuel adjustment clause, which reconciles actual fuel costs with projected expenditures, or a separate account. The balancing

account ensures recovery, yet does not provide a

profit for underspending. Expensing and cost

recovery do not account for revenues losses from

sales foregone because of DSM.

A recent study sponsored by the National

Association of Regulatory Utility Commissioners

(NARUC), which surveyed DSM options in

Michigan, concluded that balancing account expensing offers advantages over other methods of

cost recovery.

26 The policy g rOUP recommende d

that Michigan allow receipts to be adjusted up or

down in relationship to expenditures. This would

be accomplished by modifying the conservation

surcharge mechanism currently in place. This

treatment of expenditures minimizes the utility’s

risk of cost disallowance and allows timely

recovery and flexible spending levels. The report

notes that this mechanism for recovery should be

linked with a performance incentive to maximize

value.

RATEBASED RECOVERY

Ratebased recovery allows the utility to include DSM investments in the rate base. Since

ratebased items earn a return, DSM items will as

well. DSM expenditures are capitalized and have

an amortization period over which they earn a

return. This allows the benefits to be charged over

the lifetime of the investment. Ratebasing provides a fair return to shareholders, making it

easier to attract necessary capital. However, it is

unlikely that ratebasing alone can stimulate DSM

investment because every additional kilowatthour sold may add to revenues and profits.

Ratebasing of DSM resources creates new risks

for the utility. The potential of cost disallowance

in a prudence review may make investors wary.

With the perception of risk, needed capital maybe

costlier. DSM may be particularly susceptible

since much of it is not backed by utility-owned

assets unlike the investment in supply-side measures, like powerplants.

There are also considerations for the regulators.

There is a higher revenue requirement from

ratebasing. It also does not provide any inherent

incentive to control costs, except for utility fear of

subsequent disallowances. Utilities may invest in

the most expensive efficiency measures to maximize their return (’ ‘goldplating’ ‘). Alternatively,

in situations where a measure achieves less

savings than authorized, the utility sells the

unanticipated kilowatt-hours and recovers DSM

costs that were not lost.

H Status of State Cost Recovery Provisions

A 1992 study by the Edison Electric Institute

found that 13 States have authorized deferred

recovery, 19 States have approved a flow-throughto-rates mechanism and 17 States have allow

ratebasing of DSM programs.27 Table 6-3 shows

all the States, but the following States illustrate

the diversity of approaches taken to date:

■ Indiana has authorized its utilities to defer

DSM program costs with carrying charges

until the next rate case and the utility will be

allowed to recover costs that appeared costeffective when they were incurred.28

26 “S~~.Savfigs ~d Expensing Favored in Michigan S~dy,” Demand-Side Monthly, August 1991, pp. 1-3.

27 EEI, fntegrazed Resource Planning in the Stares: 1992 Sourcebook, supra note 1, pp. --N.

2S ~son Elec~~ ~ti~te ~d Elec~c power Rese~h ~ti~te, DSM]ncentiveRegu&rion: status and current Trends (wSShingtoq ~:

Edison Electric Institute, March 1991), p. 14. Hereafter referred to as EEI, DSMlncentive ??egulation.
Chapter 6-State Energy Efficiency Initiatives I 133

Table 6-3-State Regulatory Initiatives for Demand-Side Management, 1992

Ratebase Lost Higher rate Shared

State recovery =

revenue b Decouplingc

of returnd Bounty•savlngs f

Alabama. . . . . . . . . . . . . .

Alaska . . . . . . . . . . . . . . .

Arizona . . . . . . . . . . . . . . .

Arkansas. ..,. . . . . . . . .

California . . . . . . . . . . . .

Colorado . . . . . . . . . . . . . .

Connecticut. . . . . . . . . . .

Delaware . . . . . . . . . . . . .

District of Columbia. . . . .

Florida. .,....... . . . . . .

Georgia . . . . . . . . . . . . . . .

Hawaii. . . . . . . . . . . . . . . .

Idaho . . . . . . . . . . . . . . . . .

Illinois. . . . . . . . . . . . . . . . .

Indiana . . . . . . . . . . . . . . .

Iowa. . . . . . . . . . . . . . . . .

Kansas . . . . . . . . . . . . . . .

Kentucky . . . . . . . . . . . . .

Louisiana . . . . . . . . . . . . .

Maine . . . . . . . . . . . . . . . .

Maryland. . . . . . . . . . . . . .

Massachusetts. . . . . . . .

Michigan . . . . . . . . . . . . . .

Minnesota . . . . . . . . . . . .

Mississippi. . . . . . . . . . . .

Missouri . . . . . . . . . . . . . .

Montana . . . . . . . . . . . . .

Nebraska . . . . . . . . . . . . .

New Hampshire . . . . . . . .

New Jersey . . . . . . . . . . .

New Mexico . . . . . . . . . . .

New York. . . . . . . . . . . . .

— — — —

—

—

—

—

— —

x

—

x

—

—

—

— — — x

—

x

x

x

— — — —

x

x

—

x x —

— — — —

x

—

x

x

—

x

—

—

— —

x

x

—

— — — x — — — — —

x

x

—

x

x

— —

x

— —

—

x

— —

— — — —

x

x

x

—

—

x

x

—

— — — —

—

—

—

— — —

x

x

—

—

—

—

—

x — — — —

— — — — — —

x

x

x

x

x

x

x

x

x x

x

—

— —

—

—

— —

x

x

x

—

— — x —

x — — x — — — —

—

—

— —

— — — — —

x

—

—

x

— — x

—

—

—

—

x

x

— — —

x

x

— —

— — x — — — — —

—

—

x x x x x

(Continued on next page)

expenditures through the fuel adjustment

clause. Any monthly variances will be

tracked and accrue interest. Cumulative variances will be added to or subtracted from

projected DSM costs for then next year.31

Colorado has approved ratebasing for the

Public Service of Colorado with a 7 year

amortization period, including expenditures

used for load research.32

New Jersey and North Carolina have adopted

regulations to provide for deferred costs,

with a return.29

Hawaii, New Hampshire, Ohio, and Rhode

Island have exclusively chosen a balancing

account for cost recovery for DSM pro- ■

grams.

30

The New York Public Service Commission

will allow its utilities to recover DSM

29 NMUC, Incentives for Demand-Side Management, supra nOte 25, pp. 9-13.

w Ibid., pp. 9-13.

31 Ibid., p. 149.

32. EEI, Integrated Resource Planning in the States: 1992 Sourcebook, supra note 1, pp. --W.
134 I Energy Efficiency: Challenges and Opportunities for Electric Utilities

Table 6-3-State Regulatory Initiatives for Demand-Side Management-(Continued)

Ratebase Lost Higher rate Shared

State recovery. revenue b Decouplingc

of returnd Bounty•savlngs f

Nevada. . . . . . . . . . . . . . . x x — x — —

North Carolina . . . . . . . . — — — — —

North Dakota . . . . . . . . .

—

x — — — —

Ohio. . . . . . . . . . . . . . . . . —

—

x — — x

Oklahoma . . . . . . . . . . . .

—

x — — —

Oregon. . . . . . . . . . . . . . .

— —

x x — — — x

Pennsylvania. . . . . . . . . . x — — — — —

Rhode Island . . . . . . . . . . — — — — x

South Carolina . . . . . . . . . —

—

— — —

South Dakota . . . . . . . . . . —

— —

— — — —

Tennessee . . . . . . . . . . . . —

—

— — — —

Texas. . . . . . . . . . . . . . . .

—

x — — x

Utah. . . . . . . . . . . . . . . . . —

— —

. — — — —

Vermont. . . . . . . . . . . . . . x x — — — x

Virginia . . . . . . . . . . . . . . . — — — —

Washington. . . . . . . . . . .

— —

x x x x x

West Virginia . . . . . . . . . . —

—

— — — — —

Wisconsin. . . . . . . . . . . . . x — — —

Wyoming. . . . . . . . . . . . . —

— —

— — — — —

NOTES: An X in a column indicates that:

a State allows utility to capitalize and amortize DSM expenditures.

b State allows utility to recover loss revenue attributable to DSM programs.

C state has established mechanism that separates power sales from profit.

d State allows utility an adjustment in overall rate of return for DSM program performance.

e State allows utilitya specific bonus amount for either kilowatts saved or kilowat-hours saved in DSM programs.

f State allows utility to receive a percentage share of benefits from its DSM management programs.

SOURCES: Office of Technology Assessment, 1993, based on data from Edison Electric Institute, Integrated Resource Planning in the States: 1992

Sourcebook (Washington, DC: Edison Electric Institute, June 1992); National Association of Regulatory Utility Commissioners, Incentives for

Demand-S/de Management (Washington, DC: National Association of Regulatory Utility Commissioners, January 1992); and Office of Technology

Assessment staff research.

■

■

■

The District of Columbia has authorized

ratebased recovery of costs over a 10-year

period. 33

Iowa has a statute authorizing ratebasing of

DSM, in addition to recovery outside of

general rate cases and adjustments up or

down based on perforrnance.34

Maryland has approved ratebasing for one of

At least ten States give the utilities a choice

between ratebasing and expensing.36

■ In Massachusetts DSM programs costs can

be expensed or capitalized as they are

incurred dollar-for-dollar and are tracked by

a separate account. Actual DSM expenditures are charged against the fund monthly.

The commission has stated that costits utilities with a 5-year amortization period recovery will be linked to performance

for DSM expenditures.35 beginning in 1992.37

33 EM, DSM]~entive Regulation, Suprs nOte 28, P. 13.

M Ibid., p. 15

35 EM, IntegratedReSource Planning in the States: 1992 Sourcebook, supra note 1, pp. *-fi.

36 NARUC, Incentives for Demand-Side Management, SUpm note 25, PP. ~.5-~.8

37 ~c~el Reid and John Charnberlin, ‘Financ ial Incentives for DSM Programs: A Review and Analysis of Three Mechanisms,’ ‘ in ACEEE

Summer Study 1990, vol. 5 (WashingtorL DC: American Council for an Energy-Efficient Economy, 1990), pp. 5,161-5,162.
9

■

Chapter 6-State Energy Efficiency Initiatives 1135

Figure 6-3-The Sales-Earnings Link

$

Over recovery

(added profits)

Underrecovery

of costs and

earnings

Revenues

(contributions to

fixed costs and

earnings)

Fixed costs

(including

aIlowed

earnings)

1 ---

Sales Test year

(kWh) sales

Utility rates are set on the basis of test year sales so that expected sales will recover fixed costs and the

authorized return on the rate base. This is shown above as the intersection of the two lines labeled fixed

cost andcontribution to fixed rests and earnings. If sales are lower than assumed for the test year, the

utility will not recover its fixed costs or earn its authorized rate of return (shaded area to left of intersection

point). If, however, sales are higher than projected, the utility will recover its fixed costs and earn more

than its authorized rate of return (shaded area to right of intersection point).

SOURCE: Office of Technology Assessment, 1993, adapted from Edison Electric Institute, Demand-S/de ManagementIncentive Regulation: Status and Current Trends (Washington, DC: Edison Electric Institute, March 1991 ), p. 8.

Vermont has established an account entitled

the Account Correcting for Efficiency, a

mechanism for the recovery of DSM expenditures which can be ratebased or expensed.38

Washington allows net conservation costs to

be placed in rate base, earning a rate of

return, although the return can only be

applied to pre-identified conservation amounts

subject to review. Any conservation investment made after the cutoff date will not be

allowed in the rate base, but will be allowed

to accumulate a carrying charge equal to the

company net-of-tax return.

Cost recovery approaches are a frost step to

removing the barriers to investments in demandside efficiency. Both ratebasing and expensing

with a return address regulatory lag, allowing

utilities to recover freed costs. However, the

inherent regulatory incentive to sell rather than to

save power remains .39

1 Lost Revenue Incentives

Lost revenue is a primary constraint to utility

adoption of significant DSM programs. The

losses arise when the utility under-recovers its

fixed costs due to a successful DSM program that

reduces kilowatt-hour sales. The utility sells less

power than is forecasted and receives lower

revenues, directly reducing profits. The more

successful the DSM program, the greater the loss

(as shown in figure 6-3). Such programs under

traditional ratemaking work against the utilities’

financial interests. While some States have addressed this issue through decoupling provisions,

38 NARUC, Incentives for Demand Side Management, SUpra note 25, pp. 1O-13, 2~.

39 David Moskovi@ supra note 19, p. 5.
136 I Energy Efficiency: Challenges and Opportunities for Electric Utilities

21 other States have authorized utilities to recover

the lost revenue attributed to DSM success.40

DSM SPECIFIC ADJUSTMENT

This mechanism provides a method for the

utility to recover the estimated amount of lost

revenue specifically attributable to DSM. Frequently, it involves an incentive/disincentive

combination. One way it works is to set a DSM

goal for the utility. If the goal is met, the utility

receives the lost revenue. However, if performance is not met, the utility forgoes the lost revenue

to the ratepayers. States including Indiana and

Maryland have allowed for recovery of lost

revenue. The other States are listed in table 6-3.

Although DSM specific adjustment removes

the disincentive to investment in DSM, the utility

still benefits from selling additional kilowatthours. The most profitable programs under this

adjustment alone are those that look good on

paper and save nothing.

Indiana has approved recovery of lost revenue

for a utility, PSI Energy. The utility is authorized

to defer, with carrying charges, recovery of the

revenue attributable to DSM programs. There is

a stipulation that the DSM programs be prudent.

Then, at the next general rate case, recovery is

considered. 41 For Southern Indiana Gas and

Electric, another utility in the state, a “lost

margins tracker’ mechanism was approved, operating similarly to a fuel adjustment clause.

The Maryland commission has authorized lost

revenue recovery for the Potomac Electric Power

Company (PEPCO) to be incorporated into the

cost recovery mechanism. Lost revenues are

estimated through the reduction in demand and

energy consumption attributed to the DSM programs. The revenue recovery mechanism is the

‘‘DSM Surcharge,’ which is calculated annually

based on program cost projections and the forecasted sales. The surcharge rider is then applied

on years when PEPCO’S return on rate base is

below the authorized return. If the return on rate

base is greater than the authorized return, all

program costs, including lost revenue, are deferred until such year the rider is applicable.42

I Performance Incentives

States have begun to combine the mechanisms

to reimburse expenses and lost revenues with

further incentives to encourage better performance in DSM programs. Some States reward

utilities shareholders with a monetary bonus or

reward for successful DSM efforts. Proponents of

shareholder incentives say that the mechanisms

stimulate expanded utility development of conservation and load management programs. On the

other hand, opponents of the incentives say that

the mechanisms may lead to increased customer

costs and that DSM development could drive up

short-term rates.

Since Wisconsin first passed a shareholder

incentive in 1987, 17 States have authorized

incentives for a total of 36 utilities. An additional

5 States have approved generic incentives and 5

more States have proposals under consideration.43 However, the Florida commission decided

not to initiate a rulemaking on incentives. It

should be noted that utilities, State collaborative,

and State legislators have also been the initiators

for incentive proposals. Wisconsin was also the

frost State to determine that DSM in 1992 has

developed to the extent that shareholder incentives were no longer necessary. The States that

have acted to date are the ones with commissions

40 EEI, Integrated Resource Planning in the States: 1992 Sourcebook, SUpm note 1, pp. ti-XXxv.

41 NARUC, Ineemivt?s for Demand-Side Management, supra note 25, p. 81.

42 Ibid., p. 101.

43 Job H. m~l~ Julia B. 13m~ and ~c~el W. Reid, ‘‘Gaining Momentum or Running out Of SteW? Utility Shareholder Incentive

Mechanisms-Pas~ Presenq and Future,” ACEEE 1992 Summer Study on Energy Eficiency in Buildings, vol. 8 (Washington DC: American

Council for an Energy Efficient Economy), p. 8.23.
“ ——

Chapter 6-State Energy Efficiency Initiatives I 137

that are historically receptive to regulatory innovation. 44

Studies have shown that utilities with incentives have increased their DSM expenditures and

savings. Diverse approaches have been tried in

order to stimulate performance including varying

bonuses on rates of return, bounties, and sharedsavings mechanisms.

RATE OF RETURN ADJUSTMENTS

The rate-of-return adjustment, either on the

total return or just to the equity portion, is linked

to a DSM target level of performance. Under this

approach, the regulatory agency adjusts the return

based on the performance of DSM programs-a

higher return with better performance and a lower

return with poorer performance. Although the

conditional bonus requires increased oversight

from regulators, it offers advantages over other

rate-of-return adjustments. Its structure is compatible with the least-cost policy by discouraging

overly expensive, ineffective DSM programs.

Rate Base Premium

This mechanism allows a return over and above

the rate allowed on supply-side investments for

ratebased DSM expenditures. This is the most

straightforward approach applied by commissions. A utility is provided an incentive to invest

in DSM when it is granted an overall increase in

its return. Rates are maintained as with conventional regulation, except ratebased investment in

DSM has been included and a higher rate of return

has been allowed. It is also a strong penalty

mechanism when overall return is decreased due

to an absence of DSM investment. Although the

penalty is regarded as effective, this approach is

viewed by some as too liberal an incentive.

Hawaii, Idaho, Michigan New York, Texas, and

Washington have each instituted this incentive

(see table 6-3).

Incentive mechanisms approved in 1989 and

1990 in New York for seven utilities provide

bonuses of 5 to 20 percent of net savings from

DSM in addition to lost revenue adjustments,

although the incentive has been capped at an

amount equal to an additional 0.75 percent return

on equity. The Orange and Rockland Company,

a utility in New York, is operating under a

formula that determines rate of return based on

net savings in both dollars and kilowatt-hours

resulting from DSM. The utility has a goal of

cutting electricity consumption 8 to 10 percent. In

1990, the utility estimated that it would spend

$4.3 million on DSM, with avoided cost benefits

totaling $658,000. Orange and Rockland would

capture $45,000 in bonus the first year.45 The

New York Commission is reviewing the incentives to determine a way to develop a uniform

incentive for all New York utilities, primarily for

equity and greater administrative ease.46

Return-on-Equity Adjustment

This mechanism adjusts the allowed return on

equity to reward or penalize a utility based its

relative progress in developing DSM programs.

Under this approach, the penalty or bonus is only

applied to the return on the DSM portion of the

rate base, The reward is more in step with what is

considered appropriate, but a penalty could be

meaningless, Should a utility not pursue DSM,

the consequences would be minimal since the

portion of the rate base affected by the penalty

would be inconsequential. Like the first approach,

the cost-effectiveness of programs has not been

incorporated.

Connecticut, Hawaii, Kansas, Montana, and

Washington all have statutes permitting a bonus

return on DSM (see table 6-3). Washington’s

1980 statute allows ratebased DSM a return 200

M Ibid,, p. 8.23.

M NARUC, Incentjv,esjor Demand-side Management, supra note 25, pp. 177-178.

46 Job H. Chamberlain et al., supra note 43, p. 8.27.
138 I Energy Efficiency: Challenges and Opportunities for Electric Utilities

basis points above other utility investments.47

Connecticut’s 1988 statute authorizes an additional 1 to 5 percent rate of return on ratebased

DSM. In a 1990 order, Connecticut also implemented a variable bonus of 1 to 3 percent based

on program cost-effectiveness and a partial sales

adjustment mechanism.%

Bounty

Using a bounty mechanism, the utility is given

a predetermined payment for exceeding a set goal.

The goal can be in terms of estimated savings or

actual savings and the reward can be either

cents/kilowatt-hour or dollars/block of power

saved.49 It is similar to adjusting the rate of return

for performance, in that program success is the

critical factor. States adopting this approach

include Massachusetts, Michigan, Minnesota,

New Jersey, and Washington.

In Massachusetts, any savings above 50 percent performance is rewarded through a bonus on

each additional kilowatt and kilowatt-hour saved.50

Massachusetts Electric, for example, could receive $5.25 million in bonuses if it fully meets its

1990 DSM impact targets. Michigan is similar

except that it adds a sliding scale to the bonus.51

Shared Savings

This mechanism creates a sharing formula to

compensate a utility for some or all of the costs,

both direct and indirect, that result from a DSM

-program.

52 It gives the utility a share of benefits,

a predetermined percentage of calculated savings,

gained from DSM, rewarding it directly for

program success. Shared-savings arrangements

are best suited for retrofit and some new construction measures since those involve hardware with

a measurable energy value. It has frequently been

selected by both regulators and utilities.

However, the incentive requires a high degree

of regulatory supervision to monitor results. The

mechanism has three components: the cost of the

program, the amount of attributable energy savings, and avoided cost.53 Since the mechanism

works by allowing the utility to keep a portion of

the difference between the costs of the DSM

resources and avoided cost of an alternative

supply resource, quantifying is very important. A

total of 17 States, as shown in table 6-3, have

approved this incentive for their utilities. Examples of approved mechanisms follows:

9

9

■

In Rhode Island with a committee consisting

of utilities, commission staff, and governor’s

staff approved a plan that provides a bonus

based on shares of gross and net program

savings (5 and 10 percent respectively). The

bonus is earned after a savings threshold of

approximately 50 percent of program goals

has been achieved.54

An Iowa utility can earn up to 25 percent of

net benefits.55

Maryland permits a bonus of 5 percent of

savings if performance exceeds the program

goals by 10 percent.56

47 E~, state Regulatory Developments in Integrated Resource planning, supra note 7, P. 13.

48 EEI, DSMI~entive Regulation, supra note 28, p. 13.

49 David Moskovi@ supra note 19, p. 36.

W Michel Reid ~d Jo~ c~~~ ‘‘l%MQc~ Im.xntives for DSM Programs: A Review ~d fhd@S of -MdUUILSmS’ ACEEE

1990 Summer Study on Energy Eflciency in Bw”ldings, vol. 5 (Washington DC: American Council for an Energy-Efficient Economy, 1990),

pp. 5.161-5.162.

51 EEI, DSM Incentive Regulation, supra note 28, p. 16.

52 David Mo8kovi@ supra nOte 19, p. 30.

53 Ibid., pp. 3G34.

~ EEI, DSM Incentive Regulation, supra note 28, P. 17.

53 Ibid., p. 15.

56 Ibid., p, 15.
Chapter 6-State Energy Efficiency Initiatives I 139

California after experimenting with several

incentive mechanisms has decided that all of

its utilities will be eligible for a sharedsavings incentive.57

Vermont authorized a shared-savings bonus

that allows utilities to retain 10 percent of net

program savings.58

1 Penalties

Some States have coupled the performance

incentives with penalties for poor performance or

costly DSM programs. The risks of prudence

reviews and cost recovery disallowances have

traditionally been associated with investments in

supply-side investments. However, with growing

DSM expenditures, adequate results from investments are essential. The States that have paired

the penalty with the incentives are the ones with

full-fledged IRP plans. The penalties are associated with shared-savings programs, return-onequity adjustments, and megawatt savings targets.

The penalty associated with shared savings is

attached to failing to meet minimum performance

standards in California and Maine. California’s

major utilities are each subject to penalty. The

State utility commission granted Pacitic Gas and

Electric a shared-savings incentive conditional on

its meeting minimum performance standards. The

standard was set at a predetermineed level of net

present value of lifecycle benefits. If the minimum standards are not met, the utility pays a

penalty equal to 15 percent of the variance. For

San Diego Gas & Electric, the penalty is also

associated with the shared-savings incentive.

However, instead of the penalty being assessed on

net present value, the penalty is equal to the fill

total resource cost value of the gap. In 1991, the

penalty equaled 40 percent of the difference. In

addition to the performance standard there is also

a cost standard. If the utility exceeds its program

costs, set by a dollar/kilowatt-hour, it must pay 20

percent of the difference as a penalty .59

In New York and Michigan, the penalty is

assessed on the utility’s return on equity when

annual goals are not met. The New York commission assesses a return-on-equity-based penalty if

the utility fails to meet annual goals established

for DSM. In order for Consolidated Edison and

Orange and Rockland to avoid a set number of

percentage points downward adjustment, they

must achieve 40 percent of their energy savings

goals.60 The Michigan commission went a step

further. Consumer Power’s potential penalty is

greater than its potential reward and is based on

return on equity. If the utility does not meet the

minimum cost-effectiveness target, it is subject to

a 2 percent return-on-equity penalty, while if it

exceeds the target it will receive a 1 percent

return-on-equity reward. The commission stated:

Consumers (Power) is. . .a regulated monopoly with an obligation to meet its customers’

needs. The penalty for failure to meet this

obligation should therefore be greater than any

additional incentive for achieving the goal.61

The Washington commission has yet another

approach. Puget Power and Light must achieve a

minimum of 10 average megawatts saved. For

each megawatt not saved below that amount, the

utility will pay $1 million. If the utility fails to

capture 6 megawatts of savings the penalty is

even greater, $1.25 million per average megawatt

below 6 megawatts.62

57 Job H. chamtxrlin et al., supra note 43, p. 8.26.

58 EEufltcgrated Resource Planning in the Sfares, 1992 Sourcebook, Sttpra XWe 1, p. xvii.

w NAURC,Irtceruives for DSM, supra note 25, pp. 23-35.

60 ~ld., pp. 157, 177.

61 Ibid., p. 120.

‘2 Ibid., p. 232.
140 I Energy Efficiency: Challenges and Opportunities for Electric Utilities

Table 6-Hate Energy Research and Development Programs

Fund ing- Program focus use

State agency Established Type ($ OOOlyr) Source of fundsb

New York State Energy

Research and Development

Administration

California institute for

Energy Efficiency

California Energy Commission

Florida Solar Energy

Center

Iowa Energy Center

Kansas Electric Utility

Research Program

Minnesota Building Research

Center

North Carolina Alternative

Energy Corporation

Wisconsin Center for

Demand-Side Management

1975

1988

1985

1974

1991

1981

1987

1980

1990

State corporation 15,500 Utility surcharge

University 4,500 Utility Contributions

State 2,900 Utilit y surcharge

University 5,800 State, contracts

University 2,200C Utility surcharge

Nonprofit 600d Utility contributions

University 1,900 Stateoil overcharge

trust fund

Nonprofit 3,100 Utility contributions

Nonprofit 2,200e Utility contributions

Energy supply & end-use,

waste management research

and development (R&D)

Electric & gas end-use

efficiency R&D

Renewable and conservation technologies,

commmercialization

matching grants & loans

Solar, renewable, end-use

efficiency

Efficiency and renewable

R&D

Electricity supply and

end-use R&D

Building energy use efficiency and indoor air quality

Efficiency and renewables

R&D and outreach

R&D on DSM technologies

and program savings; market and consumer decisions

a Average annual expenditures, 1987-1991, including research planning and management but excluding project-level matching funds (excluded due

to varying accounting practices and treatment of in-kind matches, etc.).

b Except for Florida and Minnesota centers, which have substantial inhouse R&D acivities, ths organizations mainlysponsor research Contracts

with other entities.

c Projected for 1992, first full year of operation.

d Total annual expenditures, including 35 percent for end-use projects in FY 1990 and FY 1991.

SOURCE: Office of Technology Assessment, 1993, adapted from Jeffrey P. Harris, Arthur H. Rosenfeld, Cart Blumstein, and John P. Millhone,

“Creating Institutions for Energy Efficiency R&D: New Roles for States and Utilities,” In Proceedings of the ACEEE 7992 Summer Study on Energy

Efficiency in Buildings, vol. 6 (Washington, DC: American Council for an Energy-Efficient Economy, 1992), pp. 6.91-8.102.

These carrot-and-stick concepts of performance penalty and incentive measures are a recent

addition in the regulation of demand-side investments.

ENERGY EFFICIENCY RESEARCH AND

DEVELOPMENT PROGRAMS

In addition to regulations and statures, States

have also established programs that support

efficiency utility DSM programs and other energy

efficiency efforts through research and development. There are currently eight States with energy

research and development programs. Total spending by these programs has been $39 million

annually.63 Table 6-4 describes the characteristics

of the existing programs. These programs primarily focus on implementing new efficiency technologies. Box 6-E highlights aspects of State

programs.

63 Jefieyp. WS, Arthur H. Rosenfeld, Cad Blurnstein, and John wOne, ‘‘Creating Institutions for Energy Efficiency R&D: New Roles

for States and Utilities, ” ACEEE 1992 Summer Sfudy on Energy Eficiency in Buikiings, vol. 6 (Washington DC: American Council for an

Energy-Efficient Economy, 1992), p. 6.91.
Chapter 6-State Energy Efficiency Initiatives I 141

Box 6-E—Profiles of Selected State Energy Research and Development Programs

New York State Energy Research and Development Authority (NYSERDA): NYSERDA established in

1975, is one of the oldest State energy research arms. It is also one of the largest supporting a staff of around

80. There are four research programs: industrial efficiency, building systems, energy resources and municipal

wastes. The projects are aimed at improving energy effidency wlthin the State, adopting innovative technologies,

protecting the environment and promoting economic growth.

California Institute for Energy Efficiency (CIEE): The CIEE was created in 1988 as a statewide energy

research arm It primarily funds medium to long-term projects though the State university system and nonprofit

research centers including the national laboratories in the State. All projects must have an element of technology

transfer to be approved. The multiyear projects make up two-thirds of the budget and must include two or more

research centers. Current efforts inc!ude projects on building energy efficiency, potential for end-use efficiency to

improve air quality in urban areas, and end-use resource planning. Although none of the multiyear projects are

yet complete, progress reports note success. For example, a project on thermal performance and air leakage in

residential ducts has already developed new measurement methods, better techniques for quantifying overall

energy performance, and new approaches to improve duct initegrity in construction and retrofits.

Florida Solar Energy Center (FSEC): The FSEC’S original mission in 1974 was to conduct research,

education and performance certification of solar technologies, Since then, the mission has broadened to include

all renewable and energy-efficient technologies. Unlike may of the other State research centers, FSEC work is

primarily done in-house with a staffof 137. Research efforts include energy-efficient buildings, photovoltaics, solar

thermal systems, other advanced systems for renewable energy and end-use efficiency, field monitoring, and

education and training.

Wisconsin Center for Demand-Side Research (WCDSR): The WCDSR is an independent, nonprofit

organizatlon established in 1990. It sponsors and coordinates applied research in demand-side management. This

mission includes support for the development of demand-side technologies and markets, for the evaluation of utility

program effectiveness, for the improvement of the quality of available demand-side resource planning information,

and for support of university research.

SOURCE: Office of Technology Assessment, 1993, from Jeffrey P. Harris et al., “Creating institutions fur Energy Efficiency R&D: New Roles

for States and Utilities,” ACEEE 1992 Summer Study on Energy Efficiency in Buildings, vol. 6 (Washinglon, DC: Arnerican Council for an

Energy-Efficient Economy, 1992), pp. 6.91-6. 102.
— —

Federal

Programs 7

T

he Federal Government sponsors a wide range of

programs that support electric utility energy efficiency

initiatives. Most of the programs are concentrated in the

U.S. Department of Energy (DOE), however several

other Federal agencies, including the Environmental Protection

Agency (EPA), the Rural Electrification Administration (REA),

and the Tennessee Valley Authority (TVA), also administer

energy efficiency efforts. Federal programs include those that

directly encourage the development and adoption of utility

integrated resource planning (IRP) and demand-side management (DSM) efforts such as DOE’s Integrated Resource Planning

program and the initiatives of the Federal power marketing

administrations. Other programs with a more indirect contribution to utility energy savings include energy supply and demand

research and development (R&D) and technology transfer

activities, mandatory energy efficiency standards and labels, and

efforts to encourage voluntary adoption of energy efficiency

technologies. This chapter provides an overview of the more

notable Federal programs.

THE FEDERAL GOVERNMENT AND ENERGY EFFICIENCY

The strong Federal interest in energy efficiency arises from the

importance of reliable and economic electric power production

to the economy, concerns over the environmental impacts of

power production, and the Government diverse roles of

wholesale power producer, utility regulator, and utility customer.

The Federal mission for encouraging energy efficiency through

electric utilities is based on both legislative and executive

actions. Over the past two decades, Congress has passed a

number of laws that either directly or indirectly affect consumer

electricity demand or utility resource planning and operations.

I 143
144 I Energy Efficiency: Challenges and Opportunities for Electric Utilities

For example, electric utility involvement in

helping customers to save energy was given

impetus by the National Energy Conservation

Policy Act,l which required utilities to provide

information on energy conserving measures to

their residential customers and to offer energy

audits. The act also established Federal minimum

energy efficiency standards for appliances such as

refrigerators and fluorescent lamp ballasts, eventually contributing to lower electricity consumption per unit. Table 7-1 lists some of the major

legislation shaping Federal energy efficiency

programs and policies. The Energy Policy Act of

1992 builds on many of these existing programs,

for example, expanding Federal support for State

and utility energy efficiency efforts and extending

building and appliance energy efficiency standards. 2

On the executive side, President Bush’s 1991

National Energy Strategy (NES) embraced energy efficiency as a key resource in meeting future

energy needs. The NES set forth two goals for

Federal programs related to electricity generation

and use: to “encourage efficiency and flexibility

in electricity supply and demand choices, ” and to

“promote diversity of electricity technology and

fuel choices. ”3

It listed a variety of policy

initiatives to achieve those goals. Among them

were DOE-led efforts to support reform of Federal and State utility regulation to encourage

wider use of IRP and DSM and an expanded

commitment to R&D on improved methodologies

for measurement and evaluation of IRP and DSM

efforts. In other areas, Federal R&D and demonstration activities designed to improve the reliability of electrotechnologies and the costeffectiveness of energy resources, including renewable energy technologies, could contribute to

improved efficiency of electricity use and production.4

Federal support for energy efficiency R&D (as

identified in the NES) is shown in table 7-2. Out

of total funding of some $1.2 billion requested in

FY 1993, only about $6 million was allocated to

direct support for electric utility energy efficiency

initiatives. Some indirect contributions to utility

energy efficiency efforts may flow from the

roughly $150 million in consumer energy efficiency under building energy R&D programs and

from the hundreds of millions of dollars expended

for R&D in fossil, nuclear, and renewable energy

power generation.

The Clinton Administration has also given

energy efficiency a high priority and has proposed

increased spending on several Federal energy

efficiency programs as part of its economic

stimulus plan and budget requests

US. DEPARTMENT OF ENERGY

PROGRAMS

DOE’s responsibility for formulating national

energy policy and implementing energy conservation and efficiency programs make it the lead

Federal agency in promoting energy conservation

1 Pubiic Law 95-619, as amended, sec. 215, 42 U.S.C, 8216.

2 Public hW 102-486, 102 Stat. 2776, Oct. 24, 1992.

J National Energy Strategy: Powerjid Ideas for America, First Edition 1991/1992 (Washington DC: U.S. Government Printing Ofllce,

February 1991), p. 31.

4 Ibid.

s The proposal calls for an additional $188 million in FY 1993 for DOE broad-based energy conservation programs including $47 million

for the low-income weatherization assistance, and $19 million for model projects for commercializing building energy conservation

technologies. The proposal would also allocate $14 million to improved energy efficiency in Federal Gov ernment facilities and $23 million

for EPA’s “Green Lights” program which encourages voluntary installation of energy efficient lighting. Steve Daniels and Steve Gormaq

“Emergency Supplemental Appropriations Act of 1993-HR ?,” Energy andEnvironmental Study Conference Weekly Bulletin, Mar. 15,1993,

pp. A6-7.
..— ..— .— -.

Chapter 7–Federal Programs I 145

Table 7-l-Selected Federal Legislation: Energy Efficiency and Electric Utilities

Legislation Efficiency-Relatad Provisions

Energy Policy a nd Conservat ion Act (Public Law

94-163, December 22, 1975, 89 Stat. 870, 42

U.S.C. 6201 et seq., as amended)

Energy Conservation and Production Act (Public

Law 94-385, August 14, 1976, 90 Stat. 1125, 42

U.S.C. 6801 et seq., as amended)

National Energy Extension Service Act (Public

Law 95-39, Title V, June 3, 1977, 91 Stat. 191, 42

U.S.C. 7001 et seq., as amended)

National Energy Conservation Policy Act (Public

Law 95-619, November 9, 1978, 92 Stat. 3206, 42

U.S.C. 8201 et seq. and elsewhere, as amended)

Powerplant and Industrial Fuel Use Act of 1978

(Public Law 95-620, November 9, 1978, 92 Stat.

3289, 42 U.S.C. 8340, as amended)

Public Utility Regulatory Policies Act of 1978

(Public Law 95-617, November 9, 1978, 92 Stat.

3117, 42 U. S. C.2601 et seq. and elsewhere, as

amended)

Energy Security

June 30, 1980, 94

Act 1980 (Public Law 96-294,

Stat. 611 )

Pacific Northwest Electric Power Planning and

Conservation Act of 1980 (Public Law 96-501,

December 5.1980, 94 Stat. 2697.16 U.S.C. 839)

Requires energy use labels for new appliances.

Requires appliance energy efficiency standards (later made mandatory).

Establishes State Energy Conservation Program.

Provides Federal technical and financial assistance for development

and implementation of State energy conservation plans.

Establishes Weatherization Assistance Program to fund retrofits for

low-income households.

Required mandatory building energy efficiency standards for all new

buildings (later made voluntary for nonfederal buildings).

DOE to support innovative electric utility rate design initiatives and

demonstrations to encourage energy conservation.

At State request, authorizes DOE to intervene or participate in State

ratemaking proceedings.

Provides financial assistance for State consumer services offices to

participate in State regulatory hearings.

Establishes Energy Extension Service to fund State and local energy

information, training, and demonstration programs.

Establishes Residential Conservation Service and institutional Conservation Program.

DOE to approve State plans requiring regulated utilities to implement

residential energy conservation programs offering audits, information,

and financing.

Extends residential mortgage credit for energy conservation and solar

energy improvements through Federal housing finance programs.

Imposed restrictions on use of natural gas and oil as primary fuels in

existing and new powerplants (most provisions later repealed).

Amends Federal Power Act to require State public utility commissions

to consider adopting various energy conservation and ratemaking

standards.

Amends Energy Conservation and Production Act to provide Federal

grants to States to carry out new requirements.

Requires utilities to interconnect with and purchase power from

qualifying small power producers and cogeneration facilities.

Amends National Energy Conservation and Production Act residential

conservation programs to require warranties for conservation measures, cap audit fees at$15, and limit utility installation of conservation

measures.

Establishes DOE residential energy efficiency demonstration program.

Establishes Commercial and Apartment Conservation Service (CACS).

Establishes the Pacific Northwest Power Planning Council to develop

regional conservation and electric power plans to guide BPA resource

acquisition.

(Continued on next page)
146 I Energy Efficiency: Challenges and Opportunities for Electric Utilities

Table 7-l-Selected Federal Legislation: Energy Efficiency and Electric Utilities+Continued)

Omnibus Budget Reconciliation Act (Public Law

97-35, August 3, 1981,95 Stat. 357)

Hoover Power Plant Act of 1984 (Public Law 98-381,

August 17,1984,38 Stat. 1333,43 U.S.C. 7275 et seq.,

as amended)

Conservation Service Reform Act of 1986 (Public

Law 99-412, August 28, 1986, 100 Stat. 932)

Powerplant and Industrial Fuel Use Act of 1978,

Amendments (Public Law

Stat. 310)

00-42, May 21, 1978, 101

National Appliance Energy Conservation Act of

1987 (Public Law 100-12, March 17, 1987, 101 Stat.

103)

Renewable Energy and Energy Efflciency Technology Competitiveness Act of 1989 (Public Law 101-

218, December 11, 1989, 103 Stat. 1859, 42 U.S.C.

12001-1 2007)

Authorizes BPA to acquire new energy resources consistent with

the regional plan and to encourage cost effective energy conservation and renewable energy resources.

Gives priority to conservation and renewable energy sources in

BPA resource plans.

Requires Council and BPA to collaborate on and implement a fish

and wildlife protection plan.

Amends the Powerplant and Industrial Fuel Use Act to allow DOE

to ban the use of oil or natural gas in new powerplants where

alternatives exist.

Requires electric utilities using natural gas as a primary source to

implement a conservation plan that will reduce at least 10 percent

of electricity consumption attributable to natural gas over 5 years.

Creates the imw-income Home Energy Assistance Program

(LIHEAP).

Makes building energy performance standards voluntary for nonfederal buildings under the Energy Conservation and Production

Act.

Requires Western Area Power Administration long-term firm power

service contracts to require customers to develop and implement

energy conservation programs.

Amends National Energy Conservation Policy Act.

Reforms the Residential Conservation Service and extends its

expiration to 1989.

Eliminates requirement that utilities arrange for conservation measures installation and related loans.

Allows States to develop alternative conservation plan for residential buildings.

Abolishes the Commercial and Apartment Conservation Service.

Repeals and amends certain sections of the 1978 Act restricting

utility use of oil and natural gas.

Requires that no new electric powerplant may be constructed or

operated as a base load powerplant without the capability to use

coal or other alternative to petroleum as a primary energy source,

unless it receives an exemption.

In absence of DOE implementation, establishes mandatory minimum energy efficiency standards under Energy Policy and Conservation Act and requires DOE to update standards periodically.

Adds additional appliance categories for which standards must be

developed.

Directs DOE to participate in cost share joint venture demonstrations of renewable energy and advanced district cooling technologies.

Establishes cost and performance goals for Federal wind, photovoltaic, and solar thermal research programs.

SOURCE: Office of Technology Assessment, 1993.
—..

Chapter 7–Federal Programs I 147

Table 7-2—National Energy Strategy Funding Levels for Energy Research and Development

Fiscal Years 1991-93 ($ millions)

FY 1991 FY 1992 FY 1993 FY 1991-93

Research area actual enacted requested percent change

Surface transportation efficiency

Transportation materials development. . . . . . . .

Heat engine development. . . . . . . . . . . . . . . . . . .

Electric and hybrid propulsion. . . . . . . . . . . . . . .

Other transportation efficiency. . . . . . . . . . . . . . .

Intelligent vehicle-highway systems. . . . . . . . . . .

High-speed rail, maglev. . . . . . . . . . . . . . . . . . . .

High-performance communications. . . . . . . . . . .

Total. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Air transportation efficiency. . . . . . . . . . . . . . . . .

Energy-efficient aeronautics. . . . . . . . . . . . . . . . .

Air traffic control systems. . . . . . . . . . . . . . . . . . .

Total. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

New transportation fuels. . . . . . . . . . . . . . . . . . . .

Alternative fuels utilization. . . . . . . . . . . . . . . . . . .

Fuels from biomass. . . . . . . . . . . . . . . . . . . . . . . .

Advanced oil recovery. . . . . . . . . . . . . . . . . . . . . .

Natural gasa. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Total. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Efficiency In buildings and Industry

Integrated resource planning. . . . . . . . . . . . . . . .

Industry efficiency. . . . . . . . . . . . . . . . . . . . . . . . .

Alternate industry feedstocks. . . . . . . . . . . . . . . .

Buildings energy technologies. . . . . . . . . . . . . . .

Total. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Advanced electric technology

Municipal solid waste. . . . . . . . . . . . . . . . . . . . . . .

Cogeneration. . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Photovoltaics. . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Other solar and renewable. ... , . . . . . . . . . . . .

Superconductivity. . . . . . . . . . . . . . . . . . . . . . . . .

Advanced light-water reactors. . . . . . . . . . . . . . .

Advanced reactor concepts. . . . . . . . . . . . . . . . . .

Advanced reactor facilities. . . . . . . . . . . . . . . . . .

Total. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Grand total. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Total DOE.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

$21,6

15.8

25.0

7.6

23.0

12.0

58.0

$163.0

$51.6

35.0

$86.6

$13.6

28.7

31.7

15.9

$89.9

$ 3.0

78.9

0.3

44.9

$127.1

$ 0.0

4.1

46.4

103.4

18.6

44.3

61.3

91.1

$369.2

$835.8

$660.2

$23.5

16.8

42.9

9.6

27.5

20.0

92.0

$232.3

$63.0

32.0

$95.0

$ 17.4

34.8

36.9

12.6

$101.7

$ 3.9

92.2

0.5

49.4

$146.0

$ 1.6

3.2

60.4

123.0

22.0

62.5

59.5

97.8

$ 430.0

$1,005.0

$ 782.5

$26.4

17.5

75.3

11.5

37.5

28,0

123.0

$319.2

$68.0

46.0

$114.0

$31.7

46.4

46.5

40.0

$164.6

$ 6.0

95.7

2.0

54.5

$158.2

$ 4.0

3.5

63.5

113,6

22.5

58.7

50.0

95,1

$ 410.9

$1,166.9

$ 878.4

22.20/0

10,8

201.2

51.6

63.0

133.3

112.1

95.8%

31 .8%

31.4

31.670

133.1 %

61.7

46.7

151.6

83.1 %

1 00.0%

21.3

566.7

21.4

24.50/.

NA

-14.6%

36.9

9.8

21.0

32.5

-18.4

4.4

11.370

39.60/0

33.1%

a Includes only funding contained within the Fossil Energy appropriation.

SOURCE: Office of Technology Assessment, 1993, based on data from U.S. Department of Energy, “National Energy Strategy: Powerful ideas for

America: One Year Later,” DOE/S--92008000, February 1992, p. 5.
148 I Energy Efficiency: Challenges and Opportunities for Electric Utilities

at electric utilities.6 The primary DOE programs

involving electric utilities are under the 0ffice of

the Assistant Secretary for Energy Efficiency and

Renewable Energy (formerly Conservation and

Renewable Energy). The R&D and technology

transfer efforts of the Office of Fossil Energy, the

Clean Coal Technology Program, and the Office

of Nuclear Energy, also offer some benefits for

increasing the energy efficiency, cost-effectiveness, and environmental compatibility of utility

power generation options.

Federal support for energy conservation and

efficiency has varied significantly, usually reflecting shifting political priorities. From FY

1980 to 1990, appropriations for DOE conservation R&D, where much of the utility-related

energy efficiency R&D is focused, fell by more

than half. The Bush Administration and Congress

reversed that trend, but in real terms, DOE’s

conservation R&D budget in FY 1991 was only

60 percent of what it had been in FY 1980.

In FY 1992, DOE budgeted an estimated $426

million on programs that the General Accounting

Office (GAO) identified as promoting conservation and efficiency in the use of electricity and

other forms of energy.7 While marking an increase over prior years, this budget level was only

11 percent of the $3.8 billion in funds allocated to

energy supply technology R&D. Adjusted for

inflation, DOE’s FY 1992 conservation R&D

budget was some 18 percent lower than in 1980.8

Moreover, within the conservation R&D programs, the emphasis has shifted fro buildings

and utility systems technologies to transportation

and renewable energy technologies and to longerterm, high-risk research on industrial processes

and materials, and superconducting materials.9

Determining g what portion of Federal spending

actually supports electric utility energy efficiency

initiatives or technology development is not easy.

DOE programs have multiple goals, and improving energy efficiency is often a minor objective of

DOE energy supply and demand technology

programs. According to a GAO analysis, DOE’s

FY 1993 budget request to Congress reflected

some $2.1 billion in civilian R&D identified by

DOE as supporting the NES objective of “improving electric efficiency.”l0 A more detailed

breakout of the proposed spending showed $1.2

billion related to various DOE civilian nuclear

programs (including light water reactors, highefficiency and ultrahigh-efficiency power systems, fusion energy, first repository, monitored

retrievable storage facility, and nuclear facilities).

The Clean Coal program and renewable energy

systems accounted for an additional $644 million.

Altogether, demand-side efficiency programs (including $50 million for unspecified ‘‘utility

demand efficiency,” $26 million for industrial

programs, and $27 million for buildings efficiency programs) made up less than 0.5 percent of

the budget request for electric efficiency R&D.

6 The Department of Energy Organization Act of 1977, 42 U.S.C. 7131 et seq., consolidated the energy functions of a number of ageneies

under a single department. DOE absorbed the Energy Research and Development Administration the Federal Energy Administ.ratioq the

Federal power administrations, the power marketing fimctions of the Department of the Interior, as well as some functions of other agencies.

A new independent agency established within DOE, the Federal Energy Regulatory Commissiom took over the responsibilities of the Federal

Power Coremission and the oil pipeline regulatory functions of the Interstate Commerce Commission.

7 The GAO estimate excluded transportation sector efficiency programs, but did include DOE’s ccmserv ation grant programs paid for by

Petroleum Overcharge funds. General Accounting Office, ‘ ‘DOE’s Efforts to Promote Conservation and Efficiency,” GAO/RCED-92-103,

Aprd 1992, pp. 2-3.

8 Ibid.

9 For more on the fate of DOE energy conservation R&D, see U.S. Congress, OffIce of lkchnology Assessmen4Buikfing Energy Efficiency,

OTA-E-518 (Washington, DC: U.S. Govemment Printing Office, May 1992), pp. 104-107 (hereafter referred to as OTA, Bw”ldi”ng Energy

Efficiency). See also, Fred J. Sissinc, Congressional Research Service, “Energy Conserv at.ion: ‘Rd.nieal Efficiency and Program

Effectiveness,” CRS Issue Brief 85130, April 1991.

10 Gen~~ Accounting ~lce, “Energy R&D: DOE’s prioritization and Budgeting Process for Renewable Energy ResearclL”

GAO/RcED-92-155, April 1992, pp. 13-16.
Chapter 7–Federal Programs I 149

r

I

I

I Power

Administratlons

4 ‘--- ‘

-- “

-

Alaska

k—-

~ Southeastern

-i Southwestern .—

~ Bonneville

I 1--- ----------

‘- { Western Area .———— ——— ——

Figure 7-l-Organization Chart of DOE’s Assistant Secretary for

Energy Efficiency and Renewable Energy

AAssistant Secretary

I Principal Deputy

Office of

Management and

Resources

I

Off Ice of

I

Alcohol Fuels

L-—

1

-[ -

---r---:

Off Ice of

Utillty

L

Technologies

Office of

Industrial

Technologies

—

Integrated

Resource

Planning

Program

I Office of

-1 Waste

L

Reduction

Technologies

-LOffice of

Renewable

Energy

Conversion

~–

Off Ice of )

- Solar Energy

1

Conversion

~–—–

I Office of

-1

:

Energy

Management

I

,-- --

I

Y

Off Ice of

Industria l

Processes

L -- —— – – — J

Assessment J

T— ‘-—-- -

‘-1

J

Off Ice of

I Transportation

Technologies

I Off Ice of

+ Propulsion

I

~---- 1

I Office of

-–1 Alternate

Fuels

Off Ice of

.— Advanced

Transportation

~ Materials —.

I

office of

Building

Technologies

I

OffIce of

Buildings

Energy

Research

-i

Off Ice of

Codes and

Standards

L –-

.— . .

Off Ice of

Federal

Energy

Management

~-. .~

Off Ice of

r

Technical and

Financial

Assistance

LrOff Ice of

National

J!!!a:s–

—.

Off Ice of

— Grants

Management

—

——— . — ..——

~ Off Ice of

,—.

1. ----- -

Technical

Assistance

—-

1 Regional

~ support L--- OffIces

--

SOURCE: Office of Technology Assessment, 1993, adapted from information provided by the U.S. Department of Energy, April 1993.

E Office of Energy Efficiency and operations of the five Federal power marketing

Renewable Energy agencies and Federal technical and financial

assistance programs.

11 As shown in figure 7-1, the

The Office of the Assistant Secretary for

Energy Efficiency and Renewable Energy man- major program offices are organized by end-use

ages R&D and technology transfer programs for sectors: Utility, Buildings, Industrial, and Transrenewable energy technologies, end-use energy portation Technologies, plus Technical and Fiefficiency, and utility systems. It also oversees the nancial Assistance.

11 Office of Federal Register, United Stares Government Manual, 1991/92 (Washington DC: U.S. Government Printing Office, July 1991)

pp. 279-280. Hereafter referred to as U.S. Government Manual, 1991/92.
150 / Energy Efficiency: Challenges and Opportunities for Electric Utilities

Table 7-3-Program Funding for DOE Office of

Utility Technologies, FY 1992

Appropriations

Programs: ($millions)

Office of Solar Energy Conversion . . . . . . . . .

Solar thermal. . . . . . . . . . . . . . . . . . . . . . . . . .

Biomass power. . . . . . . . . . . . . . . . . . . . . . . .

Photovoltaics. . . . . . . . . . . . . . . . . . . . . . . . . .

Resource assessment. . . . . . . . . . . . . . . . . . . . .

Integrated Resource Plannlng. . . . . . . . . . . . .

Off Ice of Energy Management . . . . . . . . . . . . .

Transmission and distrlbutlon. . . . . . . . . . . . .

Health effects of electrlc and magnetic fields.

Energy storage. . . . . . . . . . . . . . . . . . . . . . . .

High-temperature superconductivit y. . . . . . . .

Hydrogen fuels. . . . . . . . . . . . . . . . . . . . . . . . .

District heating and cooling. . . . . . . . . . . . . . .

Office of Renewable Energy Conversion. . . .

Wind.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Hydroelectric. . . . . . . . . . . . . . . . . . . . . . . . . . .

Geothermal. . . . . . . . . . . . . . . . . . . . . . . . . . . .

Ocean. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

86.7

21.1

4.4

60.4

1.2

4.0

37.7

3.1

5.0

5.4

22.0

1.4

0.8

50.6

21.4

1.0

26.2

2.0

SOURCE: Office of Technology Assessment, 1993, based on data

from U.S. Department of Energy, Assistant Secretary for Conservation

and Renewable Energy, “Conservation and Renewable Energy Tech

nologies for Utilities,” DOE/CH10093-865 (prepared by the National

Renewable Energy Laboratory, Golden, CO), April 1992, p. 5.

The Office of Utility Technologies a dministers

programs dealing with utility systems, IRP, DSM,

and renewable energy technologies R&D. Other

programs also fund activities that can contribute

to utility energy efficiency efforts. The Office of

Buildings Technologies and the Office of Industrial Technologies direct programs that are designed to improve the energy efficiency of

building and industrial systems and related processes primarily through support of R&D and

information projects. The 0ffice of Technical and

Financial Assistance promotes the use of renewable energy and energy-efficient technologies and

practices through technology transfer, grants,

cooperative activities with State and local governments and private and nonprofit organizations.

Office of Utility Technologies

The Office of Utility Technologies, created in

the FY 1990 DOE restructuring, manages various

programs to encourage the development and

adoption of cost-effective energy efficiency and

renewable energy technologies (see table 7-3).12

The office has four utility-related research, development, demonstration, and technology transfer

programs:

The Integrated Resource Planning Program,

which deals with all aspects of utility planning and operations;

The Office of Solar Energy Conversion,

which promotes the development and adoption of solar thermal, photovoltaic, and

biomass energy technologies;

The Office of Renewable Energy Conversion, which promotes wind, hydroelectric,

geothermal, and ocean energy systems; and

The Office of Energy Management, which

manages research to improve the efficiency

and reliability of electricity delivery and

storage systems.

of the foregoing programs share the broad

goals of ensuring that energy conservation and

DSM programs are considered equally with new

sources of supply, reducing institutional constraints deterring adoption of energy efficiency

and renewable energy technologies, and expanding cooperative efforts with utilities and private

industry to realize the large market potential of

these energy resources.13

Integrated Resource Planning Program

The IRP Program was established to encourage

the development and implementation of IRP

processes to ensure that cost-effective energy

12 U.S. wp~ent of Energy, Assistant Secretary for Conservation and Renewable EnerW, “Conservation and Renewable Energy

Tbclmclogies for Utilities,” DOIVCH1OO93-86 (prepared by the National Renewable Energy Laboratory, Goldeq CO), April 1992, p. 1,

Hereafter referred to as DOE, “Conservation and Renewable Energy lkchnologies for Utilities. ”

13 Ibid., p. 4.
Chapter 7–Federal Programs I 151

conservation and DSM programs are considered

equally with new sources of supply .14 The IRP

Program encourages utilities and State regulators

to use resource planning and regulatory approaches that emphasize electricity conservation

and efficiency.

The IRP Program has evolved from the LeastCost utility Planning Program (LCUP), established in 1986 in response to congressional

directives. The LCUP Program was setup to aid

the adoption of least-cost planning through technology transfer to utilities, regulators, consumers,

and government agencies. 15 The current structure

of the IRP Program has gradually evolved over

the past 8 years to support three activity areas:

E Planning Processes--developing methods

that will integrate regulatory and DSM

programs into utility planning;

■ Demand-Side Management—working to ease

adoption of DSM by utilities; and

■ Regulatory Analysis--examining the economic regulatory environment and its barriers to demand-side investment.

The IRP Program has a very small staff (2

full-time equivalents in FY 1993), and thus, little

institutional presence; its program efforts focus

on channeling Federal funds for technical assistance and information transfer to State regulators

and utilities. Program activities are primarily

carried out through arrangements with several

national laboratories to direct research, to manage

grant applications and awards for cooperative

research efforts and other cost-shared research.l6

The IRP Program has underwritten various conferences, workshops, publications, and training

programs on IRP and DSM in collaboration with

the National Association of Regulatory Utility

Commissioners, the Edison Electric Institute, the

Electric Power Research Institute, and similar

organizations. The program has funded work

evaluating and measuring utility DSM energy

savings and the reliability of energy-efficient

technologies. The program also is supporting

development of analytical tools and methods for

comparing the costs and benefits of various

energy production and consumption options,

including methods for incorporating total fuelcycle analysis and consideration of environmental, social, and other external costs in utility

resource plannin g. In recent years, the program

has underwritten efforts to expand the application

of IRP and DSM concepts to local gas distribution

utilities. Table 7-4 shows selected projects supported in FY 1991. The program continues to

support similar efforts today. According to IRP

program representatives, requested budget increases will be passed through to support expanded activities through national laboratory

programs and perhaps some additional direct

research contracts.

Among its most successful early efforts according to program officials were the creation of

organizations that have continued, independently

of DOE funding, to promote LCP objectives. One

of these projects, NORDAX, a regional utilitysponsored DSM data exchange is discussed in

box 7-A.

For most of its history, the IRP Program has

had an annual budget of some $1 million, rising

to $3 million for FY 1992-93, as shown in figure

7-2. With this modest budget, DOE has defined its

role as the gatherer and disseminator of information. DOE requested a 50 percent increase for the

IRP program for FY 1993 for a total of $6 million

to fund additional research and information activities. Actual funds received in FY 1993 were $4.9

14 L~& Berry and MC H@ Recent Accomplishments of the U.S. DOE Least-Cost Utility Program, ORNLXON-288 (Oak Mdge, TN:

Oak Ridge National Laboratory, August 1989) p. 5.

IS Hean”ng on bast cost utility Planning before the Subcommittee on Energy Development and Applications of tie HOUSC COmmitt~ on

Science and ‘Ikdnology, 99th Congress, 1st sess., Sept. 26, 1985.

1A me major raipien~ of IRP progr~ funds are the Oak Ridge National Laboratory irl Tmnessee; the Lawrence Berkeley ~boratory iII

California, and the National Renewable Energy Laboratory in Colorado.

330-075 : QL 30- 93 - 6
152 I Energy Efficiency: Challenges and Opportunities for Electric Utilities

Table 7-4-Recipients, Research Topics, and Funding of

DOE Integrated Resource Planning Program Projects, FY 1991

Lawrence Berkeley Laboratory

Gas Integrated Resource Planning (IRP) ($180,000)

Evaluation of Financial Incentives to Utilities ($100,000)

Transmission Issues in IRP ($75,000)

Environmental Externalities and IRP ($125,000)

Analysls of Fuel Price Risk In All Source Bidding ($450,000)

Competitive Bidding for Demand-Side Resources ($80,000)

Integrated Resource Bidding in New York ($60,000)

Database on Energy Efficiency Programs ($50,000)

End-Use Resource Planning: Transferability of End-Use Load Shape Data ($25,000)

Technical Assistance to National Association of Regulatory Utility Commissioners, Commissions, Utilities, and DOE ($80,000)

Technical Assistance to Power Marketing Agencies (n/a)

Technical Potential for Efficiency improvements in the Residential and Commercial Sectors (n/a)

Advanced IRP Seminar ($50,000)

Oak Ridge National Laboratory

Fundamentals of Electrlc-Utility IRP (n/a)

Analytical Foundation for Demand-Side Management (DSM) Programs (n/a)

DSM Planning Processes (n/a)

Analysis of the Role of DSM as a Resource (n/a)

DSM Collaboratives (n/a)

National Renewable Energy Laboratory

Renewable Energy and IRP Strategy ($25,000)

Renewable Energy Profiles ($40,000)

Technical Assistance to National Association of Regulatory Utility Commissioners ($30,000)

State Renewable Energy Policies and Incentives ($55,000)

Utility Fuel-Cycle Analysis Requirements Review ($30,000)

Net Energy Analysis Study ($25,000)

Center for Clean Air Policy Analysis and Dialogue on Global Warming and Energy Policy ($85,000)

Scoping Study of Renewable Energy-Related Utility Modeling Issues ($30,000)

Scoping Study of IRP Needs in the Public Utility Sector ($25,000)

IRP Definitional Study ($25,000)

DSM Pocket Guides ($38,000)

Compendium of Total Fuel-Cycle Studies for Use in IRP Processes ($5,000)

Residential technologies

Commercial technologies

Agricultural technologies

industrial technologies

Renewable resource technologies IRP ($198,000)

Bangor Hydro-Electric

Development of a Market Implementation Strategy for Water and Space Heating Technologies (n/a)

Burlington Electric Department

Small Utility Approach to DSM (n/a)

Central Vermont Public Service Corp.

innovative Approaches to Commercial Lighting for Rural Electric Customers (n/a)

Fitchburg Gas and Electric Light Co.

Small Commercial Lighting Program (n/a)
—

Chapter 7–Federal Programs I 153

Massachusetts Municipal Wholesale Electric Co.

Electric Thermal Storage Lease/Loan Program for Residential and Small Commercial Customers (n/a)

Niagara Mohawk Power Corp., NY State Electric& Gas, Rochester Gas & Electric

Assessment of New York State Farmstead DSM (n/a)

Northeast Utilities

Evaluation of the Effectiveness of a Low-Income Weatherization Program for Rural Customers (n/a)

Washington Electric Cooperative, VT

Integrated Demand Control Project for Small Rural Utilities (n/a)

KEY: n/a - funding level not published.

SOURCE: Office of Technology Assessment, 1993, based on data from the U.S. Department of Energy, Integrated Resource Planning Program,

“Volume 1: IRP Program Reviews and Catalogue of Projects,” 1991.

million. The budget request for FY 1994 is $6.8

million.17

Although the program is small (two full-time

staff members) and expenditure levels practically

invisible within the overall DOE budget, DOE,

nevertheless, has projected significant energy

savings from its investment. DOE has projected

that in the next 10 years, the program will

contribute up to 30,000 MW reduction in otherwise necessary supply options. (The estimates

assume that adoption of IRP will spur utilities to

greater investments in more efficient generating

technologies and expanded electricity savings

from utility DSM programs.) In the longer run,

according to DOE, this could amount to 80,000

MW, with over 4 quads of primary energy saved

annually. 18 DOE’S announced program goal

1992 was to increase the number of States with

comprehensive IRP from 15 to 40 by the year

2000. 19 DOE was silent on the mechanisms for

accomplishing its IRP implementation goals. As

noted in chapter 6 of this report, State progress in

adopting and implementing IRP requirements for

their jurisdictional utilities has been accelerating,

even in the absence of expansive Federal programs or Federal regulatory requirements. OTA

estimates that more than 30 States have established IRP policies (see ch. 6).

Evaluation of the effectiveness of the IRP

Program has been limited. A 1989 review by Oak

Ridge National Laboratory (funded by the IRP

Program), detailed the activities completed, and

concluded that at the time the program was:

. . playing a small but effective role in ensuring

that the large potential of integrated utility

planning is realized DOE’s role has been primarily catalytic, providing the motivation for other

organizations to join in cost-sharing and informationsharing projects. DOE’s participation in these

projects helps to publicize and legitimize the

ideas of integrated planning and aids the technology transfer processes among utilities, commissions, and other interested groups.20

No formal evaluation has been done since. DOE

continues to view its role primarily as publicizing

and legitimizing IRP and DSM concepts.

Given the modest amounts devoted to the

program and the lack of alternative sources of

17 Diane pfi~y, -~, DSM progrws, C)ffke of Utility lkchnologies, U.S. Department of En-, persod co-ti~o~ Apr. 8,

1993.

18 U.S. Dep~ent of Energy, FY 1992 Congressional Budget Request, vol. 4, DOE/CR-0001, February 1991, p. 438. Her4ter refem~

to as DOE, FY 1992 Congressional Budget Request, vol. 4,

19 ~~ony of j. Micbel Davis, &jSiS~t Swe-, Conservation~d Renew~le Energy, U.S. Dq~ent of Energy, Hearings on ~

1993 Department of Energy Appropriations before the Subcommittee on Interior and Related Agencies of the House Committee on

Appropriations, 102d Cong., 2d sess., Apr. 8, 1992, p. 5,

m Linda Berry and Eric Hirst, supra IIOk 14, p. 1.
154 I Energy Efficiency: Challenges and Opportunities for Electric Utilities

Box 7-A--NORDAX: Sharing Utility DSM Experiences

NORDAX, the NortheastRegion DSM Data Exchange, is a cooperative projectsponsored by a kgroup of some

20 utilities in the northeastern United States and Canada. NORDAX is an example of DOE's institution building

efforts. The Least-Cost Utility Planning Program (LCUP) provided money for development of a high quality

DSM database and establishment of a regional organization to maintain and update the database. Participants

in developing NORDAX included all of New York State's utilities, a number of othernortheastern utilities, the New

York Public Service Commission, State and city energy agencies, the Edison Electric lnstitut,the Electric Power

Research Institute, the Alliance to Save Energy, several national laboratories, and DOE’S LCUP program

NORDAX was incorporated as a nonprofit corporation in May 1989 to carry on the project and operates

independent of DOE funds.

Development of the NORDAX data base required establishing standards for collecting and presenting data 

on actual DSM program experiences, technologies, and costs that allow utilities to exchange data for DSM

programs and resource planning. The NORDAX database, created in 1988, provides comprehensive information

on over 90 DSM programs from participating utilities plus detailed data on other utility systemcharacterostocs, such

as demographics, load and weather. The data is organized to assist utlilties compare and select future programs

with abetter idea of their costs, market penetration, and load imparct.

From DOE’s perspective, the NORDAX project helped toaddress the need for improved information on DSM

technologies and programs. TheNORDAX experience will contribute to better methods for developinganddtahg

DSM data to improve program effectiveness and to help incorporate real world load impacts and costs of DSM

programs in IRP models. NORDAX also presents an organizational model fordevelopment of a regional DSM

database that potentially could be replicated in other regions.

SOURCE: Office of Technology Assessment, 1993, based on Berry Linda and Eric Hirst, Recent tAccomplishments of the U.S. Department

of Energy's Least-Cost Utility Planning Program, ORNL/CON--288 (Oak Ridge, TN: Oak Ridge National Laboratory, August 1989), pp.

l5-18.

support, many of the program’s clients have been Federal funds and technical assistance are not

reluctant to criticize it. Nevertheless, anecdotal

information suggests that its emphasis on promotion of IRP and DSM as general concepts is

rapidly falling behind the needs of client State

regulators and utilities who are well advanced in

implementing IRP and DSM programs. With

growing reliance on IRP and DSM measures to

meet future customer demand reliably and at least

cost, the need increases for more sophisticated

planning and evaluation methodologies and independent analyses of the cost and performance of

various energy supply and demand-side efficiency options. With its current size and scope, it

seems unlikely that the IRP Program will be able

to provide institutional leadership or significant

financial contributions to overcoming these challenges.

the sole sources for financing or directing research and education efforts on IRP and DSM

methodologies. As utility involvement in these

programs has expanded, so too has the institutional expertise within the industry and the

regulatory community. The Electric Power Research Institute maintains active research and

information programs on utility planning methods, DSM programs and efficient end-use technologies. Professional and trade associations,

including such specialized groups as the Association of Demand-Side Management Professionals,

sponsor seminars, conferences, publications, and

other educational efforts. A plethora of consulting

firms offer analytical services to utilities and

regulators.
Solar and Renewable Energy Conversion

Research Programs

The bulk of the Office of Utility Technologies

annual budget is devoted to DOE-funded R&D to

accelerate the development, demonstration, and

commercialization of advanced renewable technologies for electric power generation. The major

potential benefits to utilities from these research

efforts are increased diversity in technology and

fuel choices, reduced costs and increased confidence in the performance of solar, wind, biomass,

hydro, and geothermal power technologies.21

DOE also supports activities that target institutional factors influencing potential markets for

and commercial deployment of renewable energy

technologies.

Renewable energy technologies offer several

significant benefits as part of utility resource

plans including opportunities to reduce the operating and maintenance costs and planning uncertainties. In particular, renewable power generation technologies have the advantages of reduced

fuel costs and fewer adverse environmental impacts on-site than fossil fuel alternatives.22 Another attractive feature is that renewable energy

generating technologies are available in small,

modular units offering utilities capacity additions

in smaller size increments and with shorter

construction lead times than more conventional

generators. 23

The Office of Solar Energy Conversion manages projects to encourage solar thermal, biomass, and photovoltaic technologies. The Office

of Renewable Energy Conversion oversees geothermal, wind, hydroelectric and ocean energy

technologies. Both offices support research aimed

at lowering the costs of renewable energy technologies in the mid- and long-term to make them

more competitive economically with conventional fossil energy resources, As part of market-

.

Chapter 7–Federal Programs I 155

Figure 7-2—Funding for Integrated Resource

Planning Program, FY 1990-93

- $milllons

7

6

5

4

3

2

1

0

m 199 0

m 199 1

Cl 199 2

~ 1993 request

r

1

DSM Regulatory

analysis

Planning Total

processes

Program activity

SOURCE: Office of Technology Assessment, 1993, based on data

from, U.S. Department of Energy, FY 1993, Congressional Budget

Request, vol. 4, January 1992, p. 468.

development for renewable energy technologies,

DOE is supporting resource assessments of U.S.

solar radiation and wind power potential and

participates in cooperative efforts to boost U.S.

renewable energy technology exports. Many renewable energy research projects are carried out

on a cost-shared basis with private industry. Box

7-B shows some of the recent research efforts

supported by these programs.

Office of Energy Management Programs

The Office of Energy Management supports

development of technologies to increase the

efficiency and reliability of energy transmission,

distribution, and storage and to increase the

flexibility, and safety of utility systems. The

Office administers research programs on transmission and distribution technologies, power

systems and materials, high-temperature superconductivity, energy storage technologies, and

21 us. Dep~ent of Ener~, DO~CR.()()()6, January 1992, pp. 17-23. Hereafter referred to as DOE, Fy ~ggs congressio~i~~g~

Request, vol. 2.

22 “Conservation and Renewable Energy lkchnologies for Utilities,” supra note 12, p. 5.

23 mid., ~ pp. 11-26.
156 I Energy Efficiency: Challenges and Opportunities for Electric Utilities

Box 7-B-Renewable Energy Technologies R&D Projects of DOE

DOE participates in a variety of cooperative, cost-shared research, development demonstration, and

teohnology transfer activitiesbencourage the expanded use of renewable energy technogies. These efforts by

the solar and renewable energy programs of the Office of UtilityTechnologies are directed at overcoming both the

technical and institutional constraints that have slowed market penetration by renewable energy technologies.

These programs also support activities designed to build the international competitiveness of the U.S. renewable

energy industry and establish technological leadership in the marketplaoe.

Renewable Energy Conversion Programs

The core of the Wind Energy Program is research on materials, components, devices, and systems to

increase power output and lower costs of wind energy systems. The program goal for the year 2000 is development

of wind pow systems that can compete economicaiiy with conventionai power systems by producing electricity

at a cost of $0.04/kWh (in 1990 dollars) in moderate wind speeds. The program is emphasizing cost-shared

development of utility-scale advanced wind turbines and working to resolve critical reliability and performance

issues by examining wind/airfoil interactions and turbine structural response. DOE also continues to support

assessments of U. S. wind resources to assist State and utility energy planners and power producers in identifying

new opportunities for deploying wind energy systems. Funding for the program was about $21 million in FY 1992.

The Geothermal Energy Program emphasizes cooperative R&D on technologies for reducing the cost of

exploration development, and conversion to make more of the domestic geothermal resource available and

economic, The program is examining the peak load following capabilities of existing geothermal plants, and

exploring technologies for tapping the energy potential of hot dry rooks, and geopressurized brines. Geothermal

Energy Program activities were budgeted at $26 million in FY 1992.

The Hydropower Program sponsors research on the costs, benefits, and effectiveness of environmental

mitigation practices with the goal of reducing the uncertainties in the regulatory review of proposed hydropower

development. FY 1992 funding was about $1 million.

the health effects of electric and magnetic fields. increase power systems flexibility, efficiency,

The major recipients of R&D funds under these

programs are the various national laboratories.

Long-term goals for DOE research on transmission and distribution (T&D) technologies are

to reduce energy losses on T&D systems (now

estimated at 8 to 9 percent) by 10 percent, to

reduce nuisance outages by 20 percent, and to

increase post-outage recovery speed by 50 percent.

24 DOE is engaged in cooperative R&D on

higher capacity transmission and automated control systems incorporating advanced electronics,

communications, and computer technologies to

and reliability .25 To improve the costeffectiveness of higher efficiency transmission

technologies, for example, the DOE program is

looking at the technologies necessary for converting alternating-current (AC) transmission lines to

high-voltage direct current (DC) effectively doubling the capacity over the same right-of-way.

Development of new technologies for improved

real-time control of utility T&D will result in

more efficient transmission and increased transmission capacity utilization.

U lbi~ pp. 27-28.

~ DOE, FY 1993 Congressional Budget Request, vol. 2, pp. ll!J-123.
Chapter 7–Federal Programs I 157

The Ocean Energy Technology program with a budget of $2 million is cooperating with the State of Hawaii

in the design and construction of an experimental ocean thermal energy conversion (OTEC) facility using seawater

as its working fluid.

Solar Energy Conversion Programs

The Photovoitaic (PV) Program is pursuing efforts to aid development of more cost-effective PV energy

systems and to expand the market potential for PVS in utility applications. The program has set a goal of cutting

the cost of PV systems from today’s $0.25 to $0.35/kWh to $0.12 to $0.20/kWh by the late 1990s. The long-term

goal is PV power generation at $0.06/kWh (in 1990 dollars). The PV Program is targeting improvements in PV

materials, components, and system design to boost the solar conversion efficiency of thin-film and concentrator

materials, and to advance the development of mass-production manufacturing capability. DOE also is participating

in a PV demonstration project called Photovoltaics for Utility-Scale Applications (PVUSA), a joint-venture with

EPRI, the California Energy Commission, and several utilities to test PV arraysfromseven manufacturers in a utility

setting. The FY 1992 budget for the PV program was $60 million.

The SolarThermai Program is sponsoring research on improving basic thermal conversion technology and

is supporting cost-shared development of central receiver systems for grid-connected electric generation and dish

concentrators for remote-site power generation. The program is participating in joint ventures with industry in

development and commercialization of solar thermal systems for remote applications at $0.1 to $0.2/kWh as a

stepping stone to less-costly utility applications. Funding for solar thermal activities was $ 21 million in FY 1992.

The Biomass Power Program, budgeted at $4 million in FY 1992, is focused on research on biomass

gasification and high-efficiency turbine conversion to expand the range of applications and performance of

biomass power generating systems. The long-term goal is producing electricity at $0.04/kWh (in 1990 dollars)

allowing biomass power systems to compete with conventional fuels for utility baseload applications.

SOURCES: Office of Technology Assessment, 1993, based on information from U.S. Department of Energy, FY 1993 Congressional

Budget Request, voI. 2, January 1992, pp. 15-23; and US. Department of Energy, Assistant Secretary for Conservation and Renewable

Energy, Conservation and Renewable Energy Technologies for Utilities,” DOE/CH10093-86 (prepared by National Renewable Energy

Laboratory, Golden Colorado), April 1992, pp. 11-26.

DOE’s support of R&D on high-temperature improving the performance of high-temperature

superconductivity (HTS)

26 offers several poten- superconducting materials to allow fabrication of

tial long-term efficiency benefits for utilities,

including lower power losses on T&D systems,

more efficient generators, and advanced magnetic

energy storage systems. Development of a strong

domestic HTS industry could prove of strategic

importance to U.S. industrial competitiveness.

Significant technical challenges stand in the way

of realizing any of this potential, however. DOE’s

collaborative research program is focused on

HTS wires, coils, and cables for long-term utility

applications and is budgeted around $21 million

a year.

Research on thermal energy storage systems

includes the District Heating and Cooling (DHC)

Program supporting joint ventures to develop

technical strategies to cut the capital costs and

increase the energy efficiency of major DHC

components. 27 DHC technologies offer utilities

26 Hi@.ta_e superconductivity ref~ to materials that can conduct electricity with mIWSiStiCX ~eXWl magnetic fields

(dimagnctism) at temperatures substantially higher than liquid helium (4 degrees Kelvin(K) or 4 degrees C above absolute mm which is minus

273 degrees C). Sustaining superconductivity of high electric currm ts in high magnetic fields at temperatures of liquid nitrogen (about 77

degrees C above absolute zero) now commonly used in industrial applications could make HTS motors generators, magnets, and similar devices

potentially practical. fbi~ p. 122.

27 ne DHC prop was mandated by the Renewable Energy and Efficient ‘Rdnology Aeti Public Law 101-218, SCC. 6, JXC. 11, 1989.
158 I Energy Efficiency: Challenges and Opportunities for Electric Utilities

opportunities to lower electricity peaks and improve energy efficiency and fuel flexibility. The

DHC program was budgeted at $4.2 million in FY

1990-92 with more than $1 million expected from

nonfederal sources for demonstration projects in

FY 1992.28 Because DOE views the technology

as sufficiently mature to permit commercial

growth of DHC systems, it proposed termination

of the program and documentation of research

results during FY 1993.29 DOE also supports

research on improved battery storage systems for

utility applications and technologies for future

hydrogen energy systems.

The Electric Energy Systems program also

oversees DOE’s research efforts on potential

health effects of exposure to electric and magnetic

fields. DOE is supporting research on characterizing EMF exposures, potential biological mechanisms of EMF interaction with living systems,

and epidemiological studies. DOE is also expanding efforts on public information and engineering

research on EMF mitigation options.

Office of Utility Technologies programs are

geared specifically towards utilities. However,

several other programs in DOE perform work that

is potentially beneficial to utilities. This includes

other programs under the 0ffice of Energy

Efficiency and Renewable Energy and in the

0ffices of Fossil Fuels and Nuclear Energy, to be

discussed later in this chapter.

Demand-Side Energy Efficiency Programs

The Office of Energy Efficiency and Renewable Energy also adminis“ ters programs that promote energy-efficient demand-side technologies

through R&D, technical and financial assistance,

and energy codes and standards. With buildings

and industry contributing 30 percent each to U.S.

energy use, the potential contributions from

efficiency improvements in these sectors is substantial. DOE support for the development and

commercialization of energy-efficient buildings

and industrial technologies yields products that in

turn create energy-saving opportunities for utilities and consumers.

Office of Building Technologies30—The commercial and residential sectors are frequently

referred to as the buildings sector because most of

their energy use is for building systems (i.e.,

heating, cooling, lighting, and appliances). Building energy use accounts for more than a third of

all U.S. energy use and is continuing to grow even

as the efficiency of buildings and appliances is

improving. DOE-supported buildings R&D have

provided several energy-efficient technologies

successfully in use today, including solid-state

fluorescent lamp ballasts, advanced refrigerator

and freezer technologies, and low-emissivity

window coatings. These technologies, resulting

from R&D efforts initiated in the late-1970s,

produced results that will save energy into the

next century. Advances in fluorescent lamp ballasts aided by $3 million of DOE research funds,

are expected to save billions of dollars in lighting

energy costs in the coming decades. DOE-funded

research efforts in improved insulation and wall

and ceiling structures have also yielded successful energy-saving applications.

The Office of Building Technologies is currently supporting research to develop costeffective technologies to reduce building energy

loads by 30 percent in the near-term and by as

much as 80 percent in the long-term. Major

emphasis is given to development of highefficiency lighting systems, energy efficiency

HVAC conversion and distribution systems, advanced building materials, more energy-efficient

appliances and replacements for chlorofluorocarbons in building systems. Advances in these areas

will contribute to the technology base for utility

~ ME, FY 1992 Congressional Budget Request, VOL 4, pp. 440-441.

29 U.S. Dep~ent of Ener=, FY 1993 Congress”onalBudgetRequest, vol. 4, DO13/CR4KX16, January 1992, pp. 478-79. He*tertieti

to as DOE, FY 1993 Congressional Budget Request, vol. 4.

~ For more info~tion on DOE’s building technology researcq see OTA, Bw”Zding Energy E~ciency,suw note 9.
Chapter 7–Federal Programs 1159

DSM programs. Buildings Technologies is also

supporting R&D on cost-effective solar technologies to meet some or all of the energy needs of

new buildings.

Office of Industrial Technologies31-DOE efforts to improve industrial efficiency have zeroed

in on reducing the waste streams generated in

industrial processes to improve energy efficiency

and eliminate harmful environmental pollutants.

DOE is also supporting development and adoption of more energy-efficient technologies and

processes in energy-intensive industries and more

extensive use of industrial cogeneration and

municipal solid waste energy systems. These

efforts could offer benefits to utilities in more

diverse opportunities for new energy supplies as

well as a stream of efficient industrial electric

technologies for DSM programs.

Among the successes from DOE-funded industrial research are a control mechanism for a

high-efficiency transformer used in the welding

process, biomass grain driers, and slow-speed

diesel motors for cogeneration systems. Present

DOE industrial research is focused on improving

the efficiency of electric motors, which now

account for some 70 percent of industrial electricity use. DOE’s cooperative efforts to spur adoption of adjustable-speed drives and high performance electric motors for new and retrofit applications include efforts to develop and provide

information to justify including industrial motor

programs in utility integrated resource plans.32

Technical and Financial Assistance Programs

Federal efforts to save energy and promote

energy efficiency and renewable energy technologies have led to a variety of programs that offer

technical assistance and Federal funds to government and private entities. Many of these programs

were originally established during the energy

scares of the 1970s and they have had varying

degrees of success. Among the most notable are

the various programs administered by the Office

of Technica1 and Financial Assistance, the now

expired Residential Energy Conservation and

Institutional Energy Conservation Programs, and

the Federal Energy Management Program.

The Office of Technical and Financial Assistance (OFTA) administers a variety of programs that provide technical advice and grants to

States, local governments, nonprofit institutions,

and low-income individuals. OFTA also oversees

State programs funded from the petroleum overcharge violations settlements. OFTA’S portfolio

consists of various State and local partnerships,

information and technical assistance programs,

and energy management programs .33 The State

and local partnerships encompass the State Energy Conservation Program, the Energy Extension Service, the Weatherization Assistance Program, and the Institutional Conservation Program.

The State Energy Conservation Program,

established in 1975 under the Energy Policy and

Conservation Act, provides financial and technical assistance to States and localities to develop

and implement comprehensive energy conservation plans to encourage energy efficiency and

reduce energy demand growth. All States have

implemented the act’s mandatory energy conservation programs (including lighting efficiency,

insulation, and thermal efficiency standards for

nonfederal public buildings) and most now include supplementary programs in energy education, technology demonstration, and technical

31 ~~c~ om~ties for energy-saving technologies for industrial application ti relevant @ve rnment programa are examined in

detail in U.S. Congress, Office of Technology Asscsmen~ lndustn”al Energy Eficiency, released in April 1993 and to be published in summer

1993.

32 DOE, FY ]99.3 congressio~l Budget Request, vol. 4, p. 365.

33 ()~A ~.~fitem a number of modest programs providing technical and fucial iISSiStanCZ for .SXIM CIIerSY inventom ~d

innovators, technology transfer and information programs, and international market development and energy technology information exchange

programs. These programs am not particularly relevant to utility energy efilciency efforts and are not discussed here.
160 I Energy Efficiency: Challenges and Opportunities for Electric Utilities

Table 7-5-Budgets for DOE Energy Grant Programs, Fiscal Years 1991-93

(thousands of dollars)

Grant program 1991 1992 1993 request 1993 actual

Weatherization Assistance Program . . . . . . . 198,952 193,925 80,000 187,000

State Energy Conservation Program . . . . . 16,620 16,194 45,000 15,600

Institutional Conservation Program. . . . . . . . 31,022 30,246 30,000 29,200

Total.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 246,594 240,365 155,000 231,800

SOURCE: Office of Technology Assessment 1993, based on data from U.S. Department of Energy, FY 1993

Congressiona Budget Request, vol. 4, January 1992, pp. 28&281, and other sources.

assistance reflecting local priorities. A major goal

of the program is to build State and local

institutional capabilities for energy conservation

planning and implementation.

Funds are provided in the form of formula

grants (requiring a 20 percent State match) and

incentive awards for innovative State/industry

cooperative programs. While appropriations for

the program have decreased since 1979, overall

funding of State program activities has ballooned

because of the availability of oil overcharge

funds.34 See table 7-5 for a summary of funding.

DOE technical assistance to State energy agencies focuses on education and information exchange and has included publications, training

manuals, an information clearinghouse, seminars,

workshops, and conferences. States have used the

funds to support a variety of energy conservation

activities, including demonstration projects installing energy-efficient lighting, HVAC, and

energy management systems and solar technologies in public buildings.35 Beginning in FY 1992,

DOE has supported an initiative aimed at encouraging States to attract nonfederal resources to

supplement the grants provided by offering additional incentives to support State-led joint ventures with industry to encourage the near-term

adoption of emerging renewable energy and

energy-efficient technologies.36

A companion program, the Energy Extension

Service (EES) was created in 1977 to provide

information, technical assistance, and training

tailored to the needs of small energy users such as

homeowners, municipalities, and small businesses. Under the program, State energy agencies

or other designated entities design projects serving specific local information needs. Cost-share

funds are disbursed from DOE through State

agencies to local programs.

Among the successful projects have been

energy on-site audits, self-help workshops, and

auditor-training programs. The program is intended to be flexible and responsive to local needs

and leveraging of private funds is encouraged.

In Rhode Island, grant funds were used in a

cooperative effort with local electric utilities and

a nonprofit group to conduct energy audits of

State buildings and recommend lighting efficiency retrofits. The utilities provided rebates of

up to 82 percent of relamping costs, with State

~ Funding for thepm~ inFY 1989 was about $60 million (in current dollars), by 1989, total funding irdudhg oil ove!duwge funds VWIS

in exeess of $300 million. OTA Bui/4”ng Energy Eflciency, supra note 9, figure 4-6, p. 121, citing various DOE reports to Congress.

M A dewed re~rt on the diversi~ of State use of oil overcharge funds made available through various Federal/State p-erships by 1989

is provided in ConsumerEncrgy Council of America Research Foundation A State-&y-State Compendium ofEnergyEflciency Progrurns Um”ng

Oil Overcharge Funds, EPIU CU-7541 (Mo Alto, CA: Eleetric Power Research Institute, h4.meh 1991). By 1989 ovex $7 billion in various

oil overcharge settlemeds had been collected and additional eases (with anticipated recoveries of $0.5 to $1.0 billion) were still under

negotiation. Expenditures of funds from the eserow amounts from the Exxon settlement wem limited to various Federal and State progmms

including the State Energy Conservation Pro- the Energy Extension Serviee, Institutional Consemition Pro- Weatherization

Assistance Program, and Low-Income Home Energy Assistance Program. Funds from other settlements can be used for other ways as well.

By 1989 about half of the overcharge funds had been expended, but a huge pool of fimds remains to be tapped by State and local governments.

3A ml= of -gernmt and Budge~ Budget for Fiscal Year J993, APPCdX m, p. 472.
Chapter 7–FederaI Programs I 161

funds paying the remainder. The State estimates

that the project will result in a 20-percent

reduction in total annual State electric costs.37

EES funds have also supported providing

training for school districts in Washington on

how to reduce energy use through lighting

changes on school grounds and installation of a

cogeneration demonstration at a community and

business center, in Taos, New Mexico expected to

save $10,000 annually in energy costs.

The Energy Policy Act of 1992 repealed the

National Energy Extension Service Act that

established EES.38 The repeal is unlikely to result

in lost energy savings given the overlap with

other programs.

OTA’s Building Energy Efficiency report noted

that both the Energy Extension Program and the

State Energy Conservation Programs lack evaluations of cost-effectiveness or reliable energysavings estimates. However, OTA observed:

. . .IB]oth programs are important networks for

conveying Federal monies and expertise to the

State and local level, and both programs are

connected to small-scale energy users that could

help DOE demonstrate technologies emerging

from its energy conservation research and development projects. In addition, the auditor and other

training offered by these programs help establish

and sustain local expertise and markets for

weatherization and other conservation services.39

The experience in Rhode Island also demonstrates that the programs provide opportunities for

State/utility/private partnerships that can leverage Federal grant funds and expand the reach of

utility-sponsored efficiency programs. With the

large pool of oil overcharge funds still remaining,

these opportunities should prove attractive to

States and utilities.

The Weatherization Assistance Program (WAP)

was originally established in 1976 under the

Energy Conservation and Production Act to help

weatherize the homes of low-income families.

The program aims to reduce the energy costs of

low-income families.

WAP allocations to States are made under a

formula reflecting the number of low-income

households, residential heating and cooling energy use, and local climate conditions. Families

qualify for weatherization assistance if they meet

certain eligibility conditions, including a household income at or below 125 percent of the

poverty level. The weatherization assistance programs are usually carried out by local community

organizations that provide energy audits and

installation of cost-effective weatherization measures. In addition to the grants for weatherization

activities, DOE also provides funds for training,

technical assistance and client education.

According to DOE, energy savings of 25

percent or more are possible at residences eligible

for WAP funds. Families earning less than $5,000

a year consume an average of 68 percent more

energy to heat a square foot of living space than

higher-income families. This difference is attributable in part to the fact that lower-income

residences are old and in disrepair, and hence less

energy efficient than the homes of higher-income

households.

An early national evaluation of WAP found

that the average energy savings is 10 percent per

household from WAP retrofits.40 However, since

there have been many program changes since

1981, the evaluation may no longer be valid. DOE

37 U.S. Department of Ener~, The Secreta~’s Annual Report to Congress 1990, DOE/S-0010P(91), p. 58. I-Iereafter DOE Annual Repofi

to Congress 1990.

36 ~bhc ~w 10246, 1~ S@t< 2776, @t. 24, 1992, ~ti~n 143.

39 OTA, Building Energy Eficiency, supra note 9, pp. 122-123.

@ G.J3. PeaMy, U.S. Department of tiergy, Energy ~ormation~“ “stratiom Weathenzation Program Evaluation, sewice repofi

SR-EE~-84-1, Washin@o~ ~, August 1984, pp. 1, 18.
162 I Energy Efficiency: Challenges and Opportunities for Electric Utilities

has initiated a new evaluation and anticipates a

final report at the end of 1993.41

In recent years, the WAP program has also

shifted more of its emphasis to encourage leveraging of Federal funds to increase the number of

clients it can serve. Agreements were made with

two utilities to augment WAP funds with additional financial and in-kind services.42

The Institutional Conservation Program (ICP)

was established by the National Energy Conservation Policy Act in 1978 as a matching grant

program that provided funds for both detailed

energy audits and the suggested energy-saving

capital improvement in nonprofit institutions,

such as schools and hospitals. Projects are funded

on a 50 percent cost-share basis and are administered through State agencies. Since 1978, the

program has awarded over $800 million in grants

while saving over $2 billion in energy bills at

participating institutions.43

New rules adopted as a result of Public Law

101-440 will streamline the program and encourage leveraging, and third-party financing options

(such as utility demand-side management programs and energy savings contracts). The new

rules will allow a State to use up to 100 percent of

its funds for program and technical assistance

activities and up to 50 percent of its Federal funds

for marketing and other costs associated with

leveraging nonfederal funds.44

The DOE Weatherization Assistance Program

and the Institutional Conservation Program (ICP)

are financed in large part from the petroleum

overcharge fund. An additional beneficiary of

these funds is the Low-Income Home Energy

Assistance Program (LIHEAP) at the U.S. Department of Health and Human Services (HHS)

that helps poor households in meeting their

energy bills. LIHEAP is described in box 7-C.

Past Technical Assistance EffortsBuilding Energy Audits

During the 1980s Congress discontinued two

legislatively-mandated building energy audit programs that included utility participation. The

Residential Conservation Service (RCS), which

expired in 1989, and the Commercial and

Apartment Conservation Service, repealed in

1986, were designed to provide building owners

and occupants with building-specific information

on energy use and savings.45 The centerpiece of

the program was the requirement that utilities

perform an on-site energy audit that included

actual measurements by an auditor and an individualized written report for its customers.

The enabling legislation for RCS estimated

that the program would contribute to the insulation of 90 percent of the Nation’s homes. However, at the conclusion of the program 7.3 million

audits had been performed, achieving only 11

percent participation.%

As designed, the programs did not address

either the availability and costs of financing

conservation retrofits nor the regional availability

of conservation supply and installation services.

Additionally, under most State ratemaking formulas then in use, participating utilities lacked

sufficient incentives to conduct the program as

the costs of the program were merely passed

through to customers without any added profit

and resulting energy-savings potentially reduced

utility revenues.

Despite these drawbacks, the programs, like

other federally-mandated technical assistance and

41 ()’E.q, Buil&’ng Energy Eficiency, Supra note g, pp. %’-99.

42 DOE , Annul Report to Congress 1990, P. 61.

43 ()~, Building Energy Eflciency, supra note 9, pp. 99-100.

~ ME, FY 1993 Congressional Budget Request, VOL A, p. SM.

45 For more on tie h~tow ~d ~ffWtivmess of hew progr~ s= OTA, Buil~”ng Energy Eficiency, supra note 9, pp. 117-121.

46 cen~w AssW~te~, Up&te of the E~~l~tion of the Re~&ntial conse~ation Sem”ce program, VO1. 1, l’t!poll prep~ed fOr he U.S.

Department of Energy, DOE/CS/10097, 1987, p. 2-19.
Chapter 7–Federal Programs I 163

Box 7-C-Helping the Poor Pay Their Electricity Bills:

The Low-Income Home Energy Assistance Program

LIHEAP, established in 1961 by the Imw-income Home Energy Assistance Act (Public Law 97-35), is a

block-grant program administered by the Department of Health and Human Services. The program provides funds

to States to help eligible low-income households meet heating and cooling bills, such as utility bills. Up to 15

percent of State LIHEAP grants (25 percent with a special waiver) can be used for home weatherization.

In 1990, with funding of about $1.6 billion, LIHEAP reached about 6 million households; weatherization

services were provided to only 146,000 homes. On average, States spend from 7 to 10 percent of their LIHEAP

funds on weatherization. The bulk of the funds are spent on energy assistance, averaging about $200 per

household. In contrast, average weatherization expenditures under the program are about $l,600 per household.

For the Federal Government and State agencies, helping poor families pay their energy bills allows thereto reach

more households with available funds than weatherization efforts, even though weatherization could cut

household energy bills.

OTA’s report, Building Energy Efficiency found that there was little assessment of the cost-effectiveness of

LIHEAP weatherization efforts and no dear program policies encouraging cost-effective weatherization. Moreover,

utilities benefit substantially from Federal LIHEAP outlays by collecting payments that otherwise would have been

lost or delayed. (Utility arrearages from delays in paying residential bills amount to hundreds of millions of dollars

annually; LIHEAP funds help offset these liabilities.) The report noted that new Federal policies or requirements

to leverage LIHEAP weatherization funds with State and utility resources could boost the number of low-income

households that receive energy efficiency measures under the program.

SOURCE: U.S. Congress, Office of Technology Assessmens, Building Energy Efficiency, OTA-E-518 (Washington, DC: U.S. Government

Printing Office, May 1992), pp. 99-100.

reformation programs, helped to create the insti- budget ($4 million in FY 1992). FEMP has four

tutional infrastructure and expertise in State

government, utilities, and energy conservation

service providers that now help sustain active

energy efficiency and technical assistance efforts.

The Federal Energy Management Program

The Federal Energy Management Program

(FEMP), located in The Office of Building

Technologies, is an outreach program designed to

assist Federal agencies in adopting energy efficiency measures in buildings, transportation and

operations (see box 7-D). The program was

established in the mid- 1970s in response to

legislation and Executive Orders directing Federal agencies to reduce energy use. The program

has a small staff (six people in 1991) and a modest

areas of operations: 1) reporting on the energy

management efforts of Federal agencies; 2) providing information training, and technical SUpport

to Federal agency personnel; 3) hosting interagency meetings to develop new Federal initiatives; and 4) awarding annual certificates of

achievements to Federal facilities and personnel

for demonstrating exemplary performance .47

As part of its efforts to assist Federal agencies

in implementing energy-saving measures, FEMP

has been evaluating agency participation in utilitysponsored DSM programs and is assisting in

administrative reforms that would encourage

greater use of shared energy savings contracts by

Federal agencies as an alternative means of

funding efficiency improvements. DOE estimates

47 U.S. CoWess, Office of TMIIIO1OW Asses.smen~ Energy Eficiency in the Federal Government: Government by Good Emmple7,

OTA-E-492 (Washington DC: U.S. Government Printing Office, May 1991), pp. 24-25.

330-075 : QL 3 0 - 93 - 7
164 I Energy Efficiency: Challenges and Opportunities for Electric Utilities

Box 7-D--Federal Energy Management Program

Federal Spending on Energy, FY 1989

Other

/

Assisted

housing

4

SOURCE: Office of Technology Assessment, 1993, adapted from U.S.

Department of Energy, Federal Energy Management Program, “Report

on Federal Government Energy Management and Conservation Programs,” October 1990.

The Federal Government is the Nation’s

Iargest single energy consumer. In FY 1989, the

Federal Government spent over $8*7 billion on

direct energy purchasesfor its own facilities and

operations and another $4 billion subsidizing the

energy expenses of low-income households

(see figure). Not reflected in this direct energy

expenditure are some $12.7 billion for energy

costs for leased space for which the Federal

Government does not directly pay utility bills.

Payments to electric Utilities accounted for an

estimated $2.4 billion of the FY 1989 energy bill

for Federal buildings. Electricity accounts for

around 70 percent of total energy costs.

OTA’S report Energy Efficiency in the

FederalGovernmentby Goo d

Example? concludes that much Federal energy

is inefficiently used OTA estimated that the

Federal Government could profitably conserve

at least 25 percent of the energy used in Its

buildings by adopting commercially 

cost-effeotive measures such as high-efficiency

lighting and carefully operated heating, ventilation, and air conditioning equipment-with no sacrifice of comfort

or productivity.

The constraints to Improved Federal energy efficiency are real and significant (see table.) Implementing

efficiency improvements will require overcoming several hurdles, including finding sufficient funds to pay for

retrofits in an era of tight budgets.

OTA’s ease studies found a large potential for savings. However constraints, notably the Iack of funding and

staff, limited action at the facilities. For example, the General Services Administration’s (GSA) Suitland Complex

has about 2 million square feet of commercial building space. Electricity accounts for over 90 percent of the

$5-million annual energy bill. The facility has increased effiencyof the heating, ventilation, and airconditioning

system, improved lighting efficiency, and improved the building envelope. Most Improvements consisted of low

first-cost measures because the funds for more capital-intensive measures were unavailable.

In spite of these efforts, energy use at the facility has risen since 1985. Changes in the building’s use, such

as greater use of computers and increased occupancy, offset the gains. Further measures have not been

implemented for several reasons. The complexity of the procurement process creates significant lag time, and

inhibits selection of innovative equipment and participation in local rebate programs. Current policy restricts

replacement of functional equipment in spite of technological advances that would reduce energy use. Lastly,

building personnel often Iack training in energy conservation and some new technologies may be too sophisticated

to run without it.

OTA found that there are mechanisms in place to promote greater energy efficiency in Federal buildings

including sanctioned private-sector financing options available to assist funding of energy efficiency measures.

1 U.S. Congress, Office of Technology Assessment, Energy Efficiency the Federal Government:

Govemnent by Good Example?OTA-E-492 (Washington, DC: U.S. Government Printing Offioe, May 1991).
Chapter 7–Federal Programs 1165

The first of these are shared energy

savings (SES) contracts. Under the Comprehensive Omnibus Budget Reconciliation Act of

1985 (Public Law 99-272), all Federal agencies

can seek private financing from energy service

companies. These companies perform conduct

energy audits and install efficiency measures

using their own capital and personnel. Their

costs and profits are paid for out of the monies

that previously went to higher energy bills.

However, this procurement practice is rarely

used by Federal agendas. The complexity of

the procurement process and uncertainty over

who keeps the savings discourage interested

agencies from initiating such contracts. Legislation was passed to assist the Department of

Defense (DOD) overcome constraints in SES

contracting. DOD is permitted to retain twothirds of energy savings at the installation with

the SES contract. One-half is to be used for

further energy conservation measures, while

the other half is available for other projects.

Additionally, provisions in the act simplify the

contracting procedures for DOD.

Utility rebates are another important

source of funding. Large Federal installations

offer significant energy savings for interested

utilities.Therebates offered by utilities are likely

to bring borderline efficiency measures within

financial reach. For example, the GSA and

Constraints on Improved Federal

Energy Efficiency

Resource constraints

Priorities favor other agency needs

Energy efficiency is not central to most Agencies’ missions

Energy is a small component of most agendas’ expenditures

Little senior management interest

Many measures require initial capital spending

Many measures require personnel

Many facilities have no energy coordinator

Information constraints

Opportunities have not been systematical!y assessed

Agencies are uncertain of technical and economic performance

Does this technology really work?

Would the facility be better off waiting for next year's model?

Lack of metered energy-use data

%0 little information sharing between agencies

Energy-use decisions are dispersed, made by thousands of

individuals

Implementation requires coordinated effort from diverse parties

Too little training and education for diverse parties

Lack of incentives

Dollar savings often do not acrue to energy savers

Energy costs are readily passed through budgets

Federal procurement policies often favor status quo

Procurement practices am complex often restrictive

SOURCE: U.S. Congress, Office of Technology Assessment, Energy

Efficiency in theFederal Government: GovernmentbyGood Example?

OTA-E-492 (Washington, DC: U.S. Government Printing Office, May

1991), p. 10.

Potomac Electric Power Company in the Washington, DC, metropolitan area have been working on a Federat

Lighting Initiative. In 1991, GSA committed $10 million towardthis effort with PEPCO offering an additional $10

million in rebates. As of early 1991, only DOD and DOE had an explicit policy on receiving utility rebates. DOD

is allowed to retain two-thirds of rebate, while the remaining third is returned to the general fund at the Treasury.

DOE is allowed to retain the entire sum and credit the rebate to energy cost appropriation. Pacific Northwest

Laboratory, a national laboratory, iS working with FEMP to develop a generic Federal utility rebate program.

Efforts to improve the energy efficiency of Federal buildings received further stimulus under the Energy Policy

Act of 1992. The act toughens energy efficiency standards for Federal buildings and sets anew deadline of 2005

for Federal agencies to install cost-effective technologies to save energy and water. Also enacted were a number

of other measures to raise energy awareness among Federal managers and financial commitments to energy

efficiency.

SOURCE: Office of Technology Assessment, 1993.
166 I Energy Efficiency: Challenges and Opportunities for Electric Utilities

that aggressive implementation of energy efficiency measures in Federal buildings, such as

lighting retrofits, could cut Federal energy use by

10 percent from 1985 levels and yield savings of

$400 million per year by 1995.48

ENERGY EFFICIENCY INFORMATION

AND STANDARDS

The Federal Government has had almost 20

years of involvement in various programs involving building energy codes and standards, and

appliance labeling and efficiency standards. In

addition to DOE, the Federal Trade Commission

(FTC) and the U.S. Department of Housing and

Urban Development (HUD) have been involved

in these efforts. The programs have required

Federal agencies to work in cooperation with

trade and professional organizations and manufacturers.

OTA’S report Building Energy Efficiency examined the history and efficacy of these programs

for commercial and residential energy technologies.49 OTA found that although there has been

limited evaluation of the effectiveness and energysavings attributable to these efforts, there is some

consensus that they help reduce informationrelated constraints to energy efficiency improvements, and they provide accepted benchmarks

used by electric utilities in determining and

advertising energy-efficient products in their

DSM programs.

Federal Building Energy Codes and Standards

While building energy codes generally are

adopted and enforced locally, most localities rely

on model codes published by national building

organizations .50 The DOE and HUD have been

active in developing model and mandatory building energy codes and standards. In cooperation

with States and various national organizations,

Federal agencies have issued voluntary guidelines for nonfederal buildings. DOE and HUD

have promulgated energy efficiency standards for

Federal buildings and manufactured homes (e.g.,

mobile homes). Although the number of new

Federal buildings constructed annually is small,

the Federal Government potentially has the ability to influence about 27 percent of new home

construction through eligibility requirements for

Federal mortgage insurance programs of the

Federal Housing Administration, the Veterans

Administration, and the Farmers Home Administration. 51 Table 7-6 shows the status of Federal

efforts.

Appliance Efficiency Standards

The National Appliance Energy Conservation

Act52, as amended, establishes Federal minimum

efficiency or maximum energy use standards for

certain appliances, including refrigerators, air

conditioners, and furnaces. DOE is required to

update the standards to reflect technological

changes every 3 to 10 years depending on the

appliance. Federal efforts to promulgate efficiency standards for consumer appliances were

initiated in the 1970s under the National Energy

Conservation Policy Act. Implementation of that

act’s mandatory efficiency standards was slow

because of opposition within the Executive

Branch and from manufacturers, and litigation.

Pressure for uniform national standards helped

break the logjam after California and several

other States adopted appliance efficiency stand48 WE, FY 1993 Congressiowl Budget Request, vol. 4, p. 327.

@ OTA, Buildin8 Energy E#iciency, Supra note g, pp. 107-116.

m The major organimations are: the Building Of?lcials & Code Administratmx International the International Conference of Building

C)Mcials, the Southern Building Code Congress International, and the Council of American Building C)fflcial.s, a federation of the fiist three

organizations. The American Society of Heating, Refrigeration and Air-Conditioning Engineers (ASHRAE) promulgates standards for

building HVAC systems tbat are often incorporated into building codes.

51 Om, Buifding Energy Eficiency, Supra IIOte 9, pp. 1O’7-1W.

52 Pubfic bw 1w137, w. 17, 1987, amended by Public Law 100-357,42 U.S.C. 6292.
—

Chapter 7–Federal Programs I 167

Table 7-6-Federal Energy Standards for New Buildings 1992

Code

HUD Minimum Property Standards

(1950s)

National Manufactured Housing Construction and Safety Standards (1974)

DOE Building Energy Performance

Standards (1979)

DOE Mandatory Performance Standards for New Federal Residential

Buildings (1989)

DOE Energy Performance Standards for New Commercial Buildings

(1990)

DOE Voluntary Guidelines for Nonfederal Residential Buildings

Applicability

Residential buildings receiving

Federal mortgages

All manufactured housing

All new construction

Federal residential construction

(95 percent is military housing)

Mandatory for Federal commercial buildings. Voluntary for privatesector commercial buildings.

Voluntary standards for nonfederal residential buildings

Status

To be replaced with Council of

American Building Officials ‘Model

Energy Code’

Active

Never implemented; supplanted

by performance standards listed

below

Active

Active

Underdevelopment; issuance pending

NOTE: New Federal Building Energy standards adopted in Energy Policy Act of 1992 (Public Law 102-488) are not included

above.

SOURCE: Office of Technology Assessment, 1993, adapted from U.S. Congress, Office of Technology Assessment, Building

Energy Efficiency, OTA-E-518 (Washington, DC: U.S. Government Printing Office, May 1992), p. 109.

ards of their own in the absence of Federal action.

Table 7-7 shows selected appliance standards

established before 1992, The Energy Policy Act

of 1992 added additional energy and water-using

devices to the list of products for which minimum

Federal energy efficiency standards have been

established .53

Appliance Labels

The Federal Government has also mandated

labels showing energy use for the appliances

covered by the standards under the Energy Policy

and Conservation Act.54 The requirement is based

on the belief that consumers will purchase more

efficient appliances if given information about

operating costs and comparative product efficiencies. Labels now exist for refrigerators, freezers,

dishwashers, water heaters, clothes washers, room

air conditioners, and furnaces.55 The labels include estimated operating costs for the product, as

well as the range of operating costs for other

available products in the same class. Appliance

labeling requirements are the responsibility of the

FTC.

53 fiblic I.AW 102-4$6, Subtitle C, 106 Stat. 2805, Oct. 25, 1992. The product categories added were @S, mOtOrS, commercial heaQ

and cooling equipment, plumbing products, distribution transformers, windows, Iuminari es, and offke equipment. The dates for promulgation

of standards vary, but most must be published over the next 10 years.

~ me ~er~ poliq ad Comaatlon ~t(~blic IAW 95- 163), as amended, requires the Federal made Commission to develop ~d is~e

appliance energy-use labels for: 1) refrigerators, 2) freezers, 3) dishwashers, 4) clothes dryers, 5) water heaters, 6) room air conditioners, 7)

home heating equipment (other than furnaces), 8) television sets, 9) kitchen ranges and ovens, 10) clothes washers, 11) humidif’’ers and

dehumidifiers, 13) furnaces, and 14) any other type of con.sumerproduct defined as covered by the Secretary of Energy. Swimmin g pool heaters

and fluorescent lamp ballasts were added to the list by the National Appliance Energy Conservation At.

55 The Fede~ Trade Commission determined that labeling the remaining classes of appliances (clothes dryers, home hwm qipment

other than fi.maces, television sets, kitchen ranges and ovens, and humidifiers and dehumidifiers). was economically unfeasible and would not

assist consumer purchasing decisions. 44 Fed. Reg. 6W66 (Nov. 19, 1979).
168 I Energy Efficiency: Challenges and Opportunities for Electric Utilities

~

~ Refrigeator-Freezer

(Name of Corporation)

Model(s) AH503, AH504, AH507

~ Capacity 23 Cubic Feet Type of Defrost. Full Automatic

iEllERGYGUIDE ‘ Esttmates on the scale are based

$

*

Only models with 225 to 244

on a national average electrlc cubfc feet are compared

UI rate of 4 97c per kilowatt hour

n

in the scale

wu.

Model with $91 Model with

lowest highest

energy cost

$68

energy cost

$132

v THIS ~ MODEL v

Your cost will vary depending on your local energy rate and how

you use the product. Thios energy COSI is based on u s Government sstandard tests

How much will this model cost you to run yearly?

[Yearly cost

Cost per 2¢ $36

kilowatt

hour

4¢ $73

6¢ $109

8¢ $146

10¢ $182

12¢ S218

Ask your salesperson. or local utility for the energy rate (cost per kilo

watt hour) in your area

Impotant Removal 01 this label before consumer purchase IS a violation Of

federal law (42 U S C 6302)

(Pa, ! No 371026I

The Federal Trade Commission requires many new

appliances to display labels that indicate the units’

expected energy use of efficiency.

B Other DOE Supply-side Research

The Office of Energy Efficiency and Renewable Energy administers a variety of programs

with potential benefits for electric utility energy

efficiency efforts. Three other DOE programs

also sponsor R&D and demonstration projects

dealing with energy efficiency in utility power

generation and operations and cleaner generating

technologies for new utility plants or repowering

of existing plants. Energy efficiency is at present

a minor consideration among the many objectives

of these programs, which appear to be primarily

directed at advancing particular fuels or technologies. DOE-funded activities could also provide

cost and performance information on advanced

power technologies that could aid consideration

of these options in utility IRP programs. It is not

clear, however, whether such information is

effectively made available to the utility sector or

to DOE’s own 0ffice of Utility Technologies.

FOSSIL ENERGY R&D PROGRAMS

Fossil fuels contribute 60 percent of the fuel for

the production of the Nation’s electricity. The

Office of Fossil Energy (FE) supports a wide

range of basic R&D and demonstration projects

involving coal, oil, and natural gas. One of the

strategic goals identified for the fossil energy

research program is to “provide environmentally,

economically superior technology for the generation of electrical and thermal energy, and for the

production of fossil-fuel-based chemicals and

products for the electric utility market. . .“56

Other goals include encouraging utilization of

domestic resources, improving international competitiveness of U.S. technologies and technologybased products, and environmental protection. In

recent years, consistent with these goals, greater

emphasis has been given to cost-shared research

and technologies for near- and mid-term commercialization by the private sector.

DOE-sponsored efforts with potential applications for electric utilities include R&D on coal

combustion and control technologies, waste reduction, and fuel cells.

The coal program activities are focused on

reducing emissions and boosting the energy

efficiency of coal-fried powerplants. Low-cost

coal cleaning methods will reduce costs for

utilities’ compliance with clean air regulations.

The fuel cell program, involving both coal and

gas resources, is working to realize the potential

of highly efficient, clean, and competitive generation of electricity and heat in the major sectors of

the economy and is proposed to be shifted toward

56 ME, COngressiorlal Budget Request, Fiscal Year 1992, VO1. 4, p. 15.
gas applications. By the year 2000, the program

expects to demonstrate high-efficiency, natural

gas fuel cell powerplants for on-site applications

and low-megawatt electric utility powerplants

that are economically competitive with conventional technologies.

The Clean Coal Technology program provides Federal funds to spur demonstration of

advanced coal power generation technologies

offering higher efllciencies, reduced emissions,

and cost savings that can help coal compete with

other resources (see box 7-E).

Cost and performance data from the Clean Coal

Technology Program and other Fossil Energy

R&D projects could aid utilities in resource

planning for future power needs. Figure 7-3

shows the Fossil Energy R&D Budget.

NUCLEAR ENERGY R&D PROGRAMS

Nuclear power currently provides about 20

percent of the Nation’s electricity. The Office of

Nuclear Energy supports research projects in

fission energy, including commercial nuclear

reactor development. Preserving the viability and

economic competitiveness of commercial nuclear

power generation is a major priority of these

efforts.

Much of the DOE nuclear R&D is targeted at

the development of standardized designs for new

nuclear plants. The $200-million program is

shared equally between industry and the Federal

Government. The goal of this partnership is to

develop advanced light-water reactor designs for

commercial application. Another focus is continued R&D in advanced nuclear power systems.

DOE requested $50 million in FY 1993 for

systems that show ‘‘promise of potentially significant breakthroughs in economics, safety, licensing, and waste management. ’ ’57 The early site

permit program, a joint program started in 1992

between DOE and three electric utilities, will

Chapter 7–Federal Programs I 169

Table 7-7-Selected National Appliance Energy

Conservation Act Standards 1992

Covered product NAECA standard

Refrigerator-freezers’. .. ...960 kWh/yr (1990)

688 kWh/yr (1993)

Freezersb. . . . . . . . . . . . . . . . .706 kWh/yr (1 990)

533 kWh/yr (1993)

Room air conditioners.

... ..9.0 EER (1990)

Heat pumpsd

. .. ...........10.0 SEER (1992)

6.8 HSPF (1992)

Water heaterse

Electric. . . . . . . . . . . . . . . . .88.4% EF (1990)

Natural gas. . . . . . . . . ..,. .52.5% EF (1990)

Furnaces. . . . . . . . . . . . . . . . .78.0°\0 AFUE (1992)

Fluoresoent lamp ballasts. , . .See 42 U.S.C. 6295(g)(5)-(6)

KEY: kWh/yr - kilowatt-hours per year; EER - energy efficiency ratio;

SEER - seasonal energy efficiency ratio; HSPF - heating seasonal

performance factor; EF = eff iciency factor; AFUE = annual fuel use (or

utilization) efficiency.

a Automatic defrost units with top-mounted freezers, no through-thedoor ice, and with adjusted volumes of 20.8 cubic feet.

b Uprighf, manual defrost units with an adjusted volume of 26.1 cubic

feet.

c Room air conditioner units without reverse cycle, with louvered sides,

and with capacities ranging from 8,000 to 13,999 Btu.

d Applicable to split (rather than single package) heat pump systems.

SEER standard also applicable to central air conditioning systems.

e Standads shown here apply to 50 gallon units. NAECA water heater

standards are less stringent for larger volume heaters.

SOURCE: Office of Technology Assessment, 1993, adapted from U.S.

Congress, Office of Technology Assessment, Building Energy Efficiency, OTA-E-51 8 (Washington, DC: U.S. Government Printing Office,

May 1992), p. 112.

demonstrate the effectiveness of the early site

permits procedure established by the Nuclear

Regulatory Commission. The procedures are

designed to approve sites for nuclear powerplants

before both construction and substantial financial

investment in an effort to improve industry

standing. 58 Nuclear R&D funding requests were

at $307 million in FY 1993, down from $332

million in FY 1992.

The energy efficiency related goals for nuclear

power plants differ somewhat from those for

ST u.S. Department of Energy, ‘‘National Energy Strategy: Powerful Ideas for America--One Year Later,’ DOE/S-92008~, February

1992, p. 35.

‘g Ibid., pp. 33-36.
170 I Energy Efficiency: Challenges and Opportunities for Electric Utilities

Box 7-E—The Clean Coal Technology Program

The Clean Coal Technology Program was established as an outgrowth of U.S.-Canadian agreements on add

rain control (Public Law 99-190, Dec. 19, 1965). The program provides Federal funds for up to 50 percent of the

cost of building and operating facilities demonstrating the futurecommercial feasibility of dean coat technologies

that burn coal more efficiently, with Iower emissions, and at a lowercostthan existlng technologies. The program

was envisioned as a $5 billion effort with $2.5 billion in Federal funds to be matched with $2.5 billion in private funds.

The Federal investment would be paid back over 20 years from sales of the technologies. Private-sector

participation has exceeded expectations, and the overall investment in projects funded under the program is now

anticipated to top $6 billion.

Clean Coal Program appropriations rose from $99.4 million in FY 1966 to $415 million in FY 1992. The

program has encountered a number of difficulties and delays. Obligations have lagged behind the amounts

appropriated. Awarding, negotiating, and obligating Federal funds for joint-venture arrangements proved to take

longer than originally anticipated. A number of projects fell behind schedule and faced higher than expected costs.

The objectives of the Clean Coal Program have shifted over time. Originally, the program was envisioned as

a means to spur practical technologies that would allow expanded coal use by reducing the adverse environmental

impacts of burning coal and lowering costs for various industrial and commercial applications. As it has evolved,

greater priority was given to technologies that can be used for retrofitting or repowering existing plants.

(Repowering technologies c an also be used for new plants.) In later rounds, emphasis shifted to energy efficiency,

environmental compliance, international competitiveness, and technologies with potentlal tocontribute to reducing

global warming through lowered carbon dioxide emmisions. The fifth round targeted super-dean, high-efficiency

power generation systems needed for coal to compete as an energy source under the more stringent post-2000

standards for sulfer dioxides and nitrogen oxides under the Clean Air Amendments acid rain controls. lnformation

from dean coal demonstration projects will be collected by DOE for use by the industry, energy users,

policy makers, regulators, and equipment vendors.

DOE has held five rounds of solicitations for clean coal Projects with the winners of the fifth round announced

in May 1993. As of late 1992 there were 41 projects from the first four rounds of competition that were either

underway (pre-construction or construction, or operational phases) or completed. Total value of these products

iS nearry $4.6 billion with 60 percent of the funding coming from nonfederal Sources.

Five projects were selected in the fifth round to share in sores $568 million available In cost-sharing.

According to DOE, all five projects propose significant improvements in powerplant efficiencies, achieving

conversion efficiencies of 45 percent of the energy content in the fuel, compared with the 33 to 35 percent

efficiencies of conventional coal powerplants.

Among the technologies that have been funded under the demonstration program in early rounds are

advanced coal cleaning, co-firing ofcoal with other fuels, advanced scrubbing technologies, underground coal

gasification, atmospheric and fluidized bed combustion, slagging combustion, sorbent injection, integrated

gasification combined-cycle, and advanced nitrogen oxide control and other flue gas cleanup technologies.

Proposed projects selected in the fifth round include: a 480-MWadvanced integrated combined-cydepowerplant

coupled with a 2.5 MW-molten carbonate fuel cell, a combined-cycle plant created by repowering an existing plant

with an external gas turbine, a second-generation pressurized circulating fluidized bed powerplant, a small diesel

power system fired by a coal-water slurry and equipped with a heat recovery boiler-steam turbine, and an

advanced integrated steelmaking-power generation process.

The Energy Policy Act of 1992 calls for DOE to consider additional solicitations under the Clean Coal

Technology Program

SOURCES: Office of Technology Assessment, 1993, bawd on information from U.S. Department of Energy, “National Energy Strategy:

One Year Later,” DOE/S--92008000, February 1992, pp. 27+32; and U.S. Department of Energy, Office of Fossil Energy, Clean Coal

Today, No. 9, winter 1992.
Chapter 7–Federal Programs I 171

fossil-thermal plants. The industry is interested in

reducing the downtime that nuclear plants have

experienced, improving load-factor and capacity

availability, and refining predictive maintenance

methodologies, as well as improving the energy

efficiency of individual plant components. Improvements in the energy efficiency of nuclear

powerplants is not a driving force in DOE

commercial nuclear programs. Efforts supporting

standardized nuclear reactor designs and permitting procedures could enhance the viability of

nuclear options in utility resource plans.

FEDERAL POWER SYSTEMS

There are 10 Federal “electric utilities”—

Government-owned and, operated power systems

that generate and sell electricity. They include the

Tennessee Valley Authority (TVA), the five

Power Marketing Administrations (PMAs), the

U.S. Army Corps of Engineers, the Bureau of

Indian Affairs and the Bureau of Reclamation in

the Department of the Interior, and the International Water and Boundary Con-mission in the

Department of State. Together, they operate over

150 powerplants and generate 8 percent of the

Nation’s electricity supply .59 Much of the power

is generated at Federal darn projects initially

designed to control flooding and improve irrigation.

These Federal utilities are primarily generators

and wholesalers of electricity, although some also

serve as retail power distributors to ultimate

customers. Most of the power is sold for resale to

municipalities, electric cooperatives, and other

nonprofit customers under preferences required

by authorizing statutes. In 1990, Federal power

systems sold 197.9 million MWh to wholesale

customers, while sales to ultimate or retail customers totaled 52.1 million MWh. Federal system

Figure 7-3-Fossil Energy Research and

Development Budget, FY 1991-93

- - - Budget ($millions)

500

400

300

200

100

0

— - —: —— — . .

g 1991

n 1992

~ 1993 request

~ 1993 actual

Coal

RZA I 1mEli— - 1

Gas 0il Other Total

Activity

SOURCE: Office of Technology Assessment, 1993, based on data

from U.S. Department of Energy, FY 1993 Congressional Budget

Request, vol. 4, January 1992, pp. 1$17.

operating revenues totaled $8.2 billion and operating expenses were $5.4 billion for 1990 (see

table 7-8). Pricing of Federal power is not

intended to make a profit, but rather to recover

operating costs and ultimately the capital costs of

the facilities plus interest. Long-term debt and

liabilities totaled some $31.9 billion in 1990.60

The major Federal power producers are TVA,

the Army Corps of Engineers, and the Bureau of

Reclamation. TVA markets its own power. Most

of the electricity produced at Corps of Engineers

and Bureau of Reclamation projects is marketed

and transmitted by five power marketing administrations: the Bonneville Power Administration

(BPA), the Western Area Power Administration

(WAPA), the Southeastern Power Administration

(SEPA), the Southwestern Power Administration

SWPA), and the Alaska Power Administration

(APA).61 The PMAs also purchase power from

other electric utilities in the United States and

59 U.S. Dep~ent of Energy, Energy ~o~tion~‘ ‘stratiow Financial Statistics of Selected Publicly OwnedE[ectn’c Ufi”lities 1990,

DOE/EIA-0437(90)/2 (Washingto~ DC: U.S. Government Printing Oftlce, February 1992), p. 337.

m Ibid.

61 me Bureau of Indian Affairs markets power for its Mission Mlley Power and San Carlos dams. The Corps markets power from its Nofi

Central Division in Sault Ste, Marie, Michigan.
172 I Energy Efficiency: Challenges and Opportunities for Electric Utilities

Table 7-8-Statement of Income of Federal Power Marketing Administrations and the Tennessee Valley

Authority, 1990 ($ thousands)

Item APA BPA SEPA SWPA WAPA TVA Total

Operating revenues. . . . . . . . . . . 9,602 2,070,265 136,569 95,326 517,259 5,338,721 8,167,742

Operating expenses. . . . . . . . . . . 3,867 1,554,260 26,500 84,845 514,954 3,216,460 5,400,886

Total income. . . . . . . . . . . . . . . . . . 5,735 516,256 110,069 10,482 2,305 2,117,557 2,762,404

Income deductions. . . . . . . . . . . . . 2,983 201,950 110,081 830 44,918 2,845,175 3,205,937

Net income. . . . . . . . . . . . . . . . . . 2,752 315,605 0 9,652 (44,598) (387,588) (104,177)

KEY: APA . Alaska Power Adminstration; BPA - Bonneville Power Administration; SEPA - Southeastern Power Administration; SWPA -

Southwestern Power Administration; TVA - Tennessee Valley Authority; WAPA = Western Area Power Administration.

SOURCE: Office of Technology Assessment, 1993, from data in U.S. Department of Energy, Energy Information Agency, Financial Statistics of

Selected Publicly Owned Electric Utilities 1990, DOE/EIA-0437(90)/2 (Washington, DC: U.S. Government Printing Office February 1992), table 24,

p. 338.

Canada to help meet customer demand, especially

during periods of drought. ARA is an exception;

it operates its own powerplants and distributes

power to ultimate customers. Figure 7-4 shows a

map of the areas served by the PMAs. With their

broad customer base, PMAs are in a position to

influence almost 30 percent of retail electricity

sold. 62 Although all of the PMAs have authority

to encourage their utility customers to invest in

conservation, only Bonneville and Western have

express legislative authority to link power sales to

their customers with energy efficiency. Without

this “conditioning authority,” the other smaller

PMAs have been limited in their ability to require

their customers to participate in DSM activities.63

Individually, TVA and the PMAs have supported a number of energy conservation initiatives. Energy efficiency improvements offer several opportunities, including reduced agency costs

and increased ability to satisfy varied uses of river

systems.

I Tennessee Valley Authority

TVA was created by Congress in 193364 as a

government-owned corporation with the broad

mission of resource and economic development

for the Tennessee Valley region, an 80,000 square

mile area extending to parts of seven States

(figure 7-5).65 TVA conducts a wide range of

resource development programs including improvement of flood control, navigation, and

recreation for the Tennessee River system, forestry and wildlife development, and electric

power production. TVA also provides technical

assistance in such areas as industrial development, regional waste management, and tourism

promotion and has set up high-tech skill training

centers to meet the needs of regional businesses

and industries. TVA supports a fertilizer research

facility and a bioenergy research program at Oak

Ridge, Tennessee. TVA is governed by a threemember board of directors who are appointed by

the President and approved by the Senate to serve

9-year terms.66

TVA is the largest Federal power producer. It

serves some 110 municipal and 50 cooperative

utilities that distribute power to some 3.3 million

customers. TVA also provides power to about 50

retail customers. In 1990, TVA generated 116

million MWh, accounting for one-half of total net

62 ~H~AccOUII@ ~% ‘‘Utility Demaad-Side Management Programs Can Reduce Electricity Use, ” GAO/RCED-92-13, October

1991, p. 33.

63 Ibid., pp. 37-38.

@ 16 us-c+ 831-831dd0

65 me ~mes= Wey region consists of Alab~ Gem@ Kentucky, Mississippi, North CarOl@ ‘lknnessee, ~ Vh@a.

66 U.S. Gover~nf Manual 1991192, SUp~ note 11, pp. 728-731.
,—

Chapter 7–Federal Programs I 173

Figure 74-Federal Power Marketing Administrations Service Areas

l+), L-q&

/

/

v

c+

., .*-

WAPA

A PA

BPA

SEPA

SWPA

Western Area Power Administration

Alaska Power Administration

Bonneville Power Administration

Southeastern Power Administration

Southwestern Power Administration

Area served by both SWPA and WAPA

\

,,.r

>

SOURCE: U.S. Department of Energy, The Secretary’s Annual Report to Congress 1990, DOE/6-OO1OP (91 ), p. 160.

generation and over two-thirds of the electric

operating revenues reported by the Federal electric utilities.67

While TVA’s regional development programs

are financed by congressional appropriations, the

power program is required by law to be financially self-supporting through power sale revenues. Rates are to be set to cover capital and

operational costs. Power system operations account for over 95 percent of the TVA budget.

In addition to hydroelectric plants, TVA maintains coal-fired powerplants, nuclear powerplants,

combustion turbines and pumped storage systems

68 Table 7-9 provides statistics in its capacity base.

Figure 7-States in the Service Area of the

Tennessee Valley Authority

)“7 .

SOURCE: Office of Technology Assessment, 1993, based on data

from the Office of Federal Register, The United States Government

Manual 1991/92 (Washington, DC: U.S. Government Printing Office,

1991).

67 Fi~ncial Statistics of ~ekctedpub[ic[y Owned E/ectric Utilities 1990, SllpHl llOk j~, P. 337.

68 co~-f~ed steam plants now account for 55 percent of TVA’s capacity and provide about 70 percent of the dtily load. TO Wmply wifi

regulations required by the 1990 Clean Air Act Amendments, TVA estimates that it will invest more than $1 billion on new pollution control

technologies by 2000, increasing annual operating costs by $300 million. William Malec, “TVA Re-Examm“ es the Nuclear OptiorU’ Forum

for Applied Research and Public Policy, winter 1991, p. 89.
174 I Energy Efficiency: Challenges and Opportunities for Electric Utilities

Table 7-9-Tennessee Valley Authority Power

System Statistics, 1990

Power system operators Million kWh

System sales

Municipalities and cooperatives. . . . .

Federal agencies. . . . . . . . . . . . . . . . .

Industrial customers. . . . . . . . . . . . . . .

Total sales. . . . . . . . . . . . . . . . . . . .

Power delivered under cogeneration

agreement. . . . . . . . . . . . . . . . . . . . . . .

Losses, etc.. . . . . . . . . . . . . . . . . . . . .

Total system output. . . . . . . . . . . .

System generation by source

Hydro (includes pumped storage)....

Coal-fired. . . . . . . . . . . . . . . . . . . . . . . .

Nuclear. . . . . . . . . . . . . . . . . . . . . . . . . .

Combustion turbine. . . . . . . . . . . . . . .

Total net generation. . . . . . . . . . . .

Purchased power. . . . . . . . . . . . . . . .

Net Interchange and wheel ing. . . . .

Total system Input. . . . . . . . . . . . .

96,748

2,336

17,134

116,483

1,168

3,135

120,768

21,654

78,504

15,275

203

115,636

959

4,191

120,786

SOURCE: Office of Technology Assessment, 1993, based on data

from Tennessee Valley Authority 1990 Annual Report, November

1990.

on the TVA power system. TVA also coordinates

power output from Corps of Engineers dams in

the Cumberland Valley and from Aluminum

Company of America dams.

In the recent past TVA ran extensive energy

conservation programs. However, in 1989 most

of these efforts were terminated by TVA’s board,

citing the financial stresses facing the system.

From 1985 to 1988, TVA rate hikes averaged 4.5

percent a year as the result of a combination of a

problematic nuclear program, expensive repairs

on coal-fired plants, and diminished hydroelectric

production because of drought.69 TVA’s management felt its customer base was threatened as

some of TVA’s largest customers, including

Memphis Light Gas & Water, which then accounted for 10 percent of kilowatt-hour sales,

began to explore alternative power supply options.

To secure its base of distributors, TVA promised to freeze electricity rates for three years

beginnin g in 1988. Among the various actions

taken to reduce operating costs was elimination of

most energy conservation programs. TVA officials gave two reasons for discontinuing conservation programs. First was the pledge not to raise

rates for the 3-year period. TVA’s managers

reasoned that if sales declined because of successful conservation efforts, rates would likely have

to increase as fixed costs were spread over fewer

sales. TVA feared that increased rates would

induce large customers to leave the system,

leading to further decline in sales. Second, TVA

cited an internal analysis that concluded that it

had exhausted cost-effective conservation options. 70 In TVA management’s view, finishing

the partially complete nuclear plants offered more

cost-effective options than continuing conservation programs to meet future electrical supply. In

the summer of 1988, the TVA board of directors

approved a transition program that began cutting

the conservation staff. In 1989, then TVA Chairman Marvin Runyon stated: ‘‘Conservation will

add to our rates. ’ ’71 In spring 1989, the board

voted to terminate residential conservation programs, cut personnel from 600 to 280, and reduce

the budget from $40 to $20 million.72

Prior to termination, TVA conservation programs were among the most extensive in the

country, saving an estimated 913 MW in an

8-year period from home weatherization programs alone. 73 Average annula electricity use for

69 Roger L. Cole ~d ~‘. ‘we! “The Power to Change: The Case of TVA, ” Training and Development, August 1991, p. 59.

TO WMessee ~ley AU~Ori~, TVA Power Group, Power Planning, attachment in Hearings on WA COnSefVUticVI %OgW?L$ ~fore tie

Subcommittee on Energy and Power of the House Committee on Energy and Commerce, IOlst Cong., 1st sess., June 29, 1989 (serial no.

101-60), pp, 190202.

71 ~~ony of Marvin Runyon, Chairman , lkrmessee Wiley Authority, ibid., p. 148,

72 Jfi CNpm, U.S. Repre~n~tive, ”~t Is TVA’s New Policy on Energy Con.servatioq ” ibid, pp. 16-21.

73 ~meS5ce ~le. Au~ori~, “EnerU s~ices Repofl ‘gT,’ ‘ NA/Op/~HS/lT, 1988, p, 43.
Chapter 7–Federal Programs I 175

Table 7-10-Tennessee Valley Authority Major Energy Conservation Programs,

Fiscal Years 1977-87

Estimated Estimated

Number of Dollars annual cumulative

Energy services Installations loaned savings (kWh) savings (MW).

Residential

Home weatherization. . . . . . . . .

Sunscreens. . . . . . . . . . . . . . . .

Heat pumps. , . . . . . . . . . . . . . .

Heat-pump water heaters. . . . .

Wood heaters. . . . . . . . . . . . . .

“Cycle and Save”

Air conditioner cycling. . . . . . . .

Water heater cycling. . . . . . . . .

“Energy Saver” homes. . . . . . .

Commercial and Industrial

Energy management surveys. .

Other programs, . . . . . . . . . . . .

Total. . . . . . . . . . . . . . . . . . . . . . .

601 ,282b

2,626

53,103

1,504

16,246

53,287’

57,037 d

22,518

26,500

n/a

834,103

$375,001,000

490,000

166,555,000

1,108,000

4,484,000

.

—

—

4,947,000

n/a

$552,585,000

1,802,300,000

2,100,000

188,500,000

4,100,000

79,100,000

—

99,900,000

838,600,000

50,200,000

3,064,800,000

913.0

1.0

58.4’

0.8

55.4

54.0

79.4

30.8

173

14

1,411

aValues shown are maximum seasonal reductions.

blncludes residences weatherized with TVA loans, without TVA loans, and residences weatherized in a joint effort

with Community Action Agencies.

cDoes not include switches installed on 12,324 heat pumps.

dDoes not include 2,882 switches installed on solar water heaters Or 75 switches on heat pump water heaters.

‘Refers to number of buildings surveyed.

lncludes savings attributable to "Cycle and Save” switches.

SOURCE: Tennessee Valley Authority, “Energy Services Report, 1987,” TVA/OP/CEM-88/17, p. 43.

TVA residential customers was 50 percent higher

than the national average due to the large number

of homes heated by electricity .74 Residential

customers received services ranging from free

audits to interest-free loans to financing for

installation of conservation measures. In 1987,

TVA celebrated the completion of 1 million home

energy surveys. TVA had an extensive engineering staff assisting individual commercial and

industrial customers with tailormade conservation programs. Additionally, industrial customers

were eligible to receive information on relevant

new technologies from TVA representatives.

TVA also participated in a number of energy

efficiency R&D efforts. TVA demonstration programs showcased innovative home designs, new

water heaters, radiant barriers, and photovoltaics

and helped confirm the cost, reliability, and

availability of these emerging technologies.75

Table 7-10 highlights the major conservation

programs pursued by TVA.

After 1989, the programs remaining in TVA’s

conservation budget are primarily educational

and information programs and strategic load

management. The information programs include

distributing energy sourcebooks and other teaching materials, and operating a TVA energy center

for teachers and students. The consumer energy

efficiency information program provides brochures to customers on appliances. The Energy

Management Program provides technical assistance to Tennessee county governments in identiT4 Atjout @ Wment of TVA r~idential customers rely on electric heat compared with 20 percent of homes nationally. mid., p. 6.

75 Ibid., pp. 1-34.
176 I Energy Efficiency: Challenges and Opportunities for Electric Utilities

fying opportunities for installation of energysaving measures financed with State and Federal

conservation funds.

The load management programs are designed

to maintain and expand TVA’s customer base

load. In the industrial sector, TVA is encouraging

the use of electrotechnologies. In the residential

sector, the focus is on promoting construction of

all-electric homes. TVA “energy conservation”

programs have effectively shifted in focus from

saving kilowatt-hours to strategic load marketing

and demand growth.

The Industrial Energy Services program is a

technical assistance program that works with the

largest industrial customers to determine their

energy requirements. TVA personnel then identify how to meet energy requirements costeffectively and promote use of electrotechnologies. TVA estimates that 20 percent of activity in

this program is concentrated on energy efficiency

improvements.76

In 1989 TVA established the Residential Energy Service Program (RESP), which provides

technical and financial assistance for installation

of energy-efficient electric heat pumps, and

information on electric hot water heating systems.

RESP is currently budgeted at $10.5 million.

TVA offers bounty payments to distributors who

successfully encourage construction of new allelectric homes.77 RESP was designed to “help

TVA maintain a desirable balance between summer and winter peaks by helping maintain winter

water heating and space heating loads. ”78 TVA

provides the loans and support materials to its

distributors which are responsible for the administrative costs. If a distributor does not participate,

customers in its service area are not eligible for

the loans.79

Under the stewardship of Marvin Runyon,

TVA was poised to expand its generating capacity

and “committed itself to nuclear power as an

integral source for meeting the energy needs of its

service area.”80 TVA demand is growing 1.5 to 4

percent a year according to TVA load forecasts.

TVA plans have called for completing four

nuclear powerplants currently in the construction

or licensing stage by 2000.81 With the five units

already licensed, TVA anticipates that nuclear

power will supply 40 percent of its annual

generation by 2000. This additional power will be

used to meet projected growth in demand.82

With passage of the Energy Policy Act of 1992,

TVA’s determination to eschew energy efficiency and build new nuclear generating capacity

may be stalled and its future path redirected.

Section 113 of the act requires TVA to establish

a least-cost planning program to develop a

resource plan with the lowest system cost.83 The

planning process must consider supply and demand resources, including renewable resources,

energy conservation and efficiency, on a consistent and integrated basis. TVA must incorporate

opportunities for its distributors to recommend

cost-effective energy efficiency opportunities,

76 ~essee ~ey AIIrhority, at~chment to testimony, in Hearings on TVA Conservation programs, SUpm 130te TO, at p. 160.

77 Repofi mbmittd by Represm~tive Jim Cooper, Hearings on TUA COnserVatiOn prOgra?nS, SUp~ note 70, pp. 17-21.

78 Ibid, p. 17.

‘g Ibi~ p. 16-25.

80 w~~ ~= (Se~or Vim ~~ident ~d ~ef F~c~ ~~r, ~~essee ~ley AU~(Jri&), ‘ ‘WA MS Not N~(j m Be

Privatize&” Public Utilities Fortnightly, Feb. 15, 1991, p. 28.

at ~ ~ly 1993 WA’S b~ vot~ to prowed with Consmction of the mothballed unit of the Bellefonte nuclear plant finish work on two

units at Browns Ferry, and bring Watts Bar Unit 1 on line in 1994. Ed Lane, “In Debt and OH Line: Uncertain Future Faces Nuclear-Driven

TVA,” Energy Daily, May 4,1993, pp. 3-4.

S2 WTiU~ F, ~=, “WA Re-~~esthe Nuclear OptiOL” Forum for Applied Research and Public Policy, winter 1991, pp. 87-90.

s3 ~bficbW 1m4t3tj, &t. 24, 1992, sec. 113, 102 Stat, 2798, 16 U.S.C. 831m-1. !ktion 11303)(3) dcdines syStem cost =”~ ht ~d

quantifiable net costs for an energy resource over its available life, including the cost of production transportatio~ utilization waste

rnanagemenl environmental compliance, and in the case of imported energy resources, maintaining access to foreign sources of supply.”
—-—.———

Chapter 7–Federal Programs I 177

rate structure incentives, and renewable energy

proposals for inclusion in the program.

In planning and selecting new resources, TVA

must evaluate the full range of existing and

incremental resources (including new power supplies, energy conservation and efficiency, and

renewable energy resources) in order to provide

adequate and reliable services to its customers at

the lowest system cost. The act further requires

TVA to provide opportunity for public review and

comment before selection of any major new

energy resource and include a description of the

action in its annual report to the President and the

Congress

TVA was also directed to encourage and assist

distributors in the planning and implementation

of cost-effective energy efficiency options and

authorized to provide a range of technical and

financial services to advance these efforts.

The impact of these requirements on TVA’s

nuclear plans and its conservation programs

remains to be seen. The act set no schedule for

TVA’s least-cost planning process and did not

include any explicit mechanisms for enforcement

or ‘review. TVA is moving forward to develop

expanded energy conservation programs and

preparing comprehensive DSM analyses for the

upcoming integrated resource planning process.84

1 Bonneville Power Administration

BPA, established in 1937, is the Federal

electric power marketing agency in the Pacific

Northwest. 85 BPA markets hydroelectric power

from 21 multipurpose water resource projects of

the U.S. Army Corps of Engineers, and 9 projects

of the Bureau of Reclamation, plus power from

nonfederal generating plants. These generating

stations and BPA’s 14,794 miles of transmission

lines and 389 substations make up the Federal

Columbia River Power System. In marketing its

power, BPA must give preference to publiclyowned utilities and electric cooperatives.

BPA is the largest power wholesaler in the

Northwest, supplying half of the electricity and

operating almost 80 percent of the region’s

high-voltage power transmission capacity. BPA

sells power at wholesale to local utilities and also

provides power to a small number of large

direct-service industrial customers86 and to other

Federal agencies. It participates in seasonal power

exchanges and maintains power coordination and

transfer agreements with utilities in other regions

and in Canada.

Under its authorizing legislation, BPA may

build and operate transmission facilities and

market power, but it is not authorized to build or

own power generation facilities. To meet its firm

power contracts with its customers, BPA supplements its Federal hydropower supplies with

purchases from other utilities. Under the Pacific

Northwest Power Planning and Conservation Act

of 1980, BPA’s selection of nonfederal supply

and demand resources to meet its customers

energy needs is guided by a collaborative planning process.87 The act also gave BPA responsibility for technical and financial assistance for

energy conservation and renewable resource development, and for fish and wildlife protection in

the Columbia River drainage basin.

84 Meg ~K@@t, WA ~vernment Relations Office, Washin@on, DC, ~o~ comm~do~ Aw. 14! 1993.

135 At of August 20, 1937 (The Bonneville Project Act), as amendx 16 USC 832 et seq. BPA serves Oregon md was-on @pof MonU Neva@ Utah and Wyoming.

86 nem ~e ~enfly fewer than 20 direct service customers, but when they are operating at capacity, they account for some 17 pement of

BPAs power sales. 7%ey include anumberof electricity-intensive industrim: alumin um smelters, electroprocessing plants, pulp and paper mills,

and chemical companies. Northwest Power Plann@g Council, 1991 Northwest Conservation andEfectnc Power Plan, vol. 1,91-04 (Portland,

OR: Northwest Power Planning Council, April 1991), p. 9.

87 Pubfic ~W %-501, 94 Stat. 2697, Dec. 5, 1980, 16 U.S.C. 839-839h.

88 HOU% Report No. %976, Rut 1, %th Cong., 2d sess., May 15, 1980, PP. 23-30.
178 I Energy Efficiency: Challenges and Opportunities for Electric Utilities

The House Report provides some of the background history that led to the legislation. 88 For

over 40 years, the Columbia River system was

able to provide the power requirements of BPA’s

preference customers, Federal agencies, investorowned systems, and direct-service industrial customers. The region enjoyed some of the lowest

electric rates in the country. In the 1970s, growing

power demand was outstripping BPA’s ability to

meet customer needs from available hydroelectric

resources. Extensive hydroelectric development

also was blamed for declines in the region’s fish

and wildlife, and corrective measures to protect

salmon and other species would reduce water

flows for power generation. The BPA administrator warned that threatened power shortages could

force it to curtail firm-power sales to investorowned utilities and direct-service customers and

to allocate available resources among the preference customers. To avoid this, BPA and the

region’s utilities then set forth on an effort to add

nuclear and coal-fired generating plants owned by

nonfederal entities to the Federal system. To help

finance this capacity expansion, BPA entered into

agreements with its preference customers that

obligated BPA to purchase power generated from

the new plants. In return, the selling utilities

would receive credits on charges for power

purchased from BPA.

89 However, this financing

mechanism was foreclosed for additional resources by an adverse ruling by the Internal

Revenue Service. Subsequent efforts also were

derailed. The region’s utilities and regulators

scrambled to find some way to preserve their

shares of BPA’s low-cost hydro resources. At the

same time, the cost of building new generating

resources was climbing. By the late 1970s, BPA

was selling wholesale electricity at 8 mills per

kWh ($0.008/kWh) while power from new thermal powerplants would cost 10 times as much.

The alternative of energy conservation, was being

ignored, despite the existence of several successful programs demonstrating cost-effective electricity savings. Desperate for a solution, the actors

turned to Congress.

The prescription was the Northwest Power Act

of 1980. The House Committee report diagnosed

the region’s problems as follows:

The opportunity for conservation of electric

power in the region is great. Kilowatts saved cost

a small fraction of the cost of producing an

equivalent amount of kilowatts. All concede that

a vast potential for energy conservation is being

wasted in the region.

As the costs of new generation have increased the

potential for cost-effective conservation programs in the region have also increased. Unfortunately, the region appears to lack mechanisms to

undertake an effective regional conservation effort. BPA has limited authority to carry out

conservation programs, and no authority to borrow or underwrite funds to finance these programs. Individual utilities (particularly publicly

owned systems) face many legal and practical

problems which limit their conservation efforts.

Further, under current conditions it could be

several years before many customers of BPA

preference customers will face the kind of price

signals that would encourage them to invest

money in cost-effective conservation measures.

. . . In the absence of a coordinated regional power

program, it is probable that conservation efforts in

the region will be too slow, too scattered, and too

modest to be effective; and the region would thus

lose a good portion of conservation’s potential

economic benefit.90

The report concluded:

The certain inability of the region to resolve its

problems without legislation represents a serious

economic, social, and environmental threat to the

SE Home Rqofi No. 96-97(j, Part I, %th COW., 2d .WSS., my 15, 1980, PP. 23-30.

W ~s mw~sm WM USed to f~ce three nuclem units of the ill-fated Washington Public Power System with BPA effectively

guaranteeing repayment of bonds issued to pay for construction.

90 HOUS.S Report 96-976, supra note 88, P. 26.
Chapter 7–Federal Programs I 179

region, and by implication to other regions of the

country. The continued failure to use existing

resources and conservation effectively and to plan

efficiently for future needs raises the potential of

severe regional electrical power shortages in this

decade.91

The solution was to create a public planning

process enabling States, localities, consumers,

BPA customers, fish and wildlife agencies, Indian

tribes, users of the Columbia River System, and

the public to participate in the region’s electric

power decisionmaking process. The act authorized BPA to acquire additional resources on a

long-term basis, consistent with the regional plan,

and giving frost priority to conservation and

renewable resources. It also clarified BPA’s

authority to enter firm power sale contracts with

investor-owned utilities and direct service customers.

In form and practice, the regional planning

process used by the Pacific Northwest Planning

Council and BPA resembles utility IRP processes

in wide use today. In 1980, however, the act

marked a bold innovation in Federal and State

collaboration. The act also required that conservation be treated as a resource, and that all resources

be evaluated to determine the best and lowest-cost

alternatives to meet the region’s electricity needs.

In planning and selecting resources, priority was

to be given first to conservation; second, renewable resources; third, generating resources utilizing waste heat or generating resources with high

fuel-conversion efficiency; and fourth, all other

resources, including conventional thermal powerplants.

92 

BOX 7-F summarizes the planning process created by the act and the results of BPA’s

most recent resource plan.

BPA CONSERVATION ACTIVITIES

The Northwest Power Act of 1980 directed

Bonneville to use conservation to the fullest

extent possible in its resource mix and authorized

a wide range of technical and financial assistance

to encourage energy efficiency and renewable

energy development.

BPA has had more than a decade of experience

in developing, administering, and evaluating

energy conservation programs. Its programs are

extensive and serve customer utilities, residential,

commercial, and industrial consumers, and State

and local governments. Customer outreach provides technical and financial assistance for conservation measures. BPA pays part of the cost of

residential weatherization. Hotlines inform commercial and industrial customers about emerging

energy-efficient technologies. BPA has assisted

State and local governments with the development and implementation of model energy conservation codes, and offered financial incentives

to jurisdictions that adopt and enforce the codes.

BPA also has underwritten extensive demonstration programs to test energy-efficient technologies and provide cost and performance information to their utility customers and others.

BPA’s resource plans and energy conservation

experience also contribute to the system’s flexibility in responding to changing conditions. In

April 1993 BPA outlined a number of emergency

measures intended to head off or reduce a

potential 25 percent rate hike on October 1, 1993.

Among the circumstances that have contributed

to the financial crisis were a drought that decreased sales and required BPA to purchase

replacement power to meet its loads and the loss

of one-quarter of its direct sales to aluminum

companies. In an attempt to hold the price

increase below 20 percent, BPA announced that

91 Ibid, p. 27.

92 pJ~fiWeSt poWerp-and conse~ationAct, fibfic ~W 96-501, 1980, SW. 4.(C)(1). me d~tition of cost-effective in the aCt

provides a 10 percent cost advantage to conservation resources. Section 3(4)(D) provides: “A conservation measure or resource shall not be

treated as greater than that of any non-conservation measure or rwource unless the incremental system cost of such conservation measure or

resource is in excess of 110 per centum of the incremental cost of the non-conserv ation measure or resource. ” 16 U.S.C. 839a(4)(D).
180 I Energy Efficiency: Challenges and Opportunities for Electric Utilities

Box 7-F--Regional Power Planning: The Bonneville Power Administration and the

Pacific Northwest Power Planning Council

‘Ten years ago, the Pacific Northwest embarked on a grand experiment It was a test initiated by the

Northwest Power Act of 1960, to determine whether four states, sharing common needs and assets,

could coordinate their efforts to ensure their people energy services at the Iowest possible cost."1

Northwest Power Planning Council, April 1991

The Northwest Power Planning Council

The Pacific Northwest Electric Power Planning and Conservation Act of 19802created the Northwest Power

Planning Council to develop a long-term regional conservation and electric power plan to guide the Bonneville

Power Administration’s resource planning and selection. The act requires that BPA's resource acquisition be

consistent with the cOUncil'S recommendation and resource acquisition proposals must have council approval.3

The plan is to be updated at least every 5 years. The Council is authorized to monitor and report on implementation

of the resource plan and efforts at depbyment of conservaton and renewable energy resurces in the region. The

act also gave the Council responsibility for developing a program to protect and enhance fish and wildlife and

related spawning grounds and habitat on the Columbia River and its tributaries.4

Collaboration between State and Federal agencies and public review and involvement are key features of

the Northwest planning process. The Council consists of two members each from Washington, Oregon, Idaho,

and Montana Council members are appointed by the Governor of each State. The act provides for public hearings

on the proposed plan and for an ongoing public information and outreach program to involve State and Federal

agendas, Indian tribes, customers, and the public In the planning process.

The Planning Process

The act specifies that the regional conservation and electric power plan must contain:

1.

2.

3.

4.

5.

6.

7.

an energy conservation program, including model energy Conservation standards;

recommendation for research and developmet,

a methodology for quantifying environmental costs and benefits in evaluating the cost-effectiveness of

resource options;

a 20-year demand forecast covering the amount and types of resources needed to rneet BPA obligations

impacts of fish and wildlife protection, and estimates of the resources to be acquired on a long- term basis;

an analysis of the resources required to assure adequate and reliable electric power at the lowest probable

cost and the met-effective means of providing them;

the fish and wildlife protection, mitigation, and enhancement program; and

recommendations, if any, for surcharges to be imposed on customers not implementing energy

conservation standards.5

Energy conservation and renewable energy resources are given the highest priority for new resources. The act

provides that conservation resources are to be given a 10 percent advantage in cost-effectiveness determinations.

The Council has developed three regional power plans. The most recent one was released in April 1991.

The 1991 Northwest Conservation and Electric Power Plan sets forth the planning council’s estimates of

power needs and recommendations for resource acquisition.6

The early plans weredeveloped during a timewhen
Chapter 7–Federal Programs I 181

the region faced an energy surplus from the overbuilding in the 1970s. The 1991 plan addresses a tightening power

supply. The plan forecasts a potential for a capacity deficit by the turn of the century unless new resources are

acquired.

The plan analyzed a number of electricity demand growth scenarios ranging from one where average demand

declines at a rate of-0.4 percent per year to one with a high growth rate of 2.5 percent per year, however more

emphasis was placed on mid-range growth levels of 0.6 to 1.7 percent per year. 7 The council developed several

alternative resource portfolios containing various mixes of supply and demand resources capable of meeting the

full range of energy demand reflected in the scenarios. Potential supply and demand resources were evaluated

by examining total costs including direct costs and enviromnental impacts, and reliability. Other evaluation criteria

included lead times, size, and capital cost. Based on its analysis and public comment, the council plan adopted

four objectives for a regional energy strategy.

1.

2.

3.

Acquiring all low-cost resources-The plan recommends that BPA and regional utilities acquire 1,500

average megawatt (aMW)8 of conservation and energy efficiency improvements at a total cost to utilities

and customers of $7 billion (see figure on next page). This would entail aggressive efforts to install

efficiency measures in the residential, commercial, industrial and agricultural sectors at a level many times

greater than current DSM and conservation programs. Efficiency improvements in powerplants,

transmission, and distribution facilities would contribute 360 aMW of conservation savings. In addition, the

plan callsfor 150 aMWof new, Iow-cost hydropower and 650 aMWof Iow cost industrial cogeneration by

the year 2000.9

2. Shortening lead times needed to bring new resources into operation to enable quick and flexible

responses to rapid load growth. The plan would reduce lead times by beginning inexpensive

pre-construction preparations such as siting, permitting, licensing, design, contracts, and other approvals

to enable addition of 100 aMWof new hydropower and up to 750 aMW of cogeneration to resource plans

if demand growth is higher than anticipated. These pre-construction activities often are among the most

time-consuming in developing new power resources. The council also recommends that BPA and utilities

investigate cost- effective backup power supplies for 1,500 aMW of the region’s non-firm hydropower to

accommodate potential impacts of fish and wildlife protection programs. Good candidates for

“hydrofirming” include interregional energy transactions, increased interruptible loads and gas fired

combustion turbine plants.10”

Confirming the cost and availability of additional resourocs that could be incorporated into future

plans--The plan callsforsupport of research, development, and demonstration efforts for resources that

are not yet ready for utility-scale deployment including new energy conservation and renewable energy

technologies (such as geothermal, wind, and solar generating technologies). Additionally, the council

requests that BPA determine whether the continued preservation of its two uncompleted nuclear power

plants remains a prudent insurance policy.11 The council also suggests that BPA investigate

7 Ibid., p. 17.

8 ~~rqe megawatt (aMw) is 8J7W megawatt-hours of_ or the amount of energy produced by

continuous operation of 1 megawatt of generating capadty over a year. It Is distinct from a megawatt or MW used

to refer to @@ty, the maxinwm output of an electrical generator. Because most generators do not run

continuouety, securing 1 aMW of resources may require acquisition of more than IMW of capadty.

9 Ibid., pp. 31-36

10 Ibid., pp. 36-38.

11 ibid., pp. 38-43. in Aprii 1993, the Washington Pubiio PHr Supply Sy8temhgan fxqingstofor~ily

terminate *partially completed nudearpowwpiantthat had been preserved in an unfinished condition simx 1983.

BPA is guaranteeing repayment of some $4.6 bllllon In revenue bonds sold to finance construction, It Is estimated

that more than $3 blIlion would benecessarytocompiete the plants. BPAandregional planners have conc!udedthat

more than 5,000 MWfrom other sources at prices of $0.03/kWh making electridty from the two nuclear plants at an

estimated $0.04MVh uneconomic.

(Continued on next page)
182 I Energy Efficiency: Challenges and Opportunities for Electric Utilities

Box 7-F–Regional Power Planning: The Bonneville Power Administration and the Pacific

Northwest Power Planning Council--Continued)

Recommended Resource Acquisitions of the

1991 Northwest Conservation and Electric Power Plan

- Transmission upgrades %

235 Mw

,,,, \N Efficient businesses

435 MW

,“, W, ,,,a, , ,,3

15 M W

Efficient homes

495 MW

SOURCE: Office of Technology Assessment, 1993, from Northwest Power Planning Council, 1991 Northwest Conservation and

Electric Power Plan, vol. 1,91-04 (Portfand, OR: Northwest Power Planning Council, April 1991), figure 17, p. 33.

4.

rapid-response resources replace 500 to 1,000 aMW of existing generating capacity should the need

arise. Rapid-response resources include acquisitions through bidding, and alterations to existing

combustion turbine resources. The council states that “if sufficient rapid-response resources cannot be

identified, it may be necessary to seek interruptible loads and develop curtailment strategies until

resources with longer lead times can be added.”12

Encouraging regulatory and other lnstitutional changes to help implement theplan--The plan details

recommendations for a variety of actions by BPA State regulators, utilities and Iocal governments to ease

the implemental’bn of the council plan. Among the suggestions are that regulators consider changes to

decouple profits from the energy sold and relink profits to energy saved and review policies to ease the

siting and acquisition of generating resources. Regulators were encouraged to consider appropriate rate

treatment for investing in activities that reduce resource lead times, and for participation in research

activities to confirm/deny potential resources. Lastly, the council urged cooperation between regulatory

12 Ibid., pp. 31-43.
Chapter 7–Federal Programs I 183

agencies and Bonneville in the issue of transmission access for non-utility generators.13

Responsibility for implementing the plan is shared by BPA and region’s regulators and utilities backed by

support of environmental, consumer groups and the public. The Council notes that it will monitor progress in

addressing these recommendations.

BPA’s 1992 Resource Program

Every two years BPA issues a 10-year resource program outlining its proposals for meeting electricity loads.

The November 1992 resource program was the first adopted after the 1991 Northwest Power Plan and identifies

conservation as its preferred resource. BPA assumed a 1 percent annual growth rate and proposed acquiring

1,530 aMW. In doing its part to meet regional electric needs, BPA proposes to:

● acquire all cost-effective conservation-targeting 880 aMW of conservation and 120 aMW of power system

efficiency improvements through 2003 in its public utilities service areas (estimated cost $2.8 billion);

■ acquire an additional 400 aMW of new generating resources to meet the most likely range of need through 1998;

and

• purchase 250 aMW of options (rights to buy firm power at a specific time) to cover the outer range of need. 14

BPA also plans to secure 1,050 aMW in options and contingent resources to provided needed capacity if

demand growth is higher than forecast. BPA will reserve the right to cancel selected projects on option in exchange

for reimbursing the sponsor’s pre-development costs.

To accomplish its goal of accelerated acquisition of conservation resources, BPA is making major changes

in the operation of its conservation programs and how it pays for energy savings. Program development and

decisionmaking will shift from headquarters to BPA area offices which will collaborate with utilities and local

communities in designing and implementing local conservation plans. Under the Northwest Power Act BPA can

pay utilities and others for conservation resources that reduce BPA’s loads. BPA anticipates securing conservation

resources through:

z utility adoption of BPA-sponsored programs;

= utility reimbursement for costs of program administration and conservation measures installed; and

~ utility or energy service company compensation for installation of conservation measures based on kwh saved.15

Instead of paying up-front, BPA plans to shift to pay-for-performance contracts that purchase measurable

savings over time. Verification of energy savings will be required in the performance contracts. BPA expects utilities

to provide a substantial portion of the necessary capital for installing conservation measures rather than relying

on BPA to provide financing. BPA also will continue to require utilities that own generation to pay a percentage

of the cost of conservation in their service area, based on the percentage of the utility’s load supplied by BPA. This

cost-sharing is required so that nongenerating utilities do not pay a disproportionate share of conservation program

costs. For some utilities, current cost-sharing percentages have, however, created a financial impediment to

meeting accelerated conservation targets and BPA is investigating alternative mechanisms for an equitable

sharing.

The accelerated conservation path and will face several challenges. There will have to be unprecedented

cooperation among all groups in the region to identify and install all commercially available cost-effective

conservation measures. Utilities and governments will need greater staff, technical, and financial support from BPA

to develop and carry out local conservation programs. Regulators will have to review policies and rate structures

for possible conflicts with conservation goals.16

13 Ibid., pp. 43-44.

14 Bonneville power Administration, 1992 Reset.mx Program--10 Year Plan, Draft II DOE/BP-1874

(Portland, OR: Bonneville Power Administration, May 1992), p. i, Draft II insubstantially identical to the final resource

program released in November 1992.

15 Ibid., p. 48.

16 Ibid.r pp. 26-33. (Continued on next page)
184 I Energy Efficiency: Challenges and Opportunities for Electric Utilities

Box 7-F–Regional Power Planning: The Bonneville Power Administration and the Pacific

Northwest Power Planning Council--(Continued)

Savings to Date

In the view of the Northwest Power Planning Council, the act’s grand experiment has been a clear success

for the people of the Pacific Northwest:

‘This region is convinced! Every Northwest utility is promoting efficiency through marketing programs

and incentives. They have already saved more than 350 megawatts at a cost less than half of the power

from a new generating plant Aluminum companies also have cut their consumption. And state energy

office programs brought Us another 200 megawatts.

New energy-efficient building codes and appliance standards already adopted by Federal, State and

local governments can save the region more than 1,300 average megawatts by the year 2010.

In addition, if the region captures all the energy savings described in thisplan over the next 20 years,

it could add another 4,600 megawatts of conservation.”17

17 1991 Northwest Conservation and Electric Power Plan p. 20.

SOURCE: Office of Technology Assessment, 1993.

it is cutting all programs by 25 percent, including important link in regional power systems. Westconservation and fish and wildlife activities, and em serves some 532 wholesale customers, mostly

administrative programs by 50 percent. The cuts public power systems and electric cooperatives

are not expected to change BPA’s resource supplying over 10 percent of the region’s needs.%

program goals, but likely will result in deferrals Other purchasers include investor-owned utilities

and slowdowns in prgram growth. and Federal and State agencies. Western supplies

an average of 35 percent of its customers’ power

I Western Area Power Administration needs. 95

WAPA was established in 1977 under section

302 of the Department of Energy Organization

Act to market power in a 15-State area generated

from federally-owned powerplants operated by

the Bureau of Reclamation, Corps of Engineers,

and the International Boundary and Water Commission. 93 It also markets Federal entitlement

power from the coal-fried Navaho Generating

Station. WAPA operates and maintains 16,500

miles of transmission lines, plus associated substations to deliver power to its customers. Like

BPA, Western’s transmission resources are an

In 1981 WAPA established its own conservation and renewable energy program with three

objectives:

1.

2.

3.

reducing wasteful uses of electricity

through energy conservation;

enhancing the place of electricity in the

energy market by making uses of electric

power more efficient; and

ensuring that conservation and renewable

energy technologies are fairly compared

95 Bill Clage~ Administrator, Western Area Power Admxu“ “stration, letter to O’IX, Sept. 18, 1992.
Chapter 7–Federal Programs I 185

with conventional resources when additional power is required.96

Title II of the Hoover Power Plant Act of 1984

essentially confined Western’s conservation and

renewable energy program and its pre-existing

authority to condition contracts for Federal hydropower on customer adoption of conservation

programs.

97 Indeed, the act explicitly requires

new firm power contracts with WAPA to contain

provisions obligating the purchaser to implement

energy conservation programs. Unlike BPA, Western is not required to meet wholesale customer

load growth, however, it must purchase power to

make up for short-term power shortages in

drought periods in order to meet its firm power

contractual commitments. Western can withhold

power from a customer that has not implemented

conservation programs or that do not submit a

plan within a year of signing a power contract.

Following the 1984 legislation, WAPA published amended guidelines and criteria for evaluating the adequacy of customer utilities’ conservation programs.

98Long-term firm power customers must submit a plan describing qualifying

program activities, the implementation schedule,

targeted goals, and energy savings estimates

where feasible. Qualifying customer programs,

include: energy consumption efficiency improvements; production efficiency improvements, load

management, cogeneration, rate design improvements, and renewable energy resources (wind,

solar, biomass, small-scale hydro, and geothermal

technologies). Western allows considerable flexibility in program design. The acceptability of

customer conservation and renewable energy

plans is determined based on utility type and total

system sales. For example, most customers with

over 100 gigawatt-hours (GWh) per year in sales

have been required to implement five individual

programs. Customers with sales of less than 50

GWh per year need only submit three programs

for acceptance.

Western provides additional support to customer utilities through a variety of information

and technology transfer activities: workshops,

information services, publications, direct technical assistance, onsite visits, equipment loans, and

IRP computer software. Under a “peer matching’ effort, Western has matched small customer

utilities to others with first-hand experience and

expertise in conservation and renewable energy

technologies. This has been particularly helpful to

small rural communities with limited staff and

resources.

Estimates of energy or capacity savings resulting from the Western’s requirements are not

available at present. Western measures program

accomplishments by the number of approved

ongoing annual customer conservation and renewable energy activities. For FY 1992, Western

reports almost 100 percent participation by the

nearly 800 customers, with a total of 3,200

separate approved activities.99 In any event,

Western believes that because Federal hydropower is a low-cost resource, customer conservation activities would likely not be used to reduce

their power purchases from WAPA, but rather to

offset their own higher-cost thermal power supplies from utilities’ own generation or from

others. In 1990 electricity savings from operating

conservation programs were insufficient to offset

the power loss caused by drought conditions.

Western spent an additional $267 million for

power purchased during the drought.l00 Because

96 Ibid.

97 mbtic Law 98.381, Aug. 17, 1984, 98 Stat. 1333-1342, 42 U.S.C. 7275. Pre-existing conditioning authority was derived from the

Department of Energy Organization Act 42 U.S.C. 7101, et seq., and the Reclamation Act of 1902, as amended.

98 so Fed. Reg. 33,892-33,899, Aug. 21, 1985.

99 Bill Clage~ Administrator, Western Area Power Administration, letter to OIA, Sept. 18, 1992.

lm Gener~ Accounting WIM, ‘‘Utility Demand-Side Management Programs Can Reduce Electricity Use,’ GAO/RCED-92-13, October

1991, p. 33.
186 I Energy Efficiency: Challenges and Opportunities for Electric Utilities

of Western’s statutory responsibility to market

available Federal hydropower and contractual

obligations to supply power to its customers

(including replacement power supplies in times of

drought), customer DSM programs will not reduce the amount of power that Western markets.

They may, however, allow that low-cost resource

to serve a higher portion of customer requirements and to be shared more equitably.

Proposed revisions to WAPA’S conservation

program begun in 1990 and now under review

would add requirements for adoption of IRP

programs and also would require customers to

quantify energy and capacity savings from their

programs. Changes would also directly link

allocation of hydro resources to long-term planning and efficient use of resources and impose

surcharges on customers that did not comply.l0l

Many elements of WAPA’S proposed Energy

Plannin g and Management Program were adopted

by section 114 of the Energy Policy Act of 1992,

which amends the Hoover Power Plant Act of

1984 to add a new title on IRP. WAPA must

promulgate rules within 1 year amending renewable resource and conservation plan requirements

for its long-term firm power customers to include

provisions calling for customer utilities to implement IRP within 3 years. WAPA is to provide

technical assistance to customer utilities in developing IRP programs and review the plans prepared. Definitions of IRP, system costs, and

least-cost resource options in the act require

evaluation of supply and demand resources in a

consistent, integrated manner to select options

that minimize life-cycle costs including adverse

environmental effects, and give priority to energy

efficiency and renewable energy to the extent

practicable. Failure to submit a plan or to comply

with an approved plan will trigger surcharges of

from 10 to 30 percent on purchases from WAPA.

Alternatively, the Administrator can curtail power

allocations by 10 percent until a customer complies. No penalties will be imposed if the Administrator determines that the utility has made a

good faith effort to comply. Several provisions

were added in recognition of the diversity of

Western’s customer utilities and to avoid duplication of requirements by State regulators or others.

For example, two or more utilities can collaborate

to submit joint IRP plans, and plans prepared

under State or other IRP programs can also be

accepted by WAPA.

1 Southwestern Power Administration

SWPA operates as the marketing agent for

Federal hydroelectric power in a six-State area.102

It was created in 1943 by the Secretary of the

Interior for the transmission and sale of electric

power from certain Corps of Engineers reservoir

projects and assumed responsibilities under the

Flood Control Act in 1944. SWPA has been under

the direction of DOE since 1977.103 Unde r

various authorizing legislation, SWPA’S mandate

is to market Federal hydropower to encourage the

most widespread and economical use at the

lowest possible cost, consistent with sound business principles. 104 SWPA supplements its power

supplies with power purchased from public and

private utilities to meet its contractual obligations. By law, publicly-owned utilities and cooperatives receive preference in power allocations.

SWPA operates and maintains some 1,380 miles

of transmission lines, 24 substations and switching stations, and 39 radio and microwave stations. l05 With these facilities, SWPA sells power

wholesale to public utilities and cooperatives.

SWPA is also responsible for scheduling and

Iol Western Area Power Ah”m”stration UpalXe, June 1992, PP. 1-2.

1~ me Stites are A*, Kansas, Ixmisiarq Missouri, OklAonq and lkxas.

103 Dep~ent of Energy ~g~~tion M, 91 S@t. 578, 42 U.S.C. 7152.

1~ 16 U.S.C. 825s.

105 U.S. Gover~nt Manua/ 1991/92, SUpra note 11, P. 283.
Chapter 7–Federal Programs I 187

dispatching power, negotiating power sales contracts and constructing facilities, and participating in comprehensive planning of water resource

development. Rates to its customers are adjusted

to ensure full recovery of Federal investment.

According to a GAO report, SWPA sought to

clarify its authority to require its customers to

adopt DSM programs. DOE’s Office of Conservation and Renewable Energy responded that

‘‘SWPA has implicit authority under Section 5 of

the Flood Control Act of 1944 to encourage

conservation programs among customer utilities,

and could propose in the absence of more explicit

legislative authority, conservation programs

through rule-making actions, subject to departmental approval. ’ 106 DOE noted, however, that

any attempts to implement programs could be

subject to challenge in the courts.

SWPA supports various activities to encourage

DSM and IRP. It maintains a program to loan

energy-efficient equipment for its customers and

provides technical assistance through workshops.

Together with WAPA and others, it is jointly

funding a project to prepare detailed IRP manuals

to assist utilities in developing and implanting

IRP programs.

1 Southeastern Power Administration

SEPA was created in 1950 by the Secretary of

the Interior to carry out the functions of the Flood

Control Act.107 SEPA operates under the general

mandate to encourage widespread use of electricity from Federal hydro projects at the lowest

possible rates consistent with sound business

principles and to give preference to publiclyowned utilities. Responsibilities include providing for the transmission and sale of surplus

electric power generated at Corps of Engineers

reservoir projects in a 10-State area of the

Southeast. 108 SEPA does not own or operate any

transmission facilities of its own; transmission

lines owned by other utilities deliver the power.

SEPA markets power from a total of 22 Federal

multipurpose water projects, giving preference to

public bodies and cooperatives. Using the region’s large private utilities, SEPA negotiates

wheeling and pooling arrangements to provide

firm power to its customers. Rates charged to

customers are adjusted to ensure that the Federal

Government recovers its investment plus interest.

Oversight of SEPA programs was transferred to

the newly created DOE in 1977.109

SEPA does not have any explicit statutory

mandate to promote DSM, IRP, or regional

cooperation in power planning. However, like

SWPA its authorizing legislation has been interpreted to support initiatives to promote energy

conservation. 110 Southeastern is offering energyefficient training programs for cooperatives and

municipalities.

1 Alaska Power Administration

APA is responsible for the operation and

maintenance of the Snettisham and Eklutna hy -

droelectric generating projects in Alaska and

markets the power produced. APA also operates

associated transmission systems serving Anchorage and Juneau.

For the past several years, DOE has been

negotiating with the State of Alaska to sell the

assets. The Alaska Power Administration Sale

Authorization Act submitted to Congress by DOE

1~ Gener~ Accounting Offia, “Utility Demand-side Management Programs Can Reduce Electricity Use,” GAO/RCED-92-13, October

1991, p. 37.

10753 S@t 39(3.

108 me s~te~ include ~abaa, ~o~d% Gargia, Kenmc@, Mississippi, Nofi C~l@ SOUti CWO@ ‘kKMICXSStX, Virginia, ~d West

V@nia.

IW Dep~ent of Energy @ganization Act of 1977, Public bw 9s-91, m amended, KC. 30Z 42 U.S.C. 7152.

110 Gener~ Accounting Ofllce, ‘‘Utility Derrand-Side Management Programs Can Reduce Electricity Use,” GAO/RCED-92- 13, October

1991, p. 37,
188 I Energy Efficiency: Challenges and Opportunities for Electric Utilities

in June 1992 would sell the 78-MW Snettisham

project to the Alaska Energy Authority and the

30-MW Eklutna project to three electric power

utilities serving the Anchorage area. Over 90

percent of the State’s electricity is now provided

by nonfederal generating sources leading DOE to

conclude that there is no longer a need for

APA. 111

APA has been assisting a customer utility with

evaluating and testing demand as well as supply-

-side energy efficiency measures.

RURAL ELECTRIFICATION

ADMINISTRATION

REA is a credit agency within the U.S.

Department of Agriculture (USDA) that makes

loans and loan guarantees to finance the construction and improvement of electric power systems

to serve the needs of rural areas. The agency was

established during the New Deal to extend

electric service to remote areas not served by

private utilities.

112 REA loans enabled borrowers

to form electric cooperatives to build power lines

for transmission and distribution of wholesale

power purchased from private utilities or from

Federal hydroelectric facilities. REA also guarantees loans made by others, and approves security

arrangements that permit borrowers to obtain

financing from other lenders without a guarantee.113 Since the 1960S, REA has made loans for

the construction of generating and transmission

facilities “to protect the security and effectiveness of REA-financed systems. ’ ’114 REA is also

authorized to provide technical assistance to its

borrowers to aid system development and to

protect loan security. In 1990, there were 897

cooperative borrowers; 838 were distribution

borrowers and the remaining 56 were generation

and transmission cooperatives. (See table 7-12.)

Loans are made through the Rural Electrification and Telephone Revolving Fund created in

1973. By law, REA loans are made at a 5 percent

interest rate and as low as 2 percent for extreme

hardship, and for years REA rates were below the

prevailing market rates for direct borrowing.115

REA requires most borrowers to obtain 30

percent of their financial needs from outside

sources to comply with a statutory requirement

added in 1973 directing REA to encourage rural

electric systems to enhance their ability to obtain

financing from their own financial organizations

or other sources.

116 Many cooperatives obtain this

financing from the National Rural Utilities Cooperative Finance Corporation and the Bank for

Cooperatives.

REA loan guarantees have been made primarily to large-scale facilities and are subject to the

same requirements as direct loans. Interest rates

on guaranteed loans are established at rates set by

the borrower and the lender with REA concurrence. Since 1974, the Federal Financing Bank

(FFB) has purchased obligations guaranteed by

the REA, although all borrower dealings were

with REA. A 1981 amendment to the Rural

Electrification Act required the FFB to make

loans under an agency guarantee if requested to

11 I “F~er~ power proj~ts in Alaska Will Be Sold to Private -em,’ Inside Energy with Federal L.unds, June 29, 1992, p. 7. Proposals

for privatizing the PMAs have been circulating for more than a decade through both the Reagan and Bush Admm“ “strations and have met SW

resistance from members of Congress and the PMAs customers. Of all the proposals, the one to sell APA has been the least controversial.

112 R@ J71~~~~ation At of 1936, 7 U,S,C+ ~1.95@.

113 U.S. Gover~nt Manual 1991192, SUpra note 11, p. 114.

~ 14 Financial Statistics of selected Publicly Owned Elecm”c Utilities 1990, Slpll nOIe 59, p. 347.

115 U.S. Govern~ntJfanua/ 199i/92, supranote 1 I,p. 114. Interest rates onthedirect borrowing have histofic~y knsevertd POks higher

than the 5 percent maximum charged on loans. More REA funds have been lent out than repaid since 1973 and the deficit is made up by direct

borrowing and sale of CertMcates of Beneficial Ownership to the Federal Financing Bank in the U.S. Tnmury.

116 ~ I

. . . that rural electric and telephone systems should be encouraged and assisted in developing their resources and ability to achieve the

fwcial strength needed to enable them to satisfy credit needs from their own fwcial organimations and other sources at reasonable rates

and terms consistent with the loan’s applicant’s ability to pay. ’ Ibid.
do so by a utility who held a guarantee. Now, most

REA-guaranteed loans are made by the FFB.117

In January 1992, REA issued a final rule

revising the requirements for general and preloan

procedures for insured and guaranteed electric

loans. 118 These regulations were in large part a

recodification of many of REA’s existing policies

and rules. REA loan requirements contain several

provisions that encourage IRP and utility energy

efficiency programs. All borrowers are encouraged to promote energy efficiency and load

management to improve system load factors,

reduce losses, and reduce the need for new

generating capacity. 119 Most REA borrowers

must prepare and maintain power requirements

studies (PRS) and construction work plans (CWP)

for review and approval by REA. Together the

PRS and CWP require a borrower to establish a

comprehensive and integrated planning system to

guide operations and resource acquisition, effec120 To qualify for new loans, tively an IRP process.

a borrower must demonstrate to REA that it has

explored all practical and feasible alternatives to

adding new capacity, including improved load

management, energy conservation, and power

purchases from other suppliers, including independent power producers. REA believes that the

rule changes are expected to lead to a more

effective power planning process.

Chapter 7–Federal Programs I 189

FEDERAL ENERGY REGULATORY

COMMISSION

FERC regulates prices, terms, and conditions

of wholesale power sales and rates involving

privately-owned power companies and of transmission of electricity at wholesale.121 With the

growth of wholesale transactions in the utility

sector, FERC now regulates about one-third of

Table 7-1 l—Rural Electrification Administration

Cooperative Distributor Borrowers: Consumers,

Sales, and Operating Revenue 1990

Number of consumers on December 31

Residential. . . . . . . . . . . . . . . . . . . . . . . . . . . . 9,732,694

Commercial and industrial. . . . . . . . . . . . . . . 915,363

Other sales to ultimate consumers. . . . . . . . . 153,324

Total ultimate consumers.. . . . . . . . . . . . 10,801,381

Sales for resale, . . . . . . . . . . . . . . . . . . . . . 203

Total consumers . . . . . . . . . . . . . . . . . . . . 10,801,584

Sales for the year (mWh)

Residential. . . . . . . . . . . . . . . . . . . . . . ......111,776,522

Commercial and industrial. . . . . . . . . . . . . . . 65,794,723

Other sales to ultimate consumers. . . . . . . . . 5,814,007

Total sales to ultimate consumers . . . . . 183,385,252

Sales for resale. . . . . . . . . . . . . . . . . . . . . . 3,095,647

Total Sales. . . . . . . . . . . . . . . . . . . . . . . . . 186,480,899

Operating revenues for the year ($000)

Residential. . . . . . . . . . . . . . . . . . . . . . . . . . . . 8,403,275

Commercial and industrial. . . . . . . . . . . . . . . 3,806,505

Other sales to ultimate consumers . . . . . . . . . 374,504

Total sales to ultimate consumers . . . . . 12,684,284

Sales for resale. . . . . . . . . . . . . . . . . . . . . . 121,008

Total revenue from sales of electricity. 12,805,290

Other operating revenues. . . . . . . . . . . . . . 196,248

Total operating revenues. . . . . . . . . . . . . 13,001,538

NOTES: Totals may not equal sum of components because of

independent rounding. This table does not included in 1990 the 56 Power

Supply Borrowers. Data for 1990 represents 838 Distribution Borrowers.

SOURCE: Office of Technology Assessment, 1993, based on data

from U.S. Department of Energy, Energy Information Administration,

Fhancia/Stat/sties of Selected Publicly Owned Electric Utilities 1990,

DOE/EIA-0437(90)/2 (Washington, DC: U.S. Government Printing

Office, February 1992), table A4, p. 349.

electricity sold. FERC also approves rates for

power sold and transported by the five power

marketing administrations.

There have been suggestions that FERC could

as a matter of policy under its existing broad

authority over wholesale transactions require

utilities selling power at wholesale to engage in

IRP and offer DSM programs and require sellers

to demonstrate that a proposed sale is consistent

117 ~ld.

118 s? Fed. Reg. 1,0441,068, J~. 9, 1992.

1197 CFR 1710.118, 57 Fed. Reg. 1061, Jan. 9, 1992.

1~ 7 CFR 17 Io.2w171o.2o6 and 7 CFR 1710.2501710.254, 57 Fed. Reg. 1062-1066, JaxI. 9, 1992.

121 16 U.S,C, 791a, 824a, and 824ct. FERC authority is discussed h ch. 3 Of WS r~fl.
190 I Energy Efficiency: Challenges and Opportunities for Electric Utilities

with the buyer’s approved IRP program. For

example, President Bush’s National Energy Strategy suggests FERC promote utilities’ use of IRP

through its rulemaking authority and its regulatory powers.

122 To open discussions, from 1991 to

1992 FERC held several workshops with State

regulators to explore IRP, transmission, and

market-based pricing issues. However, FERC has

not yet defined any potential role in promoting

IRP or DSM, nor has it been actively pursuing

issues related to energy efficiency or least-cost

planning for utilities engaged in wholesale power

sales and transmission.

ENCOURAGING VOLUNTARY EFFORTS

In recent years, there has been growing interest

in mechanisms that the Federal Government can

use to provide various incentives to utilities and

others to implement energy efficiency programs

voluntarily. These efforts are in addition to, and

not a replacement for, the variety of programs that

establish more or less mandatory requirements for

utilities or that offer technical and financial

assistance to aid utility energy efficiency and

planning. Examples of this approach include the

“green programs” in EPA’s office of climate

change, the conservation and renewable energy

emissions allowances reserve under the Clean Air

Act Amendments, and energy efficiency awards

programs for Federal facility managers.

 EPA’s Green Programs

The EPA Office of Atmospheric Programs has

embarked on several initiatives designed to encourage the voluntary adoption of energyefficient and pollution-reducing technologies as

part of EPA’s global climate change activities.

EPA’s green programs marshall the agency’s

stores of good will, credibility, and visibility in

combination with market forces to attract commercial, industrial, utility, and government participants to cooperative efforts to overcome some

of the barriers that have hampered investment in

energy-efficient and environmentally-friendly technologies. Among the goals most of these programs share are:

Changing corporate and consumer purchasing patterns to favor efficient products

through information availability and exhortation; 123

Creating a market pull and lower prices for

efficient products through aggregated purchases (group buys) and changes in longterm procurement patterns;

Encouraging utility rate reforms to reward

investments in energy efficiency;

Expanding international markets for highproductivity and energy-efficient products;

and

Changing industrial practices and processes

to reduce emissions of greenhouse gases.l24

The Green Lights Program is the largest and

most prominent of EPA’s green programs. It was

established in 1991 as a voluntary program

designed to encourage U.S. corporations to retrofit their buildings with cost-effective lighting

measures. According to EPA estimates, commercial and industrial lighting amounts to some 20

percent of total electricity consumption. By

reducing energy use from lighting, EPA anticipates a lower amount of pollutants associated

with fuels from electricity generation. In particular, EPA estimates that more efficient lighting

could lower greenhouse gas emissions by 22 to 55

million metric tonnes of carbon. EPA is relying

on the lure of cost-savings, and higher profits, and

the promise of technical assistance to attract

participants.

In NatiO~ Energy Strategy: Powerjid Ideas for America, SUpm note B, p. T.

123 J?fi~n c~m~eq Dir~tor, ~1~ of A~osp~ric ~d Moor fi~-,~W of Air @Matioq U.S. Environmental Protection

Agency, testimony before the Joint Economic Committee, 102d Cong., 2d sess., April 28, 1992, p. 5.

124 Joh Ho=, Office of Atmospheric Programs, Environmental Protection Agency, briefq fOr COUfp’WiOIItd staff sponsored by the

Environmental and Energy Study Institute, Aug. 7, 1992.
Chapter 7–Federal Programs I 191

As of May 1993, more than 900 corporations,

and organizations have joined the program.

The over 450 “partners” have each signed a

“memorandum of understanding’ ’(MOU) with

EPA committing to survey their U.S. facilities

and install all profitable lighting retrofits in 90

percent of total square footage within 5 years. In

return, EPA offers encouragement, information,

product testing, technical assistance, and public

recognition to organizations. Green Lights helps

partners overcome barriers to energy efficiency

by providing technical assistance as well as

information on products and financing. EPAprovided software and training help businesses

identify the retrofit options that maximize savings. The National Lighting Product Information

Program provides reliable information about

lighting technologies and options to corporations

concerned about product claims or potential

employee response to lighting changes. EPA also

supports participants through a registry of utility

rebates, energy service companies, banks and

leasing companies providing financing.

The over 350 Green Lights “allies” include

lighting manufacturers and energy management

companies, and electric utilities that agree to

educate customers about energy efficient lighting. EPA’s utility ally program promotes cooperation in publicizing the many benefits of energy

efficient lighting, EPA invites utilities to sign a

MOU under which the utility agrees to:

■ complete profitable lighting retrofits in 90

percent of the square footage of its own

facilities;

■ assist EPA in marketing Green Lights and

energy-efficient technologies to its industrial

and commercial customers;

■ participate in the ongoing lighting product

and employee information programs; and

= assist EPA in documenting savings from

lighting upgrades in their service area.

In return EPA agrees to:

reen

-Lights

provide tools and methodologies for pollution prevention calculations, energy savings,

dollar savings, and lighting upgrade designs;

provide materials to help the utility’s efforts

to promote high quality energy-efficient

lighting; and

enhance the energy-efficient lighting market

by working with the lighting industry to

improve consumer confidence in product

availability, quality, and value.

EPA also promises utilities that participation in

Green Lights will enhance their corporate image

by showing their concern and involvement in

environmental protection. Green Lights also offers utilities support for their own DSM objectives and access to a national network providing

a timely exchange of information on program

effectiveness, experience, and decision-support

tools.125

EPA has also enrolled the assistance of various

trade, conservation, and professional associations

as Green Lights endorsers.

Green Lights builds on the realization that

protecting the environment has become an attractive product marketing angle. As an additional

incentive, EPA authorizes participating compa1~ “U.S. EPA Green Lights, Utility Ally Program, ” flyer, April 1992.
192 I Energy Efficiency: Challenges and Opportunities for Electric Utilities

nies and allies to use the EPA Green Lights logo

in advertising and promotional materials. EPA

also displays corporate logos of participants in its

own publicity and recruitment materials and

advertising.

As of May 1993, some 2300 Green Lights

projects encompassing over 220,000 square feet

were in the process of being surveyed and

retrofitted. Approximately, 40,000 square feet of

retrofits were complete. EPA estimates that if all

participants enrolled as of May 1993 complete the

upgrading of their facilities, more than 3.3 billion

square feet will have been retrofitted.126 Annual

savings on participants’ electric bills will total

over $1 billion annually, according to EPA, and

more than $6 billion in new powerplant investments will be avoided. Lighting upgrades will

prevent emission of some 21,378 million pounds

of carbon dioxide annually-the equivalent of

removing over 2.1 million cars from the roads.

Additionally, EPA estimates that program investments in lighting upgrades will create some

66,000 job years.

Because the agreements are voluntary, there

are no enforcement mechanisms under which

EPA can compel participants to fulfill their

promises. EPA, however, is monitoring the pace

of installations and has indicated that if participants fail to follow through, EPA will bring added

pressure on them to do so.

Green Lights advances several objectives. First,

it helps overcome informational barriers to installing more efficient lighting through advertising and technical assistance provided by EPA.

Second, by expanding the pool of customers for

energy-efficient lighting services, EPA is helping

to create a market pull for efficient products and

services. Third, this market expansion could

eventually help lower prices of these products

through improved economies of scale in manufacturing and distribution. Lastly, the program

can help lower first-cost barriers to participation

by collaborating with various utility and government programs that provide loans and rebates for

installing efficient lighting.

EPA is also creating a partner lighting program

for the Federal Government, entitled Federal

Green Lights. A similar program dubbed Green

Buildings, which will launch a cooperative effort

to incorporate energy-saving construction and

building, ventilation, and air conditioning technologies in commercial buildings, is under development.

Building on the success of Green Lights, EPA

has launched an energy efficiency labeling program designed to sell consumers and manufacturers on the advantages of energy efficient products.

The first application, the EPA Energy Star

Computers program is a voluntary partnership

with EPA and the computer equipment manufacturers to manufacture and market computer equipment incorporating energy-saving technologies.

In return the participants gain the right to use the

EPA pollution preventer logo in marketing and

advertising. For more on this program see chapter

4. Other cooperative efforts under consideration

are showerheads, residential room air conditioners, and cooking equipment.

Another innovative initiative is the “Golden

Carrot” program-a consortium of 25 utilities

that is sponsoring a contest for the development

and production of a super-efficient regrigerator

that is free of ozone-depleting CFCS. The winning

manufacturer will receive a bonus of $28 million

and orders to deliver up to 300,000 units to

participating utilities for use in their DSM programs. The award will be announced in summer

1993. For more on the Super Efficient

tor Program (SERP), see chapter 4.

9 Conservation and Renewable

Energy Reserve

RefrigeraThe Clean Air Act Amendments of 1990 acid

rain title provides for allocation of up to 300,000

1X Jo~ S. Ho- ~~tor, GIobal Change Divisio~ Office of Air and Radiation Programs, U.S. fivk~nttd Protection Agency,

presentation to congressional staff, June 3, 1993.
Chapter 7–Federal Programs I 193

sulfur dioxide (S02

) emissions allowances to a

conservation and renewable energy reserve.127

The EPA Administrator can make allowances

from the reserve available to eligible utilities that

have reduced S02 emissions by installing qualified cost-effective conservation measures or renewable energy generation after January 1, 1992.

These allowances will be made available beginning January 1, 1995, and can be used for

complying with the acid rain emissions limitations. The amendments set a number of requirements for eligibility. The utility must adopt a

least-cost planning process that evaluates a full

range of resources including conservation and

renewable energy sources to meet future demand

at the lowest system cost. The plan must be

approved by the utility’s State regulatory authority and the qualifying measures must be consistent with the plan. For conservation measures,

State-regulated utilities must obtain DOE certification that State regulators have adopted rate

provisions that assure that the utility’s net income

after installing the qualified conservation measures is at least as high as it would have been

without the energy efficiency measures.in

DOE certification of this “net income neutrality status’ for DSM investments involves review

of the regulatory treatment of conservation program expenditures, such as decoupling adjustments, lost revenues, and performance incentives. 129 DOE certification must be obtained

before the utility implements the qualified conservation measure. DOE is processing certifications

on a “first-come, first-served” basis, and must

also certify that the utility is actually implementing the conservation measures it developed in

qualifying for the emission allowances.130

1 Federal Energy Efficiency Awards

Two awards programs administered by the

Federal Government recognize Federal employees and/or facilities for energy efficiency achievements. The first is the Federal Energy Efficiency

Awards at FEMP, and the other is the awards

program at the U.S. Department of Army.

Each year the FEMP awards 15 certificates of

achievement to individuals and facilities for

exemplary performance in promoting conservation in Federal facilities.131 The award does not

include any financial compensation, but it does

provide recognition and favorable publicity for

the winning individuals and organizations.

The U.S. Army in Europe (USAREUR) has an

award component in its energy program. The

awards recognize both small and large facilities

for saving energy in a variety of ways. The

strenuous review of the nominees includes scoring on elements like efficiency measures, shortterm measures, long term plans, numeric performance, mobility fuel savings, special considerations, and a day-long inspection of finalists. The

value of the program is multifold. In addition to

showing the interest and commitment of USAREUR, it creates publicity for energy programs,

recognizes deserving communities, and reduces

energy use. Prior to FY 1991, the award included

a monetary component: $500,000 for first place,

and a total $1.2 million in cash awards to be used

on a ‘‘welfare, morale, and recreation’ item for

the winning communities.132

In Clem A~ Act Amendments of 1990, Public Law 101-549, title IV, wc 404,1(M S@t. 2592-2605, NOV. 15, 1990, AZ U.S.C.7G51b121742 USC. 404( f)(2) @)( fii).

1~ Dime B. Pfikey, M~gm, DSM r%OgEUIM, CMfke of Utility Technologies, Energy Efficiency and Renewable Energy, U.S. Dep~ent

of Energy, “Demand-Side Management Activities of the U.S. Department of Energy-A National Perspective,” Mar. 25, 1993, p. 6.

130 Ibid.

131 us, Congtis, Offlm of ~~o]oW Assessmen4 Energy Eficiency in the Federal Gover~nt: Government by Good E.mmple?,

OTA-E-492, (Washington DC, U.S. Government Printing OffIce, May 1991) p. 27.

132 Ibid, p. 97.

U.S. GOVERNMENT PRINTING OFFICE : 1993 0 – 330–075 : QL 3