Energy Efficiency: Challenges and Opportunities for Electric ...2 I Energy Efficiency: Challenges and Opportunities for Electric Utilities Box l-A-Key Terms I Energy efficiency refers

Energy Efficiency: Challenges andOpportunities for Electric Utilities

September 1993

OTA-E-561NTIS order #PB94-107547

Recommended Citation:U.S. Congress, Office of Technology Assessment, Energy Efficiency: Challenges andOpportunities for Electric Utilities, OTA-E-561 (Washington, DC: U.S. Gov ernmentPrinting Office, September 1993).

Foreword

T his Report on energy efficiency and electric utilities was prepared as part of OTA’sassessment of U.S. Energy Efficiency: Past Trends and Future Opportunities. Theassessment was requested by the Senate Committees on Governmental Affairs andEnergy and Natural Resources and the House Committee on Energy and

Commerce and endorsed by the Chairman of the Subcommittee on Environment of theHouse Committee on Space, Science, and Technology. Other reports in this assessmentexamine energy efficiency in residential and commercial buildings, industry, transporta-tion, 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 utilitysector. In particular, the Report ex amines the prospects for energy savings throughexpansion of utility demand-side management and integrated resource planning programsand related Federal policy options.

OTA appreciates the advice and assistance of the many individuals who contributed to thisproject, including the advisory panel, workshop participants, and reviewers.

(7+- -Roger C. Herdman, Director

iii

Advisory Panel

James F. Gibbons, ChairmanStanford University

Dale ComptonSchool of Industrial EngineeringPurdue University

Mark CooperConsumers Federation of America

Robert deHaanAmana Refrigeration Co.(retired)

Daniel A. Dreyfus1

Gas Research Institute

Clark W. GellingsElectric Power Research Institute

David B. GoldsteinNatural Resources Defense Council

Cheryl BarringtonRegulatory Assistance Projectformerly Commissioner,

Maine Public Utilities Commission

Kenneth HickmanThe York International Corporation

Edward MclnerneyGeneral Electric Co.

Alan MillerCenter for Global ChangeUniversity of Maryland-College Park

Gary NakaradoNational Renewable Energy Laboratoryformerly Commissioner, Public Utility

Commission of Colorado

John W. RoweNew England Electric System

Maxine L. SavitzGarrett Processing Co.

Sherwood H. Smith, Jr.Carolina Power & Light Co.

Richard TraceyRyland Homes

B.C. WaycasterDow Chemical

Irvin L. WhiteBattelle Pacific Northwest Laboratories

Mason WillrichPacific Gas and Electric Enterprises

James L. WolfThe Alliance to Save Energy

Eric R. ZausnerStrategic Performance Management

1Until January 1993.

NOTE: OTA appreciates and is grateful for the valuable assistance and thoughtful critiques provided by the advisory panel members. Thepanel does not, however, necessarily approve, disapprove, or endorse this report. OTA assumes full responsibility for the report and theaccuracy of its contents.

iv

Peter BlairAssistant DirectorIndustry, Commerce, and International

Security Division(beginning February 1993)Program Manager, Energy and Materials

Program(until August 1993)

Lionel S. JohnsAssistant Director, OTA(until February 1993)

Emilia GovanProgram ManagerEnergy and Materials Program Manager(beginning August 1993)

Project Staff

PRINCIPAL STAFF

Karen LarsenProject Director

Helene Kirwan-TaylorContractor

ADMINISTRATIVE STAFF

Lillian ChapmanOffice Administrator

Linda LongAdministrative Secretary

Tina AikensSecretary

workshop Participants

Doug BauerOak Ridge National Laboratory

Michael DworkinGeneral CounselVermont Public Service Board

Hossein HaeriCentral Maine Power Co.

John HughesElectricity Consumers Resource

council

Gary NakaradoCommissionerPublic Utility Commission of

Colorado

Wally NixonEntergy Services Co.

Paul NormanBonneville Power Administration

Jackie PfannenstielPacific Gas and Electric Co.

Ronald E. RussellCommissionerMichigan Public Service Commission

Glenn SimpsonPotomac Electric Power Co.

Dennis SumnerCity of Ft. Collins Light&

Power Utility

Lynn SutcliffeSycom Enterprises, Inc.

Marika TatsutaniNatural Resources Defense Council

Nat TreadwayElectric DivisionPublic Utilities Commission of Texas

James L. WolfThe Alliance to Save Energy

OTA appreciates and is grateful for the valuable assistance and thoughtful critiques provided by the participants in OTA’S workshop onEnergy 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 AndersonElectricity Consumers Resource

council

Joel BladowWestern Area Power Administration

Ashley BrownCommissioner, Public Utilities

Commission of Ohio

Ralph CavanaghNatural Resources Defense Council

Greg CollinsPSI Energy, Inc.

Kurt CongerAmerican Public Power Association

Rich CowartCommissioner, Vermont Public Service

Board

Ron EachusChairman, Oregon Public Utility

Commission

Scott HemplingAttorney-at-Law

Robert HirschElectric Power Research Institute

Eric HirstOak Ridge National Laboratory

Barbara Kates-GarnickCommissioner, Massachusetts Department

of Public Utilities

Reviewers

Steve KlinePacific Gas & Electric Co.

Paul KomorU.S. CongressOffice of Technology Assessment

Ed MayberryPotomac Electric Power Co.

Barry MolineAmerican Public Power Association

Andrew MoyadU.S. CongressOffice of Technology Assessment

Steve NadelAmerican Council for an Energy-Efficient

Economy

John NewmanU.S. CongressOffice of Technology Assessment

Karl RabagoCommissioner, Public Utilities

Commission of Texas

Margaret RostkerElectric Power Research Institute

Robin RoyU.S. CongressOffice of Technology Assessment

Rick TempchinEdison Electric Institute

Mark WieringaWestern Area Power Administration

contents

1 Introduction 1Energy and Electric Utilities 3Findings 4

2 Policy Issues and Options 9Strategies for Energy Efficiency 12Integrated Resource Planning 13Demand-Side Management 16U.S. Department of Energy Programs 16Utility Rate Reforms 17Federal Regulation of Power Transactions 18Leading by Example: The Federal Government

as Energy Consumer 19Supporting Energy-Efficient Technologies 22Increasing Utility Resource Options 23Leveling the Playing Field in Resource Planning 24

3 Electric Utility Industry Structure,Regulation, and Operations 27Electric Utilities in the U.S. Economy 27Electric Power Regulation 34Overview of Electric Utility Systems and Operations 48

4 Using Electricity More Efficiently:Demand-Side Opportunities 63How Much Electricity Can Be Saved? 63Energy-Efficiency Opportunities for Residential

Customers 67

Energy Efficiency Opportunities in theCommercial Sector 79

Energy Efficiency Opportunities in theIndustrial Sector 88

$&-

>>>: ::: A

- Utility Energy Efficiency Programsand Experience 99Scope of Utility Energy Efficiency Programs 99Influencing Customer Behavior 100Measuring Energy Savings and

Evaluating Effectiveness 105Mixed Results from Utility Energy

Efficiency Programs 110Incorporating Energy Efficiency Into Utility

Operations: The Role of IRP 114

State Energy Efficiency Initiatives 117Plannin g for Future Electricity Needs 117IRP Requirements 122State Incentives for Utility DSM Investments 129Energy Efficiency Research and Development Programs 140

Federal Programs 143The Federal Government and Energy Efficiency 143U.S. Department of Energy Programs 144Federal Power Systems 171Rural Electrification Adrmru “stration 188Federal Energy Regulatory Commission 189Encouraging Voluntary Efforts 190

x

Introduction

E nergy efficiency offers seemingly glittering promises toall-savings for consumers and utilities, profits forshareholders, improvements in industrial productivity,enhanced international competitiveness, and reduced

environmental impacts. The technical opportunities are myriadand potential savings real, but consumers and utilities have so farbeen slow to invest in the most cost-effective, energy-efficienttechnologies available. The energy efficiency of buildings,electric equipment, and appliances in use falls far short of whatis technically attainable. Energy analysts have attributed thisefficiency gap to a variety of market, institutional, technical, andbehavioral constraints. Electric utility energy efficiency pro-grams have great potential to narrow this gap and achievesignificant. energy savings.

But along with opportunities, greater reliance on energyefficiency as a resource to meet future electricity needs alsoentails risks—that efficient technologies will not perform as wellas promised, that anticipated savings will not be truly cost-effective in practice, and that the costs and benefits of energy-efficiency 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 arerapidly being developed and implemented in most of theremaining States (see box l-A). These programs reflect arecognition that increasing the efficiency of energy use byconsumers to offset demand growth can be a financiallyattractive and reliable alternative to the addition of newgenerating plants. They also reflect a belief by policymakers thattapping the economic and technical resources of electric utilitiescan be an effective strategy for speeding the adoption ofenergy-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 aslighting, 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 usuallymeasured 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), energyefficiency improvements contribute to greater energy productivity and economic efficiency.

• Energy conservation refers to measures taken to reduce energy consumption. Conservation measuresinclude substituting more energy-efficient equipment to produce the same level of energy services with lesselectricity and changing consumer behavior to cut energy use. The term is sometimes used interchangeablywith energy efficiency.

● Demand-Side Management (DSM) refers to utility-led programs intended to affect the timing or amountof customer electricity use. These include energy efficiency programs aimed at reducing the energy neededto serve customer needs and programs that shift electricity demand to reduce peak loads or to make moreeconomic use of utility resources. All utility DSM programs fit into one or both of following: 1) programsaffecting the way energy-using equipment is operated, and 2) programs that focus on the installation ofimproved technologies. A variety of DSM mechanisms are in effect, including audit and informationprograms, rebates and other consumer financial incentives, direct installation programs, technicalassistance, and energy performance contracting.

• Integrated Resource Planning (IRP) is a teohnique used by utilities and State energy regulatory agenciesto develop flexible plans for providing reliable and economic electric power supply for customer needs. Theprocess includes explicit comparisons of both supply-and demand-side resource options to meet a rangeof 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 optionsin a consistent manner to develop an overall plan to meet Identified future needs at least cost. There areseveral competing methodologies for defining what resource chokes constitute “least-coost” mix. The IRPprocess usually includes public participation and comment and may require approval of State regulatorsbefore adoption. After adoption, the plan is used to guide utility chokes in acquiring new resources. IRPis 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 anthe Federal Government also has adopted a policyfavoring expansion of utility IRP and DSMprograms and reaffirmed its support for develop-ment and commercialization of more energy-efficient technologies.1

Efficient use of electricity and changes in theelectric power sector will play a vital role in anystrategy for achieving a more energy-efficientsociety. If the threat of global climate changeprompts concerted action to reduce carbon emis-

imperative and a major overhaul of how energyservices are provided and paid for will be requiredon a more accelerated schedule.

This report is part of the Office of TechnologyAssessment (OTA) ongoing assessment of U.S.Energy Efficiency: Past Trends and Future Op-portunities. It examines mechanisms for achiev-ing greater energy efficiency through electricutility planning, operations, and regulation. Inparticular, 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 reportalso looks at the influence of State and Federalregulatory policies on utility investments inenergy efficiency and presents a range of legisla-tive policy options for encouraging energy effi-ciency through the electric utility sector.

ENERGY AND ELECTRIC UTILITIESElectric utilities are important as energy users,

as providers of vital energy services, and as aneconomic force in the U.S. economy. Electricutilities are the Nation’s biggest purchaser ofprimary energy supplies-coal, nuclear fuel, gas,and oil. Utility power generation accounted for 36percent of total primary energy use in the UnitedStates or 29.6 quads in 1990.2

Energy efficiency improvements have slowedelectricity demand growth, but electricity use isstill increasing, Energy use for electric powergeneration as a share of the Nation’s energyconsumption has been growing-faster thangrowth in demand for other energy sources andthat trend is projected to continue. Electricitydemand growth over the past decade has slowedfrom the high (7 percent/year) annual growth ratesthat characterized the 1950s and 1960s to anaverage of 2.3 percent/year in the 1980s.3

Projecting future electricity demand is a highlyuncertain art-adding to the risks that utilitiesface in planning and building for the future.Current estimates of 10-year electricity demandgrowth range from 1 percent to 3.5 per year (seefigure l-l). Estimates of new powerplant con-struction needed to meet this new electricitydemand and replace retired units range from 56 to221 gigawatts (a gigawatt is one billion watts) inaddition 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 datafrom 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 ElectricInstitute, “Meeting Electrcity Needs in the 1990s,” September 1991(briefing paper prepared for the Strategic Planning Executive AdvisoryCommittee by Science Concepts, Inc.).

The U.S. Department of Energy uses a range ofabout 80 to 100 gigawatts for the new capacityneeded by the year 2000--equivalent to construc-tion of up to 100 new 1,000-megawatt coal-firedpowerplants. 5 The differences in the estimates ofnew capacity needs reflect hundreds of billions ofdollars in new capital equipment costs to ratepay-ers.

Efficiency advocates have long maintained thatit is often cheaper for ratepayers and better for theenvironment and society to save energy ratherthan build new powerplants. This view is nowembraced by many utilities, regulators, share-holders, 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 PlanningExecutive 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).


Figure l-2—impacts of Energy Efficiency Savings

Electricity demand

/’”) Market forcesand standards

Utility DSMprograms

Range of cost-effective potential

Maximum technicalpotential

1 9:o- 2000

This figure shows the different levels of projected energysavings impacts depending on what measure of energyefficiency is used.SOURCE: Office of Technology Assessment, 1993, adapted fromBarakat & Chamberlinr Inc., Efficient Electricity Use: Estimates ofMaximum Energy Savings, EPRI CU-6746 (Palo Alto, CA: ElectricPower Research Institute, March 1990).

strategy is already shaping our future-initialresults are promising, but substantial uncertain-ties remain, and hundreds of billions of dollars areat stake.

FINDINGS1. There are significant opportunities for

cost-effective, energy efficiency savingsin all sectors of the economy.

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

opportunities to use electricity more efficientlyand to avoid the costs and pollution associatedwith new powerplant construction and still havethe same energy services-warm showers, colddrinks, comfortable surroundings, and a vitaleconomy. 6

There is general consensus that the mostpromising technical opportunities for achievingmore efficient use of electricity include:

improvements in the thermal integrity ofbuilding shells and envelopes;improvements in the efficiency of electricequipment;lighting improvements;net efficiency gains from shifting energysources from fossil fuels to electricity (elec-trification); andOptimization of electricity use through betterenergy management control systems, shiftsin time of use, and consumer behavior andpreference changes.

Estimates of the amount of cost-effectiveelectricity savings that might be achieved throughfull adoption of currently available efficiencytechnologies vary, falling within a range of from20 to 45 percent of present use by 2000 dependingon the study. This wide range in the estimatesreflects differing assumptions about technologyavailability, adoption rates, and cost-effective-ness (see figure 1-2). The high estimates wouldrequire replacing much of the entire stock ofelectricity-using equipment with the most-efficient 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: Governmentby 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 PrintingOfi3ce, February 1991); American Council for an Energy-Eff’icient Economy and New York State Energy Office, The Achievable ConservationPotential in New York Statefrom Utility Demand-Side Management Programs, Energy Authority Report 9018 (Albany, NY: New York StateEnergy Research and Development Authority and New York State Energy OffIce, November 1990); Ameriean Council for an Energy-EfficientEconomy et al., America’s Energy Choices: Investing in a Strong Economy and a Clean Environment, (Cambridge, MA: The Union ofConcerned Scientists, 1991): and Arnold P, Fickett, Clark W. Gellings, and Amory B. IAwins, “Efllcient Use of El~trici~,” S~”en@cAmerican, September 1990, pp. 65-74.

Chapter I-Introduction ! 5

mobilizating of staggering amounts of capital tofinance the transition even though it would resultin significant long-term savings in energy costs.Even without aggressive retrofitting and replace-ment of electric equipment, it is projected thatpresent trends in energy efficiency improvementsdue to energy prices, standards, and technologicalimprovements, coupled with existing utility-sponsored resource planning, conservation, andDSM efforts will result in about a 9 percentreduction in electricity use by 2000 from what itwould be without the expected efficiency sav-ings. 7 Utility DSM programs are expected tooffset about 14 percent of new electricity demandgrowth over the next decade.8

There is general consensus among energyanalysts that we can cut electricity demandgrowth further and maybe even produce a netreduction in electricity demand over the nextseveral decades. Doing so clearly offers substan-tial benefits. We believe with wise implementa-tion of cost-effective measures, they likely willoutweigh the costs and risks inherent in thisstrategy.

2. Investments in energy efficient technolo-gies offer significant benefits to electricutilities and the Nation.

Improvements in energy efficiency through theelectric utility sector offer the promise of savingsfor ratepayers and electric utilities, profits forshareholders, and societal benefits to energysecurity, international competitiveness, and envi-ronmental quality. Figure 1-3 illustrates thepotential contributions of energy efficient tech-nologies to national interests.

Increasingly, utilities are finding that energyefficiency programs make good business sense.

-’&-

A home energy audit in progress.

Investments in energy efficiency through demand-side measures and enhancing the performance ofsupply-side options can provide reliable, flexible,and lower-cost alternatives to reliance solely onconventional generating options. Efficiency con-tributes to improved load factors for existingplants, reduces financial risks, and generates goodwill among customers.9 In addition, energy effi-ciency improvements are becoming an importantstrategy for environmental compliance by reduc-ing emissions and qualifying utilities for addi-tional emissions allowances under the acid rainprovisions of Clean Air Act Amendments of1990. With the growth of State regulatory incen-tives for DSM investments, utilities are findingthat energy efficiency programs offer new profitopportunities.

Improving the energy efficiency of electricityuse contributes to greater productivity, lowerenergy costs overall, and more competitiveness inthe international marketplace for U.S. businesses.Moreover, utility DSM investments tend to createmore 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, FinalReport (Palo Alto, CA: Electric Power ResearchInstitute, August 1990). Electric Power Research Institute and Edison Electric Institute, Impactof Demand-Side Management on Future Cmtomer Electricity Demand: An (@date, EPRI-CU 6953 (Mo Alto, CA: Electric Power Researc hInstitute, 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.


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 oilimport vulnerability. Even though electric utili-ties today account for less than 5 percent of U.S.oil demand, oil-fried generation remains an imp-ortant resource in the Northeast, California,Florida, and Hawaii. For utilities in these areas,accelerating the implementation of DSM meas-ures to displace oil-fired generation is a keystrategy for responding to potential oil importdisruptions. l 1

3. Electric utility energy efficiency pro-grams can produce cost-effective energysavings and help overcome economic,institutional, and behavioral impediments

to investment in energy efficient technol-ogies.

The potential of using the electric utilitiessector and utility regulation to spur changes in theenergy efficiency of America’s homes, schools,and workplaces has captured the attention ofenergy efficiency advocates, utilities, entrepre-neurs, State regulators, Federal policymakers, andconsumers. Public utilities are well positioned topromote the adoption of more energy-efficienttechnologies. Their integrated operations, techni-cal expertise, established ties to customers, andfamiliarity with customer energy use equip themwith the technical skill, marketing tools, andinformation to identify energy-savings opportuni-ties. 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 securecash flow, and a concomitant responsibility toprovide cost-effective and reliable service to theircustomers. Their regulated status also makesthem attractive targets for policy initiatives inpursuing energy efficiency, as it has in improvingenvironmental quality. Utilities are by no meansthe only entities that can provide energy effi-ciency investments-the growth of energy serv-ice companies and energy management technol-ogy companies testify to this. Many of thesecompanies owe much of their market to opportu-nities created by utility programs and rebates.

Utility efficiency programs can work—providing significant savings and profits forutilities. Energy efficiency and utility demand-side management and conservation efforts havebecome big business. An estimated $2 billion wasinvested by utilities in DSM in 1991 and this willgrow significantly in years to come.

Initial results have demonstrated that well-designed and implemented utility energy effi-ciency programs can deliver sustained, reliable,and cost-effective electricity savings. Despite thispromise, there have been early disappointments.In many programs, participation rates have beenlow and actual savings have been well belowcost-effective technical potential. In part this isdue to the fact that many utility programs are ofrecent vintage and are still limited in scope.Nevertheless, even the best programs have expe-rienced gaps between technical potential andactual savings. In coming years, utility programswill have to narrow this savings gap and expandthe degree of customer participation in order tomake energy efficiency the true equal of newgenerating units and other supply-side options inmeeting customer energy needs.

DSM programs entail some risks both intechnology and the associated regulatory changes:that the savings will not be as high or as durableas expected, or that consumers will be asked topay more than necessary to achieve them. DSMprograms and IRP methods are evolving to takeadvantages of lessons learned and to target a

broader range of electricity saving opportunities.The challenge is to assure that expanded utilityand State programs achieve their goals and thatFederal policies support, or at least not frustrate,those objectives.

4. State and Federal Governments will playkey roles in overcoming the barriers andconstraints to utility energy efficiencyinvestments because of the regulatednature of utilities and government’s in-fluence over other sectors of the econ-omy.

States and utilities are already well-advancedin establishing energy efficiency programs. TheFederal Government has only limited directinfluence over utility resource decisions, demandmanagement programs, and retail operations.Most of these matters are regulated at the Stateand local level. Yet there is a strong Federalinterest in energy efficiency arising from theimportance of reliable and economic electricpower production to the economy, concerns overthe environmental impacts of power generation,and the Federal Government’s roles as wholesalepower producer, utility regulator, and utilitycustomer.

Our future energy path will be determined bychoices made by utilities, consumers, regulators,and government. If we choose to pursue theenergy efficiency alternative, success depends oncooperation by utilities, acceptance by consum-ers, and institutional change. The States and manyelectric utilities have already moved far ahead ofthe Federal Government in direct initiatives formore efficient electricity use through the utilitysector. There are, however, a number of areaswhere the Federal Government can make acontribution in encouraging the development andavailability of energy-efficient technologies forelectric utilities and their customers. Moreover,Federal Government decisions in a number ofareas could signicantly affect the success andcost-effectiveness of utility programs and invest-ments.


Federal policy options for encouraging greater energy efficiency; 2) continued support for com-energy efficiency through the electric utilities mercializing energy-efficient technologiessector are discussed in chapter 2 of this report. through tough energy efficiency standards forThe overall strategies include: 1) support for buildings and equipment; and 3) support forexpanded IRP and DSM programs and other State energy efficiency research, development, andregulatory incentives for utility investment in technology transfer activities.

.

T he Federal interest in encouraging energy efficiencythroughout the U.S. economy rests firmly on three broadnational policy goals: economic growth, environmentalprotection, and national security. The Federal Gover-

nment has a long history of involvement in the utility sector, bothas a regulator and as the builder and operator of large powersystems. Following the energy crises of the 1970s, new Federallaws and programs were established to support energy conserva-tion activities, minimum energy efficiency standards, utilityregulatory reforms, and the research, development, demonstra-tion, and commercialization of new and more environmentallyfriendly technologies for generating electric power.

Improvements in energy efficiency through the electric utilitysector offer the promise of savings for ratepayers and electricutilities, profits for shareholders, and societal benefits to energysecurity, international competitiveness, and environmental qual-ity. But, as discussed later in this report, the Federal Governmenthas only limited direct influence over utility resource decisions,demand management programs, and retail operations. Most ofthese matters are regulated at the State and local level. Yet thereare a number of areas where the Federal Government can makea contribution in encouraging the development and availabilityof energy-efficient technologies for electric utilities and theircustomers. Moreover, Federal Government decisions in a num-ber of areas could significantly affect the success and cost-effectiveness of utility programs and investments.

This chapter discusses a range of legislative policy options forencouraging greater energy efficiency through the electricutilities sector. They include Federal policy options for support-ing expanded integrated resource planning, demand-side man-agement programs, and other State regulatory incentives forutility investment in energy efficiency. The chapter also presentsoptions for new Federal energy efficiency standards for buildings

PolicyIssues

andOptions 2

I 9


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 infer. 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 aboutthe Energy Policy Act of 1992.1 The policy appropriations levels for newly authorized pro-options 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 legislativeconsideration and debate. The act contains a wide range of Federal initiatives intended to Improve the energyefficiency of the U.S. economy, encourage the commercialization of energy-efficient and renewable energytechnologies, 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 GoalsNational 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 PlanningState 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 byTVA distributors.

The Western Area Power Administration (WAPA) must require its long-term firm power customers toimplement IRP within 3 years. WAPA will provide technical assistance in developing IRP programs and review theplans prepared. Utility resource plans must select options that minimize life-cycle costs, including adverseenvironmental effects, and give priority to energy efficiency and renewable energy to the extent practicable. WAPAmay impose penalties for failure to file or carry out IRP. Special provisions are included to aid small utilities inpreparing resource plans.

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

Demand-Side ManagementState 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 Ieascostplanning processes.

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

Utility subsidies to residential customers for energy efficiency measures are granted an exemption fromFederal 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; electricmotors; 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 highestlevels that are technologically feasible and economically justified.

Federal energy testing and labeling requirements are expanded to cover light fixtures, office equipment, andmajor consumer appliances, and to disclose Iife-cycle energy costs, usage, and comparisons to the most efficientmodels. 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 buildingcodes to incorporate model industry energy efficienccy standards.

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

The Department of Housing and Urban Development will establish a pilot program for energy-efficient homemortgages 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 ofenergy-efficient and renewable technologies in the buildings, industrial, and utility sectors. Goals for the utilitysector 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 Federalbuildings. 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 savingsperformance 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/kWhgenerated for up to 10 years.

To encourage growth of independent power producers, qualifying wholesale generators are granted a newexemption 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 providetransmission services to other utilities and power generators.


Several significant utility-related issues were leftunresolved, especially in the delicate area ofconflicts in Federal and State jurisdiction overutility planning on multistate systems, wholesalepower transactions, and their effects on retailrates.

STRATEGIES FOR ENERGY EFFICIENCYEfforts to harness the utility sector as a means

to achieve greater energy efficiency have focusedon three regulatory strategies: requirements foradoption of utility integrated resource planning(IRP), also called utility least-cost planning;expansion of utility demand-side management(DSM) programs; and rate reforms and otherregulatory incentives for utilities to invest inenergy-saving technologies. Programs for pro-moting energy efficiency through utility IRP andDSM measures are already entrenched in manyStates and are rapidly being developed andimplemented in many others. These State andutility efforts could eventually involve the expen-diture of billions of dollars of ratepayer funds.These programs reflect a recognition that increas-ing the efficiency of energy use by consumers canbe a financially attractive and reliable alternativeto the addition of new energy supplies to meetdemand growth and a belief that tapping theeconomic and technical resources of electricutilities can be an effective strategy for speedingthe adoption of energy-efficient technology in allsectors.

Initial results have demonstrated that well-designed and implemented utility energy effi-ciency programs can deliver sustained, reliable,and cost-effective electricity savings. Despite thispromise, there have been early disappointments.Many programs have failed to achieve the signifi-cant electricity savings and high degree of partic-ipation needed to make DSM the true equal ofnew generating units and other supply-side op-

tions in meeting customer energy needs. DSMprograms and IRP methods are evolving to takeadvantages of lessons learned and to target abroader range of electricity-saving opportunities.The challenge is to assure that expanded utilityand State programs achieve their goals and thatFederal policies support, or at least not frustratethose objectives.

Although energy efficiency through IRP was akeystone of the Bush Administration’s NationalEnergy Strategy, Federal financial commitmentsto energy efficiency are dwarfed by Federalinvestments in conventional supply-side technol-ogies (fossil and nuclear power) and in renewableenergy sources (see chapter 7). Part of thedisparity can be explained by the fact that electricutility resource planning decisions and DSMprograms are matters largely within the purviewof State regulation and Federal regulatory influ-ence is largely indirect. The Federal Governmentclearly lags far behind the States in programs andexpertise in the utilities sector, particularly in theareas of resource planning and DSM. Moreover,at the same time, Federal policies and regulatoryinitiatives are promoting both the growth of acompetitive bulk power sector that includes moreunregulated nonutility generators and greater useof market-based rates in wholesale power con-tracts in place of traditional cost of service rates.To the extent that utilities rely on wholesalepower purchases to supply future needs instead ofinvesting in their own plant and equipment,Federal regulatory control over power supplieswill increase and State regulators’ influence overpower supply costs will diminish and so too willtheir ability to enforce State-approved least-costplans unless there is a change in law at the Federallevel. 2

The Federal Government has provided modestlevels of financial support to State initiatives andsupported 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, Officeof 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 ofprograms by the Bonnville Power Adminis-tration and, to a lesser extent, the Western AreaPower Administration, the Department of Energy(DOE) and the Federal Energy Regulatory Com-mission (FERC) at present are ill-equipped toprovide substantive direction and technical sup-port on increasingly sophisticated aspects ofutility resource planning and evaluation of DSMefforts. New policy directions coupled withmodest funding support, would, however, imp-rove Federal capabilities to further utility energyefficiency programs and enhance cooperationwith State and local governments.

The primary strategies available to Congress toadvance energy efficiency through the utilitysector include:

■

9

■

m

9

■

Supporting, through Federal actions, ex-panded use of IRP, DSM programs, and Stateregulatory initiatives to increase utility in-vestment in energy efficiency technologies,including legislation imposing new require-ments on State regulators and electric utili-ties;Providing Federal financial and technicalsupport to State regulatory agencies forimplementation of utility energy efficiencyinitiatives;Providing Federal support for research, devel-opment and demonstration of energy effi-ciency technologies and technology transferprograms;Strengthening and expanding Federal energyefficiency standards and labeling and informa-tion requirements for a wider variety ofelectric products and equipment;Requiring the Federal Energy RegulatoryCommission to advance IRP and energyefficiency in its direct regulatory responsi-bilities;Requiring the Tennessee Valley Authority toadopt IRP principles to guide its futureresource acquisitions (including investmentin cost-effective energy efficiency measures)

and to assist its customer utilities in develop-ing IRP and DSM programs of their own;Expanding the activities of Federal powermarketing administrations to support IRPand DSM; andRequiring the Federal Government to “leadby example” by improving the energy effi-ciency of its buildings and operations andparticipating in utility sponsored energyefficiency programs.

The Energy Policy Act of 1992 includesprovisions that commit the Federal Governmentto many of these strategies (see box 2-A). Thechallenges now lie in the implementation of newFederal policies and requirements. For Congress,this means decisions over appropriations levelsfor new energy efficiency initiatives and hardchoices over competing demands for Federalfunds in a time of financial difficulty and loomingbudget deficits. Congressional oversight of thepace and direction of agency implementation ofenergy efficiency measures and the successful-ness of these programs also plays a role inassuring that the ambitious energy efficiencymandate is attained. Even given the breadth anddetail of the recently passed energy act, thereremain, however, several areas where additionallegislation may be appropriate to further goals ofincreased energy efficiency and greater use ofintegrated least-cost planning methods.

Much of the success of these initiatives willdepend on how they are implemented and willrequire continued congressional oversight andsupport.

INTEGRATED RESOURCE PLANNINGIRP is a technique used by utilities and State

energy regulatory agencies to develop plans forproviding reliable and economic electric powersupply for customer needs. The process includesexplicit consideration of both supply-side anddemand-side resource options. The process be-gins with development of a range of projectionsof future electricity demand under alternative


future scenarios. Next, the planners assemble amenu of potential resource options for meetingthose energy service needs including both supply--side resources (new generation, transmission anddistribution (GT&D) facilities, retrofit or im-provement of existing GT&D facilities, and/orbulk power purchhases) and Utility-Sponsored demand-side resources (conservation, load management,and end-use efficiency improvements). The life-time capital and operating costs, availability,reliability, and suitability of the various supply-and demand-side resource options are then com-pared to develop an overall plan to meet identifiedfuture needs. There are several competing meth-odologies for defining what resource choicesconstitute a “least-cost” mix. In developing aleast-cost plan, some planning processes requirethat environmental externalities be quantified andexplicitly weighed in the resource selectionprocess, others give preferences to certain tech-nology choices, i.e., locally produced coal, DSM,low carbon emissions, or renewable resources.The planning process usually includes publicparticipation and comment and may requireapproval of State regulators before adoption.After adoption, the plan is used to guide utilitychoices in acquiring new resources.

Many utility analysts and energy-efficiencyadvocates believe that, compared with past supply-oriented utility planning methods, IRP will favorthe selection of more cost-effective, more effi-cient, and more environmentally-friendly energytechnologies, including renewable energy tech-nologies and demand-side options. Adoption ofan IRP process alone will not automaticallyproduce these results. What is even more impor-tant are the policy choices made in establishingthe goals and in weighing the costs, reliability,and other attributes of alternative technologychoices in resource plans.

Adopting formal utility IRP processes hascertain clear effects that are usually deemedpositive by State regulators. First, the IRP processopens up utility resource planning to review andinfluence by the public, potential resource suppli-

ers, and regulators. IRP creates a mechanism forconsideration of a wider variety of potentialresources and future planning contingencies thanmight be the case under past internal supply-oriented utility planning procedures. Opening theprocess creates opportunities for developing broaderconsensus among utility decisionmakers, ratepay-ers, regulators, and other interested parties aboutpreferred strategies-perhaps lessening some ofthe contentiousness of adversarial proceedings oncapacity and rates. Indeed, some States andutilities have made collaborative consensus-building efforts a keystone of their overall IRPprocess. Open planning will perhaps avoid someof the problems of utility construction programsof the 1970s when unneeded capacity and costoverruns in a time of slower demand growthproduced protracted, bitter rate hearings anddisallowances of recovery for investments laterfound to be imprudent. Rigorous and openadvance review of utility plans and periodicreassessments also encourages more flexibleresponses to changing conditions.

Among the potential disadvantages of broaderapplication of IRP among States and utilities arethe additional procedural burdens it could imposeon smaller utilities and State regulatory programs.Many smaller investor-owned public power andcooperative utilities may not have the resources,personnel, or need to do extensive independentIRP. Their needs could perhaps be as well servedby participation in State or region-wide planningexercises. For some utilities and financial ana-lysts, more open planning processes and StateIRP approvals may be perceived as diminishingthe utility’s control over resource choices. Thereis no doubt that this is a goal of some IRPproponents. However, for many utilities, adop-tion of IRP with its more explicit consideration ofplanning uncertainties and inclusion of moreflexible supply and demand alternatives is anatural response to the changes in the utilityoperating environment in the 1980s and 1990s.Expanded use of IRP will require some utilities touse longer plarming horizons than previously, and


public and regulatory review will mean thatresource planning may take longer than when itwas a purely internal exercise. Offsetting this, ofcourse, is the expectation that implementation ofthe plan will be smoother.

To encourage the expanded use of IRP, Con-gress could direct State regulatory agencies toconsider adopting rules requiring jurisdictionalutilities to use IRP. This option follows theapproach established by the Public Utility Regu-latory Policies Act of 1978 (PURPA) and upheldin the courts and avoids a direct clash betweenState and Federal powers or preempting Stateauthority. State regulators can constitutionally bedirected to consider a proposed action within aspecific period of time, but the decision whetherto adopt IRP and the precise form it would take isleft to the States. The legislation might furtherprovide that States consider requiring that utilityinvestments in supply and demand-side resourcesbe consistent with the State integrated resource/least-cost plan. The Energy Policy Act of 1992, indeed,took this approach and requires State regulators toconsider several policies under PURPA section111 on IRP, DSM, and supply-side efficiencyinvestments.

More than half of the States have alreadyadopted some form of IRP requirement withoutany Federal prodding-attesting to the attractive-ness of the process to State regulators (see chapter6). Many of the remaining States are alreadyconsidering IRP proposals. These developmentsmean that utility IRP will grow even withoutFederal legislation. A key issue in formulation ofadded Federal requirements would be how exist-ing State IRP programs should be treated. ShouldState regulators initiate new proceedings to con-sider IRP anew, or would the legislation exemptStates that had already adopted plans? Imposingnew procedural requirements could divert scantresources and personnel away from implementingexisting initiatives. Utilities, too, would likelyobject to additional requirements. To minimizethis outcome, legislation could provide for States

to certify that they have already met the proce-dural requirements for IRP consideration.

The Federal Government could also provideadditional inducements for State adoption of IRPwith or without any direct Federal requirement forformal State rulemakings to consider adoptingIRP.

Federal financial and technical support couldbe provided for State development andimplementation of IRP/LCP requirementsthrough direct grants to State agencies, andfunding of cooperative research on IRPmethodology. This assistance could helpoffset the impact on State agency budgetsand staffing of developing and implement-ing IRP programs. The Energy Policy Act of1992 includes authorization for grants toState regulatory agencies of up to $250,000to implement various efficiency initiatives.Congress could require that Federal actionsincluding FERC rulings be consistent withState approved integrated resource plans. IfFERC rulings are not consistent with ap-proved regional or State least-cost plans,FERC actions should be subordinate to Stateactions needed to implement these plans.Congress could amend the Federal PowerAct to delegate more authority over whole-sale rates and intrastate electric power transac-tions from the FERC to States that haveadopted IRP programs that meet certainminimum Federal standards.Congress could authorize States to enter intoregional compacts for purposes of devel-oping and implementing integrated resourceplans for utilities that operate in more thanone State or that are members of multistatetight power pools. Congress might furtherrequire that utility resource plans be consist-ent with these regional or multistate plans.

The comprehensive energy legislation passedin 1992 did not address issues of State and Federalregulation involving resource planning. Various


proposals to clarify respective roles in regionalplanning and to close the regulatory gap createdby recent developments have been offered. (Seechapter 3.)

DEMAND-SIDE

DSM refers toaffect the timing

MANAGEMENT

utility-led programs intended toor amount of customer electric-

ity use. These include energy efficiency programsaimed at reducing the energy needed to servecustomer needs and programs that shift electricitydemand to reduce peak loads or to make moreeconomic use of utility resources. A variety ofDSM mechanisms are in effect, including auditand information programs, rebates and otherconsumer financial incentives, direct installationprograms, technical assistance, and energy per-formance contracting.

Utility DSM programs are rapidly proliferatingin extent and cost. Estimates of current annualutility DSM expenditures range from severalhundred million dollars to almost $2 billion. Onelarge California utility is poised to spend $1billion on energy efficiency investments over thenext decade and is awaiting the blessing of theState public utility commission. Equally ambi-tious efforts are being mounted in other jurisdic-tions as utilities announce plans to meet asignificant portion of their demand growth in the1990s through energy efficiency.

DSM programs have had mixed success todate. Many have delivered dramatic electricitysavings at low cost-demonstrating their prom-ise. However, many other programs have had lowrates of customer participation, produced actualenergy savings that were less than predicted, andlacked adequate evaluation and verification ofenergy savings over time (see chapters 5 and 6).For energy conservation and efficiency to becometrue alternatives to supply side resources, DSMefforts will have to be expanded in size and to awider range of end-use applications, customerparticipation rates will have to increase, and

actual savings will have to be closely monitoredand evaluated.

There are several options available for Federalencouragement of utility DSM programs.

Congress could direct State regulatory com-missions to consider requiring their jurisdic-tional utilities to establish or expand cost-effective DSM programs.The Federal Government could provide addi-tional financial and technical assistance toState agencies in developing, implementingand evaluating utility demand-side manage-ment programs. These could take the form ofdirect grants to State agencies, funding ofcooperative research and demonstration pro-gram, sponsorship of training programs forState regulatory personnel, collection anddissemination of information on variousState and utility DSM measures and theireffectiveness.

As noted, the Energy Policy Act of 1992 doesrequire States to consider financial incentives forDSM and conservation investments under PURPA,and authorizes Federal grants to State agencies.The legislation does not establish any newFederal program to aid in research and develop-ment and training in DSM evaluation.

U.S. DEPARTMENT OF ENERGYPROGRAMS

The DOE Integrated Resource Planning (IRP)Program, which has primary responsibility foradvancing IRP and DSM, has a modest budget ofa few million dollars and a very small staff. Theprogram originally was established in response tocongressional initiatives; its mission is to pro-vide technical assistance and support on utilityplanning issues including DSM. It has primarilyserved as a conduit for funds to support researchefforts at national laboratories, sponsor confer-ences, and provide small grants for cooperativeefforts. Overall, the program results to date havereceived praise from utilities, regulators, andefficiency advocates. The growth of IRP and

— ——


DSM programs and the more sophisticated tech-nical challenges they present for State regulatorsare rapidly outstripping the low budgets, modestresearch efforts, and limited expertise of the IRPProgram. Despite the high profile given to elec-tricity efficiency in DOE’s energy policy pronounce-ments and budget submissions, the size andactivities of the IRP office indicate the lowpriority actually attached to supporting utility IRPand DSM (see chapter 7). If Congress wishesDOE to provide leadership and support to Stateefforts and provide needed imputs to nationalenergy policy debates, the IRP Program will haveto be expanded and given adequate resources toestablish a strong institutional presence to ad-vance IRP and other utility energy efficiencyprograms.

There are clear opportunities for the FederalGovernment to be involved in research, develop-ment, and demonstration (RD&D) activities toadvance utility efficiency initiatives. Utilities arefunding significant amounts of resource inde-pendently and through the Electric Power Re-search Institute. Continued cooperative effortswith Federal agencies and national laboratoriesshould be encouraged. The potentially largeamounts of funds at stake in utility demand-sideprograms suggest that Federal policymakers andState regulators also have a need for independentand impartial assessments of IRP methods, DSMprograms, and alternative regulatory incentivesfor efficiency investments. DOE-sponsored re-search can serve this public need by expandingRD&D efforts on DSM, supply-side efficiencytechnologies, IRP, conservation and load man-agement methodologies, and on energy efficiencyestimation, metering, monitoring, and evaluationtechnologies. Such research should include engi-neering, behavioral, and policy studies to assistimprovement of DSM and IRP efforts. Theresearch could be funded by redirecting a smallportion of funds now devoted to supply technolo-

gies. opportunities for joint funding of researchby the Federal Government, State agencies,utilities, trade associations and other interestedparties could also be authorized and would allowleveraging of Federal research dollars.

UTILITY RATE REFORMSUnder traditional approaches to utility ratemak-

ing, utility profits are based on sales of kilowatt-hours of electricity and total investment ingenerating, transmission and distribution equip-ment (see chapters 3 and 6). Almost withoutexception, every additional kilowatt-hour sold bya utility yields a profit.3 Investments that promoteenergy efficiency and reduce electricity con-sumption, lower sales and threaten profits. Statesare currently experimenting with various regula-tory mechanisms to decouple utility sales fromprofits and to make efficiency investments moreattractive to utilities and their shareholders asdetailed in chapter 6. To support these Stateefforts, Congress could:

Direct DOE to expand funding for researchon model State utility regulations and inno-vative ratesetting mechanisms such as decou-pling profits from power sales, time of daypricing, interruptible rates, and performanceincentives for efficiency; research resultsshould be made widely available.Establish a DOE-supported multidiscipli-nary resource center to assist State regulatorsand utilities in developing and implementinginnovative rate reforms and in evaluating theresults.Provide grants to States for experiments indeveloping, implementing and evaluatinginnovative rate structures to encourage cost-effective supply and demand-side energyefficiency investment by utilities.

Congress could also follow the precedent ofPURPA and direct States to consider the adoption

3 David Moskovi@ Profits and Progress Through Utility Least-Cost Planm”ng (Washington DC: National Association of RegulatoryUtility Commissioners, 1989).


of ratemaking mechanisms that provide utilitieswith financial incentives for implementing cost-effective efficiency improvements and the En-ergy Policy Act of 1992 does this. Again, morethan half of the States have already adopted somefinancial incentives for utility demand-side effi-ciency investments. Congress, could of course gofurther and require that State regulators adopt rateprocedures that make demand-side efficiencyimprovements at least as profitable for utilities asinvestments in new supply-side resources. Thisdirect, and obviously preemptive approach wouldlikely be viewed with disfavor by many Stateregulators who believe that the choice of a properincentive is a matter of State policy. Someconsumer representatives would likely argue thatsuch provisions could distort rates unnecessarilyas utilities are already under some obligation toinvest in cost-effective efficiency measures as ameans of minimizing rates whether or not they areas profitable for shareholders as new generatingplants.

FEDERAL REGULATION OFPOWER TRANSACTIONS

While much Federal influence over utilityplanning and State ratemaking policies is indirect,there are three areas where the Federal Govern-ment can directly influence utility resource plan-ning

1.

2.

3.

and energy efficiency investments:

FERC regulatory authority over wholesalepower transactions and transmission ar-rangements.Operation of five Federal power marketingadministrations that supply power to localutilities and oversight of the operations ofthe Tennessee Valley Authority.Rural Electric Administration loans andloan guarantees to electric cooperatives.

The Federal Government can provide leadershipin adoption of IRP and cost-effective energy

efficiency investments through its establishedregulatory and administrative authority in theseareas.

The extent to which FERC on its own initiativeand as a matter of policy could require utilitiesengaged in wholesale power transactions andmultistate holding companies to develop inte-grated resource plans is not clear, even if FERCwere inclined to do so (see chapter 3).4 FERC hasused its conditioning authority to induce utilitycompliance with various FERC economic policyinitiatives, most recently open transmission ac-cess. Under the recent policy directions of FERCtoward greater reliance on competition and market-based prices, it seems unlikely that the commis-sion would advance new policies that wouldinvolve it more deeply in consideration of thedetails of resource planning and least-cost deter-minations of utilities that are either purchasing orselling power. Current FERC electricity policiescould actually work to increase disincentives toinvestment in DSM. FERC could, however, useits rate design authority to eliminate biasesagainst investment in DSM by wholesale powerproviders and purchasers. As a practical matter,FERC is largely bereft of the expertise that wouldallow it to pass on the merits of utility resourceplans and DSM programs. Even if FERC does notbecome involved in promoting IRP and demand-side management, its preemptive jurisdictionover wholesale transactions and cost allocationsin multistate holding companies has the potentialto frustrate State initiatives at least-cost planningand DSM.

As mentioned above, if Congress wishes tosupport State implementation of IRP and DSMprograms it could amend the Federal Power Actto require that FERC decisions be consistent withState-approved integrated resource/least-cost plans.To accomplish this, FERC could be directed torevise its procedures so that State regulators andother 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).


in wholesale proceedings to make regional orlocal interests known to the commission.

In the late 1980’s the Tennessee Valley Au-thority (TVA) has discontinued its energy conser-vation and DSM programs and began to look atthe need for adding new generating capacity in thelater 1990s to meet the needs of its customers.Congress could require that TVA develop andimplement its own least-cost planning program todirect its future resource acquisition strategies. Itfurther could authorize and require TVA to investin demand-side resources where it is cost-effective to do so as an alternative to constructionof new generating capacity. TVA could also bedirected to require its customer utilities to adoptIRP processes and to certify that purchases are incompliance with their plans. TVA could bedirected to reestablish its programs in support ofenergy efficiency and conservation and providetechnical assistance in these areas to its custom-ers. The Energy Policy Act of 1992 does just thisand requires TVA to adopt a least-cost planningprogram including participation by its distribu-tors and the public.

Congress could require that the Federal powermarketing administrations adopt an IRP approachand require their customer utilities to adopt IRP asa condition of power contracts. Under existinglaw, the Bonneville Power Administration al-ready engages in extensive regional power plan-ning and must give preference to conservationand renewable resources in its power procurement(see chapter 7). The Western Area Power Admin-istration has already embarked on a regulatoryeffort to require its customers to engage in limitedIRP as a part of its power supply contracts. TheEnergy Policy Act of 1992 incorporates much ofthis into statute. The much smaller SouthwesternPower and Southeastern Power Administrationshave not yet implemented planning or energyefficiency programs directed at their customers.Southwestern is cooperating with Western indevelopment of programs and materials to help

customer utilities implement IRP. Legislationhas been introduced to approve the sale of theAlaska Power Administration.) Design of IRPand DSM requirements for power marketingadministration customers must be done with careand sensitivity to the small size and limitedresources of many public power utilities andcooperatives, and potential for Federal require-ments overlapping with conditions imposed underState regulation.

Congress could require that cooperatives seek-ing REA loans or guarantees for new generationfacilities demonstrate that they have adopted anIRP process that includes explicit considerationof energy efficiency alternatives and that theproposed facility is consistent with the least-costplan. REA has already moved in this direction byrule. Legislation could reinforce and make perma-nent such conditions for REA transactions. Again,caution must be exercised in the design ofrequirements because of the size of many cooper-atives and the possibility of overlap with Stateand other Federal agency requirements.

LEADING BY EXAMPLE: THE FEDERALGOVERNMENT AS ENERGY CONSUMER

The Federal Government is the Nation’s largestsingle energy consumer, in fiscal year 1989 itspent over $8.7 billion on direct energy purchasesfor its own facilities and operations and about $4billion more subsidizing the energy expenses oflow-income households under various programs.Not reflected in this direct energy expenditure ofsome $12.7 billion are the additional energy costsfor leased space for which the Federal Gover-nment does not pay utilities directly. Payments toelectric utilities accounted for an estimated $2.4billion of the fiscal year 1989 Federal energy billfor government buildings.

The Office of Technology Assessment’s (OTA)May 1991 report, Energy Efficiency in the Fed-


eral Government: Government by Good Ex-ample, 5 found that despite a wide array ofprograms and policies developed over the past 15years, the Federal Government still has manyopportunities to improve energy efficiency in itsfacilities and operations using commercially avail-able, cost-effective measures. OTA estimated thattotal Federal Government energy consumptioncould be cut by 25 percent with no sacrifice tocomfort or productivity. There are many meas-ures with potential returns of 30 to over 100percent. OTA’s report found that existing Federalprograms and present funding levels maintainprogram capabilities and will yield gradual im-provements in Federal energy efficiency. How-ever, the status quo is not sufficient to capturesignificant savings opportunities. At the presentlow level of energy efficiency funding andstaffing for individual agencies, OTA estimatedthat it would take several decades to make all theeconomically attractive investments. During thattime tens of billions of dollars would be unneces-sarily spent to buy inefficiently used energy.

The Energy Policy Act of 1992 toughensenergy efficiency standards for Federal buildings,sets a new deadline of 2005 for Federal agenciesto install cost-effective, energy- and water-savingtechnologies, and contains a number of othermeasures to raise agency awareness and financialcommitments to energy efficiency improvements.Nevertheless, taking full advantage of existingopportunities will require a higher priority forenergy efficiency as reflected in adequate invest-ment funding and staffing. One alternative isprivate sector financing in the form of utilityrebate programs and shared energy-savings con-tracts that can be used to supplement directFederal investments.

OTA found significant benefits associated withFederal actions to support energy efficiency.

Setting a good example by demonstrating thecost and performance of a wide range ofenergy-efficient technologies and practicesin its own facilities and operations,Creating market pull for energy-efficientgoods and services through Federal purchas-ing power and promoting earlier introductionof high-efficiency technologies by specify-ing the most cost-effective energy efficiencyproducts. 6

Providing first-hand experience basis fornational energy policy on the technical andcost performance of energy efficiency meas-ures from Federal projects.Cutting Federal spending through energyefficiency savings; andReducing the environmental, health andsecurity costs of energy use. Among thecongressional policy options for making theFederal Government a leader in advancingcost-effective energy efficiency measuresare several that would encourage Federalagency participation in utility-sponsored de-mand management programs.

Congress could use its oversight and appro-priations processes to press Federal agency mana-gers to give greater priority to funding andstaffing to achieve the variety of existing congres-sional and presidential directives to cut buildingenergy use and improve energy efficiency inoperations. A 1991 Executive Order calls for areduction in Federal building energy use by atleast 20 percent by 2000 compared to 1985 andgreater participation in utility DSM services.7

Congress could provide clear authorization anddirection for Federal agencies to participate inutility 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 energyefficiency programs, and to incur obligations forfinancing of efficiency measures. Confusion overagency eligibility and authority to enter intoutility demand management programs was foundto have deterred participation. Congressionallegislation has already been enacted that specifiesthat Federal agencies (principally the Departmentof Defense and the General Services Administra-tion may enter into shared energy savings con-tracts for federally-owned buildings and facili-ties. 8 The Energy Policy Act of 1992 expands thatauthority and specifically encourages agencies toparticipate in utility programs and to negotiatewith local utilities for demand-side managementprograms specially tailored to the needs andcharacteristics of government facility loads.

Federal agencies could themselves becomepurveyors of energy efficiency savings to meetutilities’ resource needs. Many Federal facilitieswould be attractive targets for energy efficiencysavings under utility programs seeking cost-effective demand-side resources. Federal facili-ties managers should be authorized to enteragreements with energy services companies ordirectly with utilities to offer these potentialresources in competitive procurements. Undersuch arrangements, utilities might install effi-ciency measures directly, the agency might payfor the measure and receive a rebate for some orall of the costs of the measures, or an energyservice company would install the measure andrecover its costs and profits from the utility. Suchagreements at a minimum should provide thatFederal payments for efficiency measures do notexceed the value of electricity bills that wouldhave been due if the measure had not beeninstalled.

Congress could assure that agencies devotesufficient funds and competent well-trained per-sonnel to oversee and administer energy effi-


ciency efforts, including those funded in whole orin large part by private funds through utilitydemand management programs or agreementswith energy service companies. Several provi-sions of existing law and executive order attemptto do that through the budgeting process andreporting requirements.

As an additional incentive agencies could beallowed to keep some or all of the proceeds fromenergy efficiency rebates for either general pro-gram activities or for additional energy efficiencymeasures. Existing law authorizes retention of aportion of such energy savings in DOD facilitiesand allows them to be used for recreation.

Technical support could be provided to agencyenergy efficiency coordinators/personnel to aidthem in identification of efficiency opportunitiesand provide assistance in negotiations with localelectric utilities and energy service companies.These might include establishment of severalregional model or demonstration energy effi-ciency facilities.

OTA’s report on the Federal Governmentexperience suggests that rewards for good per-formance in agency energy efficiency measureswould also aid both agency management andenergy efficiency staff deterrnination in capturingpossible savings. In addition to the prior sugges-tion that agencies be allowed to keep all or aportion of savings, additional incentives mightinclude establishment of well-publicized agencycitations or awards for energy efficiency savingsand bonuses for individual energy managers.

Improving the energy efficiency of Federalbuildings and operations will require a long-termcommitment and many novel approaches to newsituations. It will be important that efforts beperiodically evaluated and that successes andfailures alike be analyzed and the results distrib-uted among public and private energy managersso 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-EFFICIENTTECHNOLOGIES

Opportunities for Electric Utilities

Federal support for improvements in the avail-ability of energy-efficient equipment in the mar-ketplace can complement utility energy effi-ciency programs. In addition to creating a marketpull for efficiency by creating incentives forutility investment in DSM measures, Federalefforts can create a market push to raise theefficiency of new products.9

H Information, Labeling andEfficiency Standards

Among possible approaches is strengtheningand expanding Federal efficiency standards andlabeling and consumer information requirementsapplicable to buildings and to household andcommercial appliances, fixtures, and electricalequipment. These actions provide consumerswith more information on energy use and canrequire that new buildings and products incor-porate cost-effective efficiency technologies.

The Energy Policy Act of 1992 contains anumber of provisions relating to increasing theefficiency of electric equipment. Specifically, it:

Expands Federal energy efficiency standardlegislation to major categories of electricequipment including: lamps; shower heads;electric motors; commercial heating, cool-ing, and water-heating equipment; and distri-bution transformers.Requires existing Federal efficiency stand-ards for appliances and fluorescent ballaststo be raised to the highest levels that aretechnologically feasible and economicallyjustified.Adopts expanded Federal energy testing andlabeling requirements for light futures, of-fice equipment, and major consumer appli-ances, including life-cycle energy costs and

usage and comparisons to most efficientmodels.

The major share of residential and commercialenergy use is for heating, cooling, lighting andproviding hot water to buildings. Improving theenergy efficiency of buildings offers significantopportunities for energy savings. Options forexpanding and enforcing energy efficiency stand-ards for buildings include:

■

■

■

✘

■

Developing and applying energy efficiencyrating systems for new and existing commer-cial and residential buildings.Requiring DOE to work with national profes-sional and trade associations to developstrengthened energy efficiency standards fornew buildings to reflect the best cost-effective energy savings practices.Encouraging States to adopt these standardsas part of State building codes and assistingthem in strengthening building code compli-ance and enforcement procedures.Requiring sellers to provide information onenergy efficiency features and energy use ofbuildings.Requiring compliance with the new Federalstandards for federally assisted housing,mortgage guarantees, and Federal facilityhousing.

The success of such information, labeling andstandards programs will require at least fourconditions to be met. First, adequate funding andtechnical expertise must be available to developstandards for technically achievable and cost-effective energy-efficient technologies in a timelyfashion and to revise them periodically to reflecttechnical advances. Second, mechanisms must beput in place to educate Federal, State and localofficials, architects, manufacturers, wholesalers,equipment installers, and construction tradesabout new requirements. Third, monitoring andenforcement 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, Officeof 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 thenew standards. Lastly, the programs must beperiodically evaluated to assess their effective-ness (including review of quantitative indicatorsof energy savings, costs, ease of administration,alternative implementation methods), improve-ments needed, and the continuing need forgovernment involvement. Continuing congres-sional oversight and support will be key to assurethat the new initiatives will be successful inattaining their goals.

H R&D and Technology TransferFederal programs promoting efficiency ini-

tiatives through the utilities sector are limited inscope and funding. Most federally supportedefforts have been targeted at the buildings andindustrial sector and weatherization assistance forinstitutions and low-income consumers. Between1980 and 1990, Federal spending on conservationand efficiency technologies and programs wasslashed. Only congressional steadfastness keptmany programs alive. Funding of efficiencyresearch and development has begun to rise.However, most of the DOE research and develop-ment funds allocated as promoting electricityefficiency in budget documents actually supportconventional fossil technologies, nuclear powerand nuclear waste disposal programs.l0 Less than0.5 percent of the non-defense DOE research anddevelopment budget went to programs to improveenergy efficiency in the utilities sector.

The Federal Government support for research,development, demonstration and commercializationactivities can advance the availability of energy-efficient supply-side and demand-side technolo-gies. For example, the DOE Clean Coal programcould be redirected to give more preference totechnologies that improve powerplant efficiencyand reduce environmental impacts of burningcoal. Similar objectives can be applied to fundingof other advanced electric power technologies

offering significant efficiency gains. (for exam-ple, advanced generating technologies such asadvanced gas turbines, and fuel cells, improve-ments in automation, monitoring, and dispatchcontrols, and high-efficiency transmission anddistribution technologies.) Efforts should be di-rected at technologies for new construction andfor retrofitting/repowering old generating plants.Research efforts should yield information on theperformance characteristics, and theoperating costs of these technologiesmore available to State regulatorsplanners.

capital andto be madeand Utility

INCREASING UTILITY RESOURCE OPTIONSA wider range of cost-effective supply- and

demand-side resources will increase potentialbenefits to utilities and customers from the fullimplementation of IRP. Proponents of greatercompetition in electric power supplies contendthat competition will bring market forces to bearto force greater efficiency in resource selectionand in the development of new power technolo-gies. Allowing demand-side measures to competeagainst supply-side options can help foster selec-tion of more cost-effective efficiency alternativesto new powerplant construction.

Utility resource planning and supply acqui-sition have largely been matters of State jurisdic-tion. However, if as seems likely, expandedcompetition results in more wholesale powertransactions, Federal authority over resource ac-quisition will increase. This enlarged influencecould hinder rather than encourage efficiencygains if utility transactions receive Federal ap-proval without regard to State least-cost plans.

I Expanding CompetitionCongress 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


Requiring utilities to acquire new powerresources through competitive procurementmechanisms and requiring the inclusion ofdemand-side options in the competition.11

Amending the Public Utility Holding Com-pany Act (PUHCA) to encourage participa-tion in bulk power and energy efficiencyindustries by broader group of potentialsuppliers.

The Energy Policy Act of 1992 creates a newexemption to PUHCA for entities engaged inwholesale generation markets. The exemption isapplicable to utility affiliates.

i Transmission AccessIncreased access to the transmission grid has

been advocated as a means to expand utilityresource options and to open additional marketsfor capacity and electricity made availablethrough efficiency efforts. Greater access totransmission facilities increases opportunities forpower producers to sell power and for buyers tochoose from a potentially greater variety of sellersand a wider range of generating options. Amongoptions Congress could consider for encouragingmore open transmission access are:

Authorizing voluntary transmission-sharingmechanisms through regional agreementsand joint planning among all prospectivetransmission users—both utilities and inde-pendent generators-under nondiscrimina-tory guidelines to be established by theFERC.Requiring the FERC to consider condition-ing approval of special rate treatment, merg-ers, etc. on the petitioning utilities offeringexpanded non-discriminatory access to theirtransmission services.Providing additional Federal authority torequire utilities to provide transmission serv-ices with protection for system reliabilityand native customer loads.

Directing the FERC to defer to State effortsto improve transmission access and trans-mission services by State jurisdictional utili-ties unless the State efforts were found to beunjust, unreasonable, or to confer unduecompetitive advantage.

The Energy Policy Act of 1992 gave FERCexplicit authority to order transmission access forwholesale transactions. The controversial detailsof pricing policies and information requirementsto carry out this mandate have been left to FERCand progress on these matters will have to bemonitored to determine if additional mechanismsare needed. Many utilities have been pressing forlegislative approval for organization of voluntaryregional transmission groups as a more flexiblealternative to mandatory wheeling orders.

LEVELING THE PLAYING FIELDIN RESOURCE PLANNING

Because most energy prices do not reflect all ofthe social and environmental costs of particularenergy choices, many economists and energyanalysts believe that market-based mechanismsalone cannot be relied upon to produce the mostefficient options from a social, environmental,and economic perspective. (A similar imperfec-tion is also introduced by the tax and other“subsidies” that some fuels enjoy.)

1 Energy TaxesOne way of correcting such market failures

would be to impose taxes on various energysources that reflected the costs they imposed onsociety and the environment. In fact, in Europeand Japan, high energy taxes perform this func-tion in some respects. Energy taxes have provento be a controversial and unpopular approach forattaining energy policy goals in the United States.Recently, there has been renewed interest inenergy taxes, not only as a means to promoteenergy 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.


‘‘market-based mechanisms’ currently in vogueamong some policy analysts, but also as a meansof increasing Federal revenues to reduce budgetdeficits. The Clinton Administration’s Btu taxproposal would have imposed a small tax on abroad range of energy sources, but was rejectedby Congress in favor of an increase in thetransportation fuels tax.

I Internalizing Social andEnvironmental Costs

An alternative to energy taxes is to use asurrogate price adjustment in the resource plan-ning process so that relative costs of energyoptions are more adequately reflected and energychoices compete on a more level playing field.One method, for example, would be requiring thatStates and utilities include consideration of socialand environmental costs/’ ‘externalities’ in eval-uating supply- and demand-side resources indeveloping least-cost plans. Including adjust-ments for externalities in the plannin g processavoids most of the political and economic impactsof direct energy taxes, while offsetting marketimperfections in energy choices. Many conserva-tion and renewable energy advocates believe thatconsideration of externalities in cost-effective-ness determinations would boost prospects forthese options being selected in utility resourceplans. However, some economists would say thatthe choice of a perhaps higher-priced energyoption would impose a hidden environmental/social energy tax.

Consideration of externalities in resource choicesis already required in many States, but experience

is limited and the State efforts have proved highlycontentious and politically controversial. More-over, economists are deeply divided over whetherand how to fashion mechanisms to internalizesuch costs in energy decisionmaking. SomeStates, such as Massachusetts and California,have attempted to set a specific quantitative valueon external environmental costs to be used inevaluating competing resource choices, whileother States have opted for a more qualitativeapproach. Various legislative proposals havebeen made that would require Federal agenciesand utilities to consider life-cycle costs of energyoptions, including environmental and social costsand benefits to the maximum extent possible, indeveloping least-cost energy plans.

Whatever the conceptual difficulties of at-tempting to include externalities in integratedresource planning, as a practical matter Stateregulators and utilities are already doing it tosome extent and proposals for expanding thisapproach to other States and Federal actions willincrease. Given experience to date, there is noclearly preferred or accepted method of address-ing the externalities problem. This suggests thatany Federal action to require explicit quantifica-tion of externalities is premature. Congress coulddirect DOE to support research on alternativemethods for assessing and quantifying environ-mental, social, and other externalities in least-costplanning and to report back on the experience todate, additional research needs, and the feasibilityof including external costs in Federal least-costplanning.

Enity 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 specialresponsibilities in return for assurances of the opportu-recover their costs, and for investor-owned utilities, to

earn a reasonable return on their investments. Maintaining thereliable operation of the Nation electric power systems requiresa high degree of cooperation and coordination among sometimescompeting utilities and adherence to stringent performancestandards. Yet, there is great diversity in the structure andorganization of the industry. The recent growth of unregulated,independent power producers and pressures from consumers andregulators for greater utility investment in electricity-savingtechnologies pose new challenges for utility operations and theregulatory compact.

This chapter providessector. It begins with a

an overview of the electric utilitieslook at utility energy use, financial

characteristics, environmental considerations, and an overviewof industry structure. Next, it gives a brief introduction to Stateand Federal regulation of electric utilities. It concludes with anoverview of utility system operations.

ELECTRIC UTILITIES IN THE US. ECONOMY

@ Energy UseElectric utilities are among the Nation’s biggest energy users

and energy producers. Utility power generation accounts for 36percent of total primary energy use in the United States or 29.6

I 27


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 datafrom 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.) Energyuse for electric power generation as a share of theNation’s total energy consumption has beengrowing-faster than growth in demand for otherenergy sources—and that trend is projected tocontinue.

Utility fuel demand strongly influences thegrowth and structure of primary energy markets.In 1990 energy inputs for providing electricityaccounts for virtually all nuclear power, 86percent of coal use, 15 percent of natural gas, 3percent of oil consumption, and over 40 percentof renewable energy production.2

Of the 29.6 quads of energy input to electricutilities to produce power, only 9.3 quads weredelivered to retail customers as electricity.3 On

Figure 3-2—U.S. Primary Energy Consumption bySector, 1990 (quadrillion Btus)

Utility power generation 36%

Industrial 24°A19.9

Residential &commercial 12% T r a n s p o r t a t i o l

onbwl I II 1 2 7 %

SOURCE: Office of Technology Assessment, 1993, based on datafrom 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 energyinput to electric power generation and transmis-sion is available/delivered to meet customerneeds. The rest is lost to inefficiencies in powergeneration processes-heat loss, incomplete com-bustion, and transformer and line losses in trans-mission and distribution. Thus, even modestgains in the efficiency of electricity productionand delivery systems could make significantcontributions to improving overall energy effi-ciency. And the impacts of demand-side electric-ity 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 beconsidered an energy carrier, the means by which the energy content of fuels, falling water, sunlight, etc. is captured and converted to electricitythat is then used to power other activities or energy serviees, electric utilities are at times categorized as energy producers rather than energyconsumers. As a result, electric utilities would be omitted from profiles of energy consumera, and the primary energy inputs used by them togenerate 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 Statisticsby Sector, 1990

Figure 3-3-Electricity Sales by Sector(billion kWh)

Sales to ultimate consumers (billion kWh). . . . . 2,713Residential. . . . . . . . . . . . . . . . . . . . . . . . . . . . 924Commercial. . . . . . . . . . . . . . . . . . . . . . . . . . . 751Industrial. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 946Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 92

Revenue from sales to ultimate consumers($billion). . . . . . . . . . . . . . . . . . . . . . . . . . . . . 178

Residential. . . . . . . . . . . . . . . . . . . . . . . . . . . . 72Commercial. . . . . . . . . . . . . . . . . . . . . . . . . . . 55Industrial . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 45Other*. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6

Average revenue/kWh (cents). . . . . . . . . . . . . . . 6.6Residential . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7.8Commercial. . . . . . . . . . . . . . . . . . . . . . . . . . . 7.3Industrial. ..,.. . . . . . . . . . . . . . . . . . . . . . . . 4.7Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.4

Emissions (million short tons)b

Sulfur dioxide (SO2). . . . . . . . . . . . . . . . . . . . . 16.5Nitrogen oxides (NOx). . . . . . . . . . . . . . . . . . . 7.1Carbon dioxide (C02). . . . . . . . . . . . . . . . . . . . 1,976.3

a includes public street and highway lighting, other sales to publicauthorities, sales to railroads and railways, and interdepartmentalsales.

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 arepreliminary. Totals may not equal sum of components because ofindependent rounding.

SOURCE: Office of Technology Assessment, 1993, based on informa-tion 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 fuelsupply side.

I Revenues andElectricity sales

electric utilities an

and capacity savings on the

Capital Investmentsand capital investments makeinfluential force in the econ-

omy. In 1990, consumers paid over $179 billionfor electric power. 4 Table 3-1 and figure 3-3 showpower sales and revenues by customer class, Theretail cost of electricity varies significantly amongthe customer classes. Industrial customers gener-ally are charged less per kilowatt-hour (kWh)

Commercial 28°/0753

// ’ ”

/

35%

‘\x=’’’’’0’h~030’0Resldentlal 34%

922

SOURCE: Office of Technology Assessment, 1993 based on data fromU.S. Department of Energy, Energy Information Administration, AnnualEnergy Review 7990, DOE/ElA-0384 (90) (Washington, DC: U.S.Government Printing Office, May 1991), table 94, p. 215.

than residential or commercial customers. Utili-ties justify this on the basis of lower costsincurred to serve industrial customers with largeloads and often a single point of delivery,compared with residential service characterizedby many dispersed customers with relatively lowindividual electricity sales volumes and higherassociated transmission and distribution invest-ment and electricity losses per kilowatt-hour sold.Lower prices are also justified to maintain marketshare and to discourage industrial customers fromleaving the system by turning to natural gas orself-or cogeneration for energy needs—whichcould result in stranded investment costs thatmust be borne by remaining customers in the formof higher rates.

On a national average, the nominal price ofelectricity in 1990 was 6.6 cents/kWh, up from

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

..———


Figure 3-4-Average Retail Electricity Prices,Nominal and Real (1987 dollars)

Cents/kWh87

RealI 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 datafrom 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 electricityprices have, on average, declined during the lastdecade (as shown in figure 3-4). Adjusting forinflation, average retail electricity prices in 1990of 5 cents/kWh are 10 percent less than they werein 1980.5

The utility industry is highly capital-intensive.Investor-owned utility capital investment in plantand equipment was valued at $379 billion in1990. 6 Total assets of public power systems andrural electric cooperatives were estimated at

$125.8 billion in 1990.7 Estimates of new con-struction spending for investor-owned utilitieswere some $26.3 billion in 1990 according to oneindustry survey.8 The largest share of this capitalinvestment, $13.6 billion, was earmarked fortransmission and distribution construction andimprovements; only $8.9 billion was for buildingnew generating plants-a shift from the massivenew powerplant construction expenditures of the1970s and early 1980s.

1 Environmental ImpactsElectric power generation is a significant

source of air pollution and carbon dioxide (CO2)emissions and thus has been a focus of environ-mental protection and cleanup efforts. In 1990electric utilities’ fossil-fired steam electric-generating plants spewed 16.5 million tons ofsulfur dioxide (SO2), 7.1 million tons of, nitrogenoxides (NOX), and 1,979 million tons of carbondioxide into the air.9 According to data collectedby the U.S. Environmental Protection Agency(EPA), burning of sulfur-laden coal and residualfuel oil by electric utilities accounted for over 80percent of SO2 emissions in 1989.10 Electricutilities also were the source of some 60 percentof NOX emissions in that year, Electric generationis responsible for about 35 percent of total carbonemissions in the United States and electricutilities account for almost all of these emis-sions.

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 kmapproximately 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 in-crease the attractiveness of energy efficiencyalternatives through demand-side management(DSM).

The Federal Clean Air Act required installationof pollution controls at electric generating plants,reducing emissions and spurring the developmentof cleaner, state-of-the-art powerplants. Stringentnew acid precipitation provisions of the Clean AirAct Amendments of 1990 will require electricutilities to make further reductions in theiremissions of SO2 and NOX starting in 1995. Theserequirements will fall most heavily on Easternand Midwestern utilities now burning high sulfurcoal and potentially involves billions of dollars innew investment in control technologies to be paidfor by ratepayers. One potential result could bethe accelerated retirement or life-extending re-powering of older plants. The 1990 Amendmentsalso offered utilities another option for compli-ance. The option was to buy emissions allowances-a kind of license to pollute-from other utilitieswho have reduced their emissions below requiredlevels, This innovative ‘market-based’ approachto environmental regulation-a new system oftradable pollution allowances-was included inthe 1990 acid rain amendments and provides afurther spur to utilities to install pollution controlequipment, participate in integrated resourceplanning, and invest in energy efficiency in theiroperations. 12 The amendments established the

Conservation and Renewable Energy Reserve toaward additional emission allowances to utilitiesthat cut emissions by installing electricity-savingDSM measures or by using renewable energyresources.13

In addition to air quality impacts, other envi-ronmental effects associated with electric powergeneration are the extraction and processing offossil and nuclear fuel; construction and operationof hydroelectric, geothermal, solar, and windfacilities; and waste to energy plants. 14 Siting,construction, and operation of the plants cancreate local land-use conflicts, congestion andnoise impacts on neighbors, and adverse impactson natural habitats and wildlife. Power generationcontributes to water and waste pollution. Nuclearpower and handling and disposal of nuclear wastealso entail a special set of serious, contentious,and long-term environmental issues because ofthe radiation hazards. Opportunities to use energymore efficiently are also opportunities to avoidassociated environmental impacts of energy pro-duction.

Electric power transmission and distributionalso have associated environmental impacts be-ginning with local land-use conflicts in the sitingof power lines and substations. The constructionphase contributes to erosion, soil compaction,destruction of forests and natural wildlife habitatin the right of way. During operation, nuisanceeffects include visual impacts, audible noise,corona effects, and interference with radio andtelevision reception. Transmission systems canhave deleterious effects on local bird life throughcollisions with powerlines and towers and elec-trocutions. Use of chemical herbicides and othervegetation management techniques along rightsof way raises concerns about ecological impactsin some areas. In recent years, the as-yet-unproven possibility of human health effects fromexposure 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, ElectricPower Wheeling and Dealing: Technological Options to Increase Competition, OTA-E-409 (Washington, DC: U.S. Government PrintingOffice, May 1989), hereinafter OTA, Electric Power Wheeling and Dealing.

. —. -— -


become a prominent concern in siting transmis-sion and distribution facilities.l5

1 Industry StructureElectric utilities are the largest component of

the electric power industry, a diverse patchworkof investor and publicly owned utilities; con-sumer cooperatives; Federal, State, and localgovernment agencies; cogenerators; and inde-pendent power producers. The distinguishingcharacteristic of most electric utilities is that theyare regulated monopolies that sell power to retailcustomers.

America’s more than 3,200 regulated electricutilities supply electricity to over 110 millionhouseholds, commercial establishments, and in-dustrial operations. The differences among utili-ties in size, ownership, regulation, customer loadcharacteristics, and regional conditions are im-portant for policy. Table 3-2 shows selectedstatistics for the electric utility sector by type ofownership. Utility ownership and location deter-mine regulatory jurisdiction over utility opera-tions and rates.

Investor-Owned UtilitiesThe 267 investor-owned utility (IOU) oper-

ating companies dominate the electric powerindustry, generating 78 percent of the Nation’spower in 1990 and serving about 76 percent of allretail customers. IOUS are private, shareholder-owned companies ranging in size from small localoperations serving a customer base of a fewthousand to giant multistate corporations servingmillions of customers. Most IOUS are verticallyintegrated, owning or controlling all the genera-tion, transmission, and distribution facilities re-quired to meet the needs of the customers in theirassigned service area.

IOUS can be found in every State exceptNebraska. Their local operations and retail ratesare usually highly regulated by State public utilitycommissions, however their wholesale powersales and wheeling (power transmission) con-tracts fall under the jurisdiction of the FederalEnergy Regulatory Commission (FERC).

Control over IOUS is further concentratedbecause many of them are actually subsidiaries ofutility holding companies. Nearly one-quarter ofthe IOU operating companies are subsidiaries ofregistered electric utility holding companies regu-lated under the Public Utility Holding CompanyAct of 1935 (PUHCA) by the Securities andExchange Commission and FERC. The followingare registered utility holding companies: Al-legheny Power System, Inc., American ElectricPower Co., Central and South West Corp.,Eastern Utilities Associates, General Public Utili-ties Corp., Entergy Corp., New England ElectricSystem, Northeast Utilities, and The SouthernCo. In addition to the registered holding compa-nies, many other utilities are also part of holdingcompany systems consisting of affiliated utilitysubsidiaries operating intrastate or in contiguousStates and, thus, are exempt from detailed over-sight under PUHCA.

Publicly Owned Electric Power SystemsThe more than 2,000 public power systems

include local, municipal, State, and regionalpublic power systems ranging in size from tinymunicipal distribution companies to giant sys-tems like the Power Authority of the State of NewYork. Publicly owned systems are in operation inevery State except Hawaii. Together, local publicpower systems generated 9 percent of the Na-tion’s power in 1990 but accounted for 14 percentof 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 publishedsuggesting a link behveenmagnetic field exposures in the vicinity of local distribution lines and increased risk of childhood cancer. Pubtic healthconcerns have resulted in increased researeh funds for investigating this possible heatth hazard in hopes of determining what risks, if any, existand how tbey might be mitigated. In the meantime, utility commissions and utilities are now increasingly including assessments of ekxtric andwetic 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 fromSales 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 Wb

Percent Billion kWh Percent

investor-owned. . . . . . . 267 84 76 2,071 71 140 79 529 77 2,203 78Publicly ownedd. . . . . . 2,011 15 13 386 14 23 13 71 10 245 9Cooperatives. . . . . . . . . 953 12 11 201 7 14 8 25 4 126 4Federal e. . . . . . . . . . . . 10 <1 0 55 2 2 1 65 9 235 8Total. . . . . . . . . . . . . . . 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/EIA0348(90) (Washington, DC: U.S. Government Printing Office, January 1992).

-.-.<

%?tgF- .“2

. ——


many public systems are involved only in retailpower distribution and purchase power suppliesfrom other utilities.

The extent of regulation of public powersystems varies among States. In some States thepublic utility commission exercises jurisdictionin whole or part over operations and rates ofpublicly owned systems. In other States, publicpower systems are regulated by local govern-ments or are self-regulated. Municipal systemsare usually run by the local city council or anindependent board elected by voters or appointedby city officials. Other public power systems arerun by public utility districts, irrigation districts,or special State authorities.

Rural Electric CooperativesElectric cooperatives are electric systems owned

by their members, each of whom has one vote inthe election of a board of directors. They can befound in 46 States and generally operate in ruralareas. In 1990, rural co-ops accounted for 4percent of total power generation and 7 percent ofsales to ultimate customers.

Congress created the Rural Electrification Ad-ministration (REA) in 1935 to bring electricity torural areas and subsequently gave it broad lendingauthority to stimulate rural electricity use. Coop-eratives have access to low-cost govemment-sponsored financing through REA, the FederalFinancing Bank, and the Bank for Cooperatives.Early REA borrowers tended to be small coopera-tives that purchased wholesale power for distribu-tion to members. Over the past 20 years, however,many expanded into generating and transmissioncooperatives in order to lessen their dependenceon outside power sources.

Regulatory jurisdiction over cooperatives var-ies among the States, with some States exercisingconsiderable authority over rates and operations,while other States exempt cooperatives fromState regulation. In addition to State regulation,cooperatives with outstanding Federal loans fallunder the jurisdiction of REA, which imposes

various conditions intended to protect the fina-ncial viability of borrowers.

Federal Power SystemsThe Federal Government is primarily a whole-

saler of electric power produced at federallyowned hydroelectric facilities and has less than25,000 retail customers directly served by itssystems. Together, Federal systems had an in-stalled generating capacity of approximately 65gigawatts (GW) and accounted for 8 percent ofthe Nation’s power generation in 1990. AllFederal power systems are required under exist-ing legislation to give preference in the sale oftheir output to other public power systems and torural electric cooperatives.

Federally owned or chartered power systemsinclude the Federal power marketing administrat-ions, the Tennessee Valley Authority, and facili-ties operated by the U.S. Army Corps of Engi-neers, the Bureau of Reclamation, the Bureau ofIndian Affairs, and the International Water andBoundary Commission. Wholesale power is mar-keted through five Federal power marketingagencies:

1.2.3.4.5.

Bonneville Power Administration,Western Area Power Administration,Southeastern Power Administration,Southwestern Power Administration, andThe Alaska Power Administration.

The Tennessee Valley Authority is an independ-ent government corporation that sells power

within its statutory service area. Jurisdiction overFederal power systems operations and the ratescharged to their customers is established inauthorizing legislation. More on these Federalutility systems can be found in chapter 7 of thisreport.

ELECTRIC POWER REGULATIONThe electric utility sector is one of the most

heavily regulated industries in the U.S. economywith 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 otherbusinesses, the electric power industry is subjectto laws and regulations governing financial trans-actions, employment practices, health and safety,and environmental impacts. But unlike otherbusinesses, as a public utility, it (along withsegments of the natural gas, telecommunications,and transportation industries) is subject to addi-tional economic regulation. Economic regulationof public utilities encompasses organizationaland financial structure, prices (rates), profits,allocations of costs, franchise territories, andterms and conditions of market entry and exit—matters that for unregulated entities are normallydetermined by management discretion and mar-ket forces. Economic regulation of public utilitiesis exercised by Federal, State, and local bodies.Which regulatory body has controlling jurisdic-tion typically depends on the type of utility, thetransaction involved, and State and Federal law.It is not at all unusual for both State and Federalregulators to be involved in review of some utilitydecisions.

9 The Concept of a Public UtilityPublic utilities enjoy a special status under

State and Federal law because their activitiesprovide vital services to businesses and commun-ities (sometimes phrased as “affected with thepublic interest”). This status confers specificrights and obligations and distinguishes themfrom most other business enterprises. Generally,a public utility has an obligation to:

■ serve all customers in its service area (withinits available capacity limitations);

■ render safe and adequate service, includingmeeting foreseeable increases in demand;

I 35

serve all customers within each service classon equal terms (i.e., with no unjust or unduediscrimination among customers); and

charge only a‘ ‘just and reasonable price forits services.l6

In return for assuming these obligations, thepublic utility enjoys certain “rights.” First, theutility has a right to reasonable compensation forits services, including a profit on capital invest-ment to serve the public. Second, through itsfranchise and certificate of public convenienceand necessity, the utility generally is protectedfrom competition from other enterprises offeringthe same service in the same service territory.Third, the public utility has a right to conduct itsoperations and render service subject to reasona-ble rates and regulations. Finally, in many Statespublic utilities can exercise the right of eminentdomain to condemn and take private property forpublic use where necessary to provide adequateservice, subject to the requirement of just com-pensation to the owner. 17

Both State and Federal laws define any entitythat sells electricity as a public utility,18 thusbringing generators and retail distributors ofelectricity under regulation, unless provided withan explicit exception. Jurisdiction over the activi-ties of electric utilities is split between the FederalGovernment and State agencies (including localgovernments). This division reflects both thehistorical growth of electric utility regulation inthis country, which began at the State and locallevel, and the Federal Government’s constitu-tional authority over interstate commerce. Manyutilities are now directly or indirectly subject toboth 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 operatesfacilities used for the generation transmission or distribution of electric energy for sale, ” 15 U.S.C. 79b(a)(3).

-. --- - . . -. — . . - -


H State RegulationState regulation of electric power is diverse,

but four broad generalizations can be made aboutthe form and extent of government oversightexercised .19

1.

2.

3.

4.

State regulatory jurisdiction over utilityrates and operations is typically vested inindependent multimember boards or com-missions whose members are either ap-pointed or elected.

State (or local government) regulators con-trol market entry by granting certificates ofpublic convenience and necessity to electricutilities--creating what are usually monop-oly franchise territories.

All States regulate retail prices of electric-ity. In setting retail rates, State regulatorsmust approve a level that covers the utility’scost of providing service and a reasonablerate of return to the utility and its sharehold-ers. Under various formulations, manyStates require that utility investments bedetermined to be prudent and “used anduseful” before they can be recoveredthrough retail rates. Some States allowrecovery for plants under construction, whileothers defer recovery until the plant isactually in operation.

State regulators also exercise control overutility securities (e.g., stock issuance, stockclassifications) and financing arrangements(bonds, loans, and other debt transactions).This oversight was instituted because of thehistorical abuses by public utility holdingcompanies and was intended generally toprevent use of utility assets for nonutility

ventures and to protect the financial integ-rity of the utility.

The extent of State commission jurisdictionover utilities varies. Some States regulate allutilities, including public power systems andcooperatives, while others limit jurisdiction toinvestor-owned systems and leave regulation ofmunicipal systems to local governments.

Many States also regulate other aspects ofutility operations in some detail, including theplanning and determination of resource needssuch as new generation, bulk power purchases,and construction of transmission and distributionfacilities.20 A number of States regulate the sitingof utility facilities either through the public utilitycommission or a separate siting agency .21

In some States public utility regulators have amore general mandate to protect and/or promotethe public interest and welfare. This mandate hasbeen interpreted as supporting other policy goalsfor utility regulation, such as economic develop-ment, universal electric service, minimum levelsof service at equitable or affordable rates, andenvironmental protection.

RETAlL RATE REGULATIONRegulators establish the rates charged to cus-

tomers, as well as their view of appropriate profitlevels for utilities, through administrative pro-ceedings. Under the most common ratemakingapproach-variously referred to as rate-of-returnregulation or cost-of-service regulation or tradi-tional rate regulation-the utility commissionsets retail rates based on estimates of the expectedcosts of service to meet projected customerdemand (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 NWRegzdutoryOrder? 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 ofOhio, Transmission Line Cemj7cation and Siting Procedures and Energy Planning Processes: Summary of State Government Responses toa Survey by the National Governors’ Association Task Force on Efecm”city Transnu”ssion, contractor report prepared for the Office ofTechnology 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.


Box 3-A-The Revenue Requirement

A utility’s revenue requirement is the total number of dollars required to cover its operating expenses and toprovide a fair profit. This rate setting method is sometimes called the fair return on fair value rule. The revenuerequirement 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 takinginto 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 LawReview, vol. 14, 1986, pp. 43-44 (1986).

Retail rates are typically set based on theutility’s revenue requirement, i.e., the estimated

revenues required to cover operating expenses.These expenses include: administrative, finan-cing, and marketing costs; personnel, fuel, mainten-ance, purchased power, and other operatingcosts; plus recovery of capital investment in therate base (plant and equipment committed topublic service less depreciation). A percentageprofit (rate of return) on all investments in-cluded in the rate base is also included in therevenue requirement for investor-owned utilities.(See box 3-A.) What capital investments areincluded in the rate base and what expenses areallowed are left to the broad discretion ofregulators, as is judgment of what is a fair and

reasonable rate of return. The utility too has someleeway in allocating expenses and capital costs inits submissions for ratemaking. State policies andregulations differ in formulations of mattersincluded or recoverable through rates, includingtreatment of construction work in progress (in-vestment in facilities that are not yet in operation).There are also variations in classes of customers,and related issues such as the availability of basicor lifeline rates for low-income customers.

After establishing the revenue requirement,State regulators must then determine how thosefunds will be collected from customers-referredto as the rate structure or the rate schedule. Therevenue requirement is divided by estimates ofexpected sales to yield the rate per kilowatt-hour


that is used to calculate the customer’s bill.Typically, different rates are established fordifferent classes of customers. The rate design foreach class must yield a price (per kilowatt-hour)that will produce sufficient revenue to cover thecosts of serving that class and contribute tomeeting the overall revenue requirement. Ratesare revised periodically to reflect changes inutility investments and performance and generaleconomic conditions.

Because fuel prices can vary considerably inresponse to market conditions, most States havea separate fuel adjustment clause, a mechanismintended to insulate utilities from fuel priceswings. The automatic fuel adjustment clauseallows utilities to raise or lower fuel charges oncustomer bills to follow fuel costs as they areincurred instead of waiting for a rate case.

There is no single approved constitutionalmethod of ratemaking. The U.S. Supreme Courthas held that the Constitution gives States broaddiscretion to decide which rate-setting mecha-nism best meets their needs in balancing theinterests of the utility and the public.22 The ratebase method for determining just and reasonablerates for public utilities as long as they are notconfiscatory was upheld by the Supreme Court inHope Natural Gas Company v. Federal PowerCommission .23

With utility profits under traditional ratemak-ing based on the total value of capital invested andthe amount of power sold, many analysts haveconcluded there is a tremendous financial incen-tive for utilities to invest heavily in capital-intensive plant and equipment and to sell as muchpower as they can at prices above their cost of

Service. 24 This incentive is counterbalanced by

the threat of penalties and disallowances by theirregulators. For example, regulators have devel-oped certain general principles limiting invest-ments included in the rate base:

Negligent or wasteful losses that are the faultof the utility management cannot be includedas operating charges.Investments must be prudent--i.e., reasona-ble under ordinary circumstances and at thetime made. Recovery of costs from uncon-trolled cost overruns, construction misman-agement, or plant abandonment can be disal-lowed as imprudent.

Some States further specify that the plant mustactually be in service to the public to qualify forinclusion in the rate base.*

A utility’s profits from electricity sales aresupposed to reflect regulators decisions aboutappropriate returns on prudent capital invest-ments in rate base. While regulatory authoritiescannot force a utility to operate at a loss, recoveryof a utility’s authorized rate of return is notguaranteed. At times, the utility may not actuallyearn its authorized rate of return because ofadverse economic conditions, poor business judg-ment, or because regulators overestimated actualsales. If a utility sells fewer kilowatt-hours thanprojected in the rate case, its actual revenues willbe lower than assumed and, accordingly, itsprofits will be less than authorized. If, however,the utility sells more kilowatt-hours than pro-jected, its revenues and profits will be higher,assuming that the marginal cost of generating theadditional kilowatt-hours is less than the salesprice. 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 requirementin the case of canceled plants violated constitutional protections for due process and just compensation. The ruling affirmed the State utilitycommission decision precluding recovering initial costs of a canceled, unfinished nuclear plant even though the costs were prudently incurredby the utility at the time.


fuel adjustment clauses operate to reduce risks toutility profits from fuel price changes. Thisbuilt-in incentive toward additional sales is whatgives rise to the claim that traditional utilityratemaking is biased against utility investment inconservation and energy efficiency.

If the costs of serving additional consumptionexceeded the established rates per kilowatt-hour,the financial incentives would change and utili-ties would profit by restraining demand, How-ever, the immediate cost of procuring or generat-ing additional kilowatt-hours usually falls wellbelow the rates at which utilities are permitted tosell them, thus providing a powerful incentive forutilities always to increase power sales and toresist efforts to lower sales.

Under conventional rate-of-return regulation,short-term profit considerations favor increasedsales of kilowatt-hours, especially in situations ofsurplus capacity that is cheap to operate. Recogni-tion of this tendency has lead State regulators,spurred in large part by consumer and environ-mental activists, to adopt various measures toinsulate or ‘‘decouple’ shareholder returns fromthe volume of kilowatt-hours sold.26 One suchdevice is the Electricity Revenue AdjustmentMechanism (ERAM) used in California and invariations in other States, in which customer ratesare automatically adjusted upward or downwardso that the utility meets, but does not exceed, itsrevenue requirement set in prior rate proceedings.These approaches are discussed in chapter 6 ofthis report.

Ratemaking is not an exact science, although,as practiced today, it relies heavily on economics,statistics, computer modeling, and expert testi-mony. Much of the regulators’ work is political innature. Fundamentally regulators seek tradeoffsamong often competing policy goals of economicefficiency, adequate and reliable service, environ-mental quality, and equity.

Assuring Quality of ServiceMost State commissions are expressly em-

powered to assure that utilities provide adequateand reliable service for their retail customers. Theobligation generally means that a utility mustprovide safe, continuous, comfortable, and effi-cient electric service within its service area.However, the utility is not required to supplypower under any and all conditions, such asduring severe storms or power outages beyondtheir control. To provide reliable service, utilitiesare required to plan to meet reasonably foresee-able contingencies and load growth.

Regulators have several mechanisms for en-forcing this obligation. They can punish chroni-cally poor, unreliable, and inefficient service bydenying or reducing rate increases. The commis-sion can order the utility to take specific remedialactions to improve service, such as acquiringadditional generation or transmission facilities, orexecuting power purchase contracts. Finally,under certain circumstances varying by jurisdic-tion, utilities can be held financially liable forinjuries or damages to their customers caused byinadequacy, interruption, or failure of electricservices.

Energy Efficiency, Resource Planning,and Demand-Side Management

With their plenary authority over retail ratesand the construction of electric power facilities,State regulators can exercise considerable influ-ence over utility resource planning and opera-tions. In response to the sizable rate increases anddisputes over new powerplant construction thatarose in the late 1970s, many utility commissionsadopted policies encouraging or requiring utili-ties to engage in demand-side management (DSM)programs and integrated resource planning (IRP).Several commissions have also adopted incen-tives or requirements for improvements in theenergy efficiency of utilities’ supply-side opera-

26 Mph c. cavwg~ “ReSpO~lble power hl~et~g in an Increasingly Competitive Er%” ycde Journuf on Regulutioff, VO1. 5, ~er1988, pp. 331-366.


tions. These requirements are generally intendedto lower electricity costs for consumers byencouraging the use of cost-effective energyefficiency measures as an alternative to higher-cost conventional generation. Some policies alsohave been adopted to support environmentalprotection, and promote diversity of energy sources.Chapter 6 of this report provides an overview ofthese State efforts.

The legal basis for requiring utility IRP andDSM varies by State. Some requirements arebacked by legislation, others are the result ofbroad rulemakings by State regulatory commis-sions, and still others have arisen out of rate casesinvolving specific utilities. By the 1990s Stateregulatory requirements for utility planning activ-ities were firmly established in more than 30States and under development in many others. Atthe same time, a broad range of financial incen-tives intended to encourage utility investment inDSM programs had also been adopted by States.These changes are altering the relationship be-tween utilities and their regulators and shiftingthe financial incentives in utility ratemaking.

8 Federal Regulation

JURISDICTIONThe Federal Power Act gave the Federal Power

Commission authority over the rates and condi-tions for interstate sale and transmission ofelectric power at wholesale.27 Federal regulationof interstate and wholesale sales was initially seenas a supplement to State authority to fill a gapwhere existing State regulation had proven inef-

fective or unconstitutional. The creation of aFederal role in the regulation of interstate activi-ties in electric power was prompted by the 1927Supreme Court ruling in Rhode Island PublicUtilities Commission v. Attleboro Steam andElectric Co. that State regulatory agencies wereconstitutionally prohibited from setting the pricesof electricity sold across State lines because doingso would violate the Commerce Clause.** Thisdecision created a gap in effective regulation ofelectric utilities that the Federal Power Act wasintended to close.

Originally, it was perceived that there was abright line between Federal and State jurisdiction—Federal regulators would have jurisdiction overwholesale transactions involving more than oneState and State commissions would overseeutility operations, instate wholesale transactions,and retail rates. But, as interconnections amongutilities grew and long-distance transmissionincreased, virtually all electric power movingover transmission lines was viewed as being ininterstate commerce and, hence, subject to exclu-sive Federal jurisdiction. These ever-more expan-sive interpretations of Federal jurisdiction havenow brought wholesale transactions betweenutilities in a single State, as well as most instatewheeling arrangements, under Federal law. Theserulings and the fact that most utilities are inter-connected with utilities in other States havearguably limited most State jurisdiction overprices and terms of wholesale sales and wheelingtransactions, even when they involve instateparties--except in Alaska, Hawaii, and parts ofTexas.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 thatthe Commerce Clause of the Constitution gave the Federal Gov ernment exclusive jurisdiction to regulate matters in interstate commerce andforeclosed 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~krnCaf~ornia Edison Co, See also Flori& Power & h“ght Co., 29 FERC 61,140 (1984), in which FERC asserted exclusive Federal jurisdictionover virtually all transmi ssion service in Florida. Because the power systems in the ERCOT region of ‘lkxas, and in Alaska and Hawaii, arenot synchronously comected to power systems in other States, it has been widely assumed that FERC does not have jurisdiction over mostpower transactions in these States.

—


With the establishment of the U.S. Departmentof Energy (DOE), the responsibilities of theFederal Power Commission for regulating elec-tric utilities, natural gas pipelines, and oil pipe-lines were transferred to a new agency, theFederal Energy Regulatory Commission.30 Itsfive members are appointed by the President andconfirmed by the Senate to staggered, fixed terms;no more than three commissioners may comefrom the same political party. Although withinDOE, FERC retains its independent status. TheSecretary may submit his or her views on energypolicy to the commission, but the Secretarycannot direct the commissioners to reach aparticular result.31

The Federal Power Act, as amended, givesFERC jurisdiction over the prices, terms, andconditions of wholesale power sales involvingprivately owned power companies and of trans-mission of electricity at wholesale.32 It alsooversees sales and mergers of public utilities,33

the issuance of securities and indebtedness ofelectric utilities,34 and power pools and utilityinterconnections.35 In addition, FERC approvesthe rates for public power sold and transported bythe five Federal power marketing administra-tions, and oversees and licenses nonfederal hy-droelectric projects on navigable waters.36

The Public Utility Regulatory Policies Act of1978 (PURPA) gave FERC expanded responsi-bilities for encouraging cogeneration and certainalternative power technologies.37 PURPA re-

quired utilities to interconnect with and buypower from cogenerators and small power pro-ducers that met standards established by FERC atnot more than the utility’s avoided cost ofpower. 38 PURPA marked the frost major Federalmove to open up electricity markets to nonutili-ties. At the same time, PURPA exempted thesequalifying facilities (QFs) from most of regula-tory burdens applicable to public utilities underFederal and State law in order to reduce theinstitutional barriers to QF development.

PURPA also imposed new requirements di-rectly on State regulatory commissions relating tothe consideration of regulatory policy initiativesand consumer protection and representation be-fore State commissions. PURPA required Statecommissions to give formal consideration toadopting certain new Federal standards as part ofState utility law and policy, but PURPA alsoexpressly provided that States could, after suchconsideration, decline to implement the standard.Many of the proposed standards were alreadybeing used by State regulators to ensure that ratesmore accurately reflect the costs of providingservice and to encourage energy conservation.The Federal standards included certain ratemak-ing methods: seasonal, time of use, and interrupti-ble rate differentials; limiting declining block rate(e.g., large volume) discounts unless they in-volved lower service costs; and requiring utilitiesto offer load management technologies to theircustomers. 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 interstatenatural 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: InnovativeGovernment 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’ Orpurchase from another source. Public Law 95-615, WC, 210,92 Stat. 3144, 16 U.S.C. 824a-3.

.


for consumer information, lifeline rates, andprocedures for terminating electricity service. Notsurprisingly, PURPA was challenged in theCourts. However, the Supreme Court ruled thatthis Federal intrusion into matters previously leftto the States was found to be within the broadembrace of the Commerce Clause.39

FERC shares responsibility for enforcing thePublic Utility Holding Company Act of 1935(PUHCA) with the Securities and ExchangeCommission (SEC).40 PUHCA vests broad au-thority over the structure, finances, and opera-tions of public utility holding companies in theSEC. PUHCA was enacted in response to wide-spread concern over the influence of a handful oflarge interstate utility holding companies that by1932 controlled over 75 percent of the privateelectric utilities.41 PUHCA was intended to limitseverely the use of the holding company structureand to force the regional consolidation of theexisting large multistate holding companies.

WHOLESALE RATEMAKING42

The Federal Power Act requires that ratescharged for wholesale power sales and for trans-mission be “just and reasonable” and “notunduly discrimin atory or preferential. ’43 Utilitiesunder FERC jurisdiction must file detailed, writ-ten tariffs and schedules of all rates and charges,which are available for public inspection. FERC

has established detailed regulations and guide-lines on rate requests, allowable costs, andmatters considered in rate of return determina-tions. FERC also requires that electric utilitiesfollow a uniform system of accounting.

Proposed new rate schedules must be filed withFERC 60 to 120 days before they are to go intoeffect. Utilities must submit detailed schedules ofinformation, including actual and projected costof service data to support the increases. When aproposed new rate is filed, FERC has severalchoices: it can reject the filing, approve the rateschedule immediately, or order a hearing andsuspend the new rate for 5 months. If FERCschedules a hearing, the burden of proof is on theutility seeking the rate increase. The Commissionmust also consider evidence submitted by cus-tomers or other interested parties. Parties toproceedings can seek review in Federal Courts ofAppeals, where the standard is whether theagency decision is supported by substantial evi-dence.

FERC decisions are made on a case-by-casebasis. However, over the years a substantial bodyof administrative precedent has accumulated thatguides the commission and applicants. FERC isnot wholly bound by precedent, however. Withinits broad and general authority under the FederalPower Act, the commission can establish newpolicies 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 moreon 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 ~~bwby decades of judicial review of administrative actions governing public utilities. Farmers Union Central Exchange, Inc. et al. v. FederalEnergy Regulatory Comnu”ssion, 734 F2d 1486, at p. 1502 (D.C. Circuit 1984). In that case, the court reviewed basic principles of rateregulation observing that Courts will uphold agency mte orders that fall within a ‘‘zone of reasonableness’ where rates are neither “less thancompensatory” nor “excessive.” The zone of reasonableness requires striking a fair balance between the financial interests of the regulatedcompany and ‘‘the relevant public interests. ’ In determi.ning the reasonableness of rates to a producer, the concern is whether the rate is highenough to cover the cost of debt and expenses and provide a return commensura te with investments in other enterprises with comparable risksin order to maintain credit and attract capital. In deciding the justness and reasonableness to the consumer, the concern is whether the rate islow enough to prevent exploitation by the regulated business.


individual case decisions or in new rulemakings.When FERC departs from past policies, however,it must provide ample justification and documen-tation of its decision in the face of possible courtchallenges.

In approving wholesale rates, FERC histori-cally has followed a cost of service approach thatis, in principle, similar to that used by Stateregulators. As with State rate regulation, Federaleconomic regulation is based, in part, on lack ofeffective competition in bulk power markets.However, during the Reagan and Bush Adminis-trations, FERC chairmen and staff embraced themarket deregulation rhetoric of the times andembarked on several initiatives with the goal ofallowing utilities and independent power produc-ers to charge ‘‘market-based rates’ for theirwholesale services rather than cost-of-servicerates established by regulators.44 Under market-based pricing, wholesale power rates are notbased on a detailed evaluation of costs of serviceplus an appropriate rate of return set by regulators,but rather on a price set through competitivebidding or arms-length negotiations betweenpower sellers and purchasing utilities wheremarket power is absent or mitigated. Someproponents expressed a preference for wholesalerates set by competitive market signals instead ofregulators’ projections, estimates, and judgmentsin the belief that such an approach would produce

a more economically optimal result for society .45Others also argued pragmatically that market-based rates with prospects of higher profits thanthose available to regulated utilities were neededto attract new entrants, so-called independentpower producers, to build new powerplants be-cause the pace of utility construction had slowedand some feared an impending capacity short-fall.% Still others supported the availability ofmarket-based prices and the expanded participa-tion of independent power producers in genera-tion markets to provide utilities with a greatervariety of options in resource planning andacquisition.

While FERC generally retains cost-of-servicerate policies for bulk power sales, in a growingnumber of cases, the commission has acceptedmarket-based prices. By May 1993 FERC hadreceived more than 40 applications for marketprices for wholesale power contracts and hadapproved 29 of these requests and rejected 9.47 Inapproving these transactions, FERC imposedvarious conditions intended to establish that theapplicant’s market power has been mitigated. Thepreconditions for receiving market-based rateshave been evolving on a case-by-case basis andFERC has not adopted any generic policy. Inthese and other cases, FERC has used its condi-tioning power to require applicants to expandaccess to transmission services to provide wider

44 ~ 1987, ~Rc ~oficited pubfic ~ments on ~= notices of propo~ ~cxs @opRs): 1) competitive bidding for new powerrequirements, 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 rulesor 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 Energylkchnology Conference and Exposition, March 1985; U.S. Department of Energy, Deputy Assistant Secretmy for Energy Emergencies, StaffRepo~ “Electric Power Supply and Demand for the Contiguous United States, 1987-19%,” DOElfLOOll (Sprin~leld, VA: NationalTechnical Information Service, Febrniuy 1988); “Summary of Current Staff Proposal on PURPA-Related Issues, ” Federal Energy RegulatoryCommission Sept. 11, 1987. Other industry experts discount the shortfall theoxy, interpreting the slowdown as the natural result of aggmsiveoverbuilding of large capacity baseload plants and slower economic gTowth. They also note that new capacity needs for many utilities are forsmaller 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.


opportunities for other buyers and sellers in bulkpower markets.

TRANSMISSION ACCESSAccess to transmission services allows utilities

opportunities to purchase and sell power in awider area beyond their local host utilities andadjacent utilities. Within segments of the electricutility industry and regulators, there has beenlongstanding concern that some transmission“haves” might use their control over regionaltransmission systems to keep their wholesaleutility customers captive and to deny competingwholesale power providers access to bulk powermarkets. Utilities that have been denied wheelingservices have had only limited options.%

The extent of FERC’S authority to order oneelectric utility to transmit or “wheel” over itslines power produced by another generator hasbeen a matter of contention for years. FERC’Sauthority under the original Federal Power Act toorder wheeling was not explicit. PURPA, for thefirst time, provided explicit wheeling authoritybut placed such severe limitations on its exercisethat made it all but impossible to obtain wheelingorders. 49 In recent years FERC has relied on itsauthority under other provisions of law to ad-vance its policy goals of expanding access totransmission services to promote the growth of

competitive bulk power markets. For example,FERC conditioned the approval of several largeutility mergers on agreement that the mergedutility system offer transmission services to otherutilities. 50 FERC also has encouraged severalutilities seeking acceptance of market-based ratesfor wholesale power transactions to file open-access transmission tariffs as a means of mitigat-ing market power.

The Energy Policy Act of 1992 clarified andstrengthened FERC’S wheeling authority .51 Nowutilities, independent power producers, and otherscan apply to FERC for mandatory wheelingorders to carry out wholesale power transactions.This change provides new impetus for the growthof competitive power markets and expands theoptions available to utilities in resource planningand 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 canissue wheeling orders settled, new controversiesare likely to arise as FERC struggles to establishfair and workable policies on transmission pricingand capacity determinations.

ASSURING QUALITY OF SERVICEUnlike 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~ ~tdid 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 PowerTransjers, September 1987, pp. 52-68, although the author notes that FERC may have some as-yet-untested authority to order wheeling as aremedy for anticompetitive behavior under sees. 205 and 206 of the Federal Power A@ id. at note 45, p. 64. See also FZorti Power & h“ghtCo. 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 existingwheeling authority FERC might have outside of sees. 211 and 212 and notes that PURPA is not intended to affect existing authority, HouseConference Report 95-1750, to accompany H.R. 4018, 95th Cong., 2d sess., Oct. 10, 1978, pp. 91-95, U.S. Code Congressional andAdministrative 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~& LightCo., subject to the condition that the merged companies provide firm wholesale transnu“ssion services at cost-based rates to any utility thatrequested such service. The condition was necessary to prevent the future exercise of market power by the new company to foreclose accessby competitors to bulk power markets. The decision was reached under sec. 203 of the Federal Power Act which requires commission approvalof mergers and acquisitions. A more expansive ‘open access” provision was included in the FERC approval of Northeast Utilities acquisitionof 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.


Power Act to remedy inadequate service.52 If aState commission fries a complaint, and if FERCfinds that interstate service of a public utility isinadequate or insufficient, the commission canorder the utility to provide the proper level ofservice provided that the utility has sufficientcapacity available .53 The commission has noauthority to compel a utility to enlarge itsgenerating facilities or to sell or exchange elec-tricity when doing so would impair its ability torender adequate service to its customers.

There is no Federal rate penalty for failure toprovide adequate and reliable service underFederal law, nor is there a basis to provide morefavorable treatment to utilities providing superiorperformance. Rate treatment provides no incen-tive or disincentive for performance or to remedyinadequate service.

Nevertheless, there is a chain of decisionscreating a Federal obligation to provide wholesaleservice. FERC can require a jurisdictional utilityto provide wholesale service to another utilitywhere the ability of the purchasing utility to meetits customer needs is threatened and the sellingjurisdictional utility can provide the servicewithout imposing an undue burden on service toits own customers. This has come into play whenlong-term power purchase contracts have expired,and the parties have not entered into new arrange-ments, and protects the purchasing utility frombeing left without power supplies. If, however,generating capacity is not available, FERC cannotenforce wholesale contracts or the obligation toseine.

Adequacy and reliability have been dealt withas planning tools for electric utilities and not asmatters of regulatory concern. PURPA amendedthe Federal Power Act to include provisionsdealing with interconnections and emergencypower sharing arrangements. Utilities are re-quired to report anticipated power shortages toFERC and contingency plans to State regulators.

FERC is authorized to work with State commiss-ions and local reliability councils to promotereliability in utility planning and coordinationactivities. Beyond this, there are no explicitresponsibilities.

ENERGY EFFICIENCY, RESOURCE PLANNING,AND DEMAND-SIDE MANAGEMENT

Compared to the scope and extent of Stateregulation of utility activities, FERC leaveslargely untouched many areas related to energyefficiency and resource planning. This has beenprimarily a matter of policy, but also reflectsuncertainty over the extent of FERC power andinfluence over generating resources and retailoperations under the Federal Power Act.

FERC regulations and rate procedures arefocused on the costs of service of the entity sellingelectric power and not on the purchasing utility.Its concepts of just and reasonable rates, and theobligation to provide electricity at the lowestpossible rates consistent with adequate service,have not been expanded into requiring that eitherthe selling or buying utility demonstrate that theresource selected is the lowest cost alternative formeeting customer needs, considering both supplyand demand-side alternatives.

PUBLIC UTILITY HOLDING COMPANIESUnder PUHCA any company that owns or

controls more than 10 percent of the votingsecurities of a public utility is considered to be apublic utility holding company. An electric utilitycompany is any company that owns or operatesfacilities used for the generation, transmission, ordistribution of electric energy for sale. Theholding companies are subject to extensive regu-lation of their financial activities and operations.Public utility holding companies that operatewholly within one State or in contiguous States

52 con~essio~ Research Service, supra note 18, p. 157.5316 uSC s~tion 824 f.


can qualify for an exemption from the moststringent regulatory oversight of PUHCA. Ex-emptions also apply to companies primarilyengaged in nonutility business and not deriving amaterial part of their income from the publicutility business.54 Nonexempt entities are regis-tered holding companies and are limited in theiroperations to “a single integrated public-utilitysystem, and to such other businesses as arereasonably incidental, or economically necessaryor appropriate [there]to. ’ Integration means thatthe utility operations are limited to a single areaor region of the country. Registered holdingcompanies must obtain SEC approval of the saleand issuance of securities; transactions amongtheir affiliates and subsidiaries; and services,sales, and construction contracts. In addition, thecompanies must fide extensive financial reportswith the SEC. In contrast, exempt companiesneed only file limited annual reports with theSEC.

With the growth of wholesale power markets inthe late 1980s, PUHCA requirements were criti-cized as unfairly restricting entry into the compet-itive power industry and requiring unnecessarilycomplex corporate structures for independentpower projects. These so-called “PUHCA pret-zels’ ‘ were created to avoid the geographicrestrictions on holding company operations and/or the loss of the PUHCA exemption for qualify-ing facilities under PURPA. Even so, the inde-pendent power sector grew substantially over theperiod and among its major players are theindependent power affiliates of regulated electricutilities.

The Energy Policy Act of 1992 amendedPUHCA to create a new category, the exemptwholesale generator (EWG), for certain entitieseither building or operating generating facilitiesthat sell electricity at wholesale to electric utili-ties. 55 The act also loosened restrictions oninvolvement of domestic registered holding com-panies’ affiliates in power markets outside theUnited States.

Regulation of resource planning and affiliatetransactions by registered holding companies hasbeen a recurring source of tension between Stateand Federal regulators.

B State and Federal ConflictsWhile States have exclusive retail rate jurisdic-

tion, under the Narragansett doctrine they mustgenerally pass through wholesale rates previouslyapproved by FERC.56 The extent to which priorFERC determinations of the reasonableness ofwholesale rates preempts State consideration ofthe retail impacts of those same rates is a matterof some controversy.

57 The strain arises because

State regulatory programs and the considerationsused in setting rates are generally far moreextensive than FERC’S. In some cases, requiringStates to adopt without question FERC’S whole-sale rate determinations in setting retail rateswould preclude States from exercising their ownregulatory authority over issues normally withintheir jurisdiction, such as resource planning andacquisition and facility siting.

The major limitation on Federal preemption isfound in the Pike County exception, whichaffirmed the right of a State commission toexamine the prudence of a wholesale powerpurchase contract and to disallow the pass-

S4 15 U.scc. 79f.

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

56 ~s tie 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), oneof 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 NaturalResources & Environment 7, Spring 1987; and Bill Clinto% Robert E, Johnsto~ Walter W. Nixon, III, and Sam Brattou “FERC, StateRegulators 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 iflower cost power supplies were available else-where.58 The issue of whether States can review

the prudence of wholesale power contracts willbecome especially critical if, as a result of Stateleast-cost planning initiatives and competitiveprocurement practices, utilities rely more heavilyon bulk power purchases for new power supplies.Wholesale prices for power sales from utilitiesand independent generators, except for QF trans-actions, fall exclusively within FERC’S jurisdic-tion, as do the terms and conditions for transmis-sion services. This creates a situation whereStates shape the initial consideration and choiceof resources for their jurisdictional utilitiesthrough the planning process but have diminishedcontrol over wholesale power costs. The splitjurisdiction increases the potential for utilities toescape State jurisdiction at the same time that thegrowth of competitive power’ entities, includingunregulated utility independent power affiliates,raises State regulator concerns over their ability toeffectively control self-dealing, unfair competi-tion, and other unfair practices.

The vitality of the Pike County exception hasbeen cast into doubt by the Supreme Court’s 1988decision in Mississippi Power & Light Co. v.Mississippi ex rel. Moore. In this decision, theCourt rejected State efforts to deny a rate increasebased on FERC’S allocation of the costs of anuclear unit built to meet the needs of anintegrated interstate holding company system, onthe grounds that the local subsidiary’s participa-tion in the project was imprudent.59 The Courtheld that a State prudence inquiry was preemptedeven though FERC had not examined the issueduring wholesale rate proceedings. The State

regulators’ only recourse is to challenge theprudence of the wholesale arrangements beforeFERC. Whether the Mississippi Power & Lightdecision is limited to the particular situation ofinterstate holding companies, or whether it marksfurther limitations on the powers of State regula-tors, is not yet known. Resolution of this contro-versy over conflicting Federal and State jurisdic-tional claims will be one of the major publicpolicy issues in any transition to a more competi-tive electric power industry.

Note that the House and Senate versions of theEnergy Policy Act of 1992 originally adopteddifferent approaches to the Federal-State jurisdic-tional conflicts over competitive power transac-tions. Conferees failed to reach agreement on analternative resolution, so the potential for conflictremains.

In an increasing number of cases, FERC’Sefforts to expand competition in bulk powermarkets in pursuit of economic policies andstreamlining g the bureaucratic process is movingFederal regulation away from detailed considera-tion of costs of service. At the same time, Statesthough IRP, incentive rates, and DSM are movingtoward greater oversight and involvement inutility planning and decisionmaking to promoteleast-cost energy plans. A number of Stateregulators see the potential for a clash betweenState least-cost plans and FERC (and SEC)preemptive regulation of wholesale transactions,particularly in the area of multistate utilityholding companies. This has led to proposals forlegislation to give States greater responsibility inresource planning areas, authorizing interstateplans 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. SupremeCourt 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.)

. . . . .


rulings to be consistent with State plans or at leastinvolve consultations with State regulators.60

Other observers argue that such legislation isnot needed because in their view the potential forconflicts is minimal and existing law could allow

cooperation and consultation among FERC andaffected State regulators and holding companiesbefore IRP approval.

61 Some also see the poten-

tial for regional integrated resource planningdecisions to result in some unspecfied adverseimpacts on bulk power markets and access totransmission services.62

OVERVIEW OF ELECTRIC UTILITYSYSTEMS AND OPERATIONS

Electric utilities provide much more than the

commodity of kilowatt-hours of electricity. Their

special obligations as public utilities require themto assure reliable, adequate, safe, and economicelectric service on demand to customers in theirfranchise area. Utility customers value electricityfor the energy services that it provides (e.g.,lighting, heating, cooling, machine drive). Theevolving perception of the role of utilities asproviders of reliable and economic energy serv-ices to customers rather than purveyors of kilowatt-hours is evidenced in shifts both in internal utilityorganization and in regulatory policies. Thesechanges reflect recognition of the potential contri-

bution of utility conservation, load management,and efficiency programs in reducing electricitydemand growth as an effective means of servicingcustomer needs and as an alternative to newpowerplant construction.

As part of their obligation to serve, electricutilities must anticipate and match customerdemand, while assuring system reliability, mini-mizing electricity rates, and maintaining financialhealth. To do this effectively—and for privatelyheld systems at a profit-requires highly complexphysical systems, specialized personnel, a myriadof operations, and extensive planning capabili-ties. Figure 3-5 shows a simplified electric powersystem. The structure and operations of electricutilities in the United States are shaped by thephysical requirements of running reliable inter-connected electric power systems and by thespecial institutional requirements imposed bytheir regulated monopoly status and serviceterritories.

In particular, many features of the design andoperation of electric power systems reflect twofundamental physical principles of electricity:63

1. Electricity must be generated as it isneeded because it flows at nearly thespeed of light with virtually no storage ofpower in the system.

60 see, for ~mp]e, Stitement of Ashley C. Brow Commissioner, Ohio public Utilities Commission iII Htigs on S. 2607, ~~lationAuthorizing 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 courtrulings and FERC policies, ‘‘under current law, holding company systems registered under PUHCA cannot be effectively regulated at any levelof governm ent—State, Federal, or local. ” See also the Statement of Sam I. Brattoni Jr., Chairman, Arkansas Public Service ComrnissiouHearing on S. 2607 Before the Committee on Energy and Natural Resources, U.S. Senate, May 14,1992. Chairman Bmtton testiiled that asa result of the U.S. Supreme Court decision in Mississippi Power & Light v. Srate of Mississippi ex rel. Moore, 487 U.S. 354 (1988), electricutility holding companies could avoid State regulatory review of retail mtes by shifting generation from retail to wholesale subsidiaries. Brattonfurther observed that while commentators continued to debate the extent of the Mississippi Power & Light decision+ “. . . participants in thedebate seemed to agree on one thing: State regulators and registered holding companies cannot plan for additions of resources for their systemand be assured that such plans will ultimately be overturned by FERC.’ He termed the situation “a major regulatory gap’ and ‘‘preemptionwithout planning. ” The State regulators were joined in their support of legislation on cooperative regional integrated resource planning byEntergy 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 andNaturat 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.

—


Figure 3-5 Simplified Model of an Electric Power System

Energy control center InterconnectionD

/‘1hPower planVsubstation

x-

1IInterconnection

+ \ <&**

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

2. Every flow of electricity from a power-plant to a distribution system affects theentire transmission system, not just themost direct path between them.

The first principle means that electric powersystems must be planned and operated to followcustomer demand (load) instantaneously. Follow-ing load requires that if customer demand forelectricity increases, more generating units mustbe dispatched to meet the increase in load, andwhen load decreases, generation must also bebacked down. Customer demands on the systemchange continuously, although they exhibit daily,weekly, and seasonal load cycles. Figure 3-6shows a weekly load profile for a typical utility.Sudden failure of generating units or transmissioncomponents instantly affects frequency and volt-

age across the power system. Following loadrequires that utilities forecast likely patterns ofcustomer demand and possible equipment fail-ures and plan for and maintain adequate generat-ing resources and transmission capacity in reserveand readily available to meet changes in demandand respond to contingencies on short notice.Moreover, power systems must be operated at alltimes to maintain narrow frequency and voltagestandards to protect customer and power systemequipment and to preserve system stability.

The second principle means that power trans-mission affects not only the transmission lines ofthe utility generating the power but also all thetransmission lines of utility systems intercon-nected with it. When one utility transfers power toanother utility, the receiving utility reduces its


12

10

8

6

4

2

0

Figure 3-6-Weekly Load CurveThousand 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 Considerationsin Proposed Increased Wheeling, Transmission Access and Non-Utility Generation,” contractor report prepared for the Office ofTechnology Assessment, March 1988, pp. 2-3.

generation while the selling utility increases itsgeneration, but the power flows over all pathsavailable, not just the transmission lines of thetwo utilities involved. Part of the load may becarried by the transmission lines of other utilitieshundreds of miles away, reducing the amount ofpower that those utilities can place on their ownlines and, perhaps, overburdening a fully loadedline, and thus risking failure. Therefore, tomaintain the integrity of the grid, each utility mustcontrol its operations and coordinate its transac-tions with neighboring systems to ensure that nocomponents are overloaded on any of the possiblepaths available.

In addition to satisfying basic physical condi-tions, utilities must meet certain operationalrequirements. They must design and operate theirsystems to provide electricity with the correctfrequency and proper voltage for customer equip-ment. The service must be reliable-sufficient to

meet changing customer loads with an acceptablelevel of outages or service interruptions. Inpractice, voltage, frequency, and reliability areviewed as fundamental technical performancestandards that must be met in system operationand planning. Plannin g and operating the powersystem in a manner that minimizes costs to thecustomer and maintains the profitability of theutility enterprise are additional objectives forutility decisionmakers and their regulatory over-seers.

Satisfying these technical and operating condi-tions over seconds, hours, days, months, andyears requires a high degree of coordination,planning, and cooperation among utilities, anddetailed data and engineering analyses. Thissection reviews the major components of electricpower systems infrastructure and operation andplanning functions.


Figure 3-7—Electricity Generation(millions of kWh)

by Fuel 1990

c1,

r\

Nuclearr 573, 1

NUGs 4i\ ~ 1 0 8 . 6 5

20%

37

“/07

“o 9%

%’ 273, 862

,~~ $“~”1 G a s 9Y0 Other utility OO\O259, 954 12, 913

SOURCE: Office of Technology Assessment, 1993, based on datafrom the North American Electric Reliability Council.

I Electric Power System ComponentsThe physical infrastructure of an electric power

system consists of:

generating units that produce electricity;transmission lines that transport electricityover long distances;distribution lines that deliver the electricityto customers;substations that connect the pieces to eachother; andenergy control centers to coordinate theoperation of the components from moment tomoment and in the near future.

A wide variety of other planningand engineeringsystems coordinate capacity utilization and ex-pansion plans for the longer term. Figure 3-5shows a simple electric system with two power-plants and three distribution systems connectedby a transmission network of four transmissionlines and is linked with neighboring utilitysystems by two tie lines.

Electric generators convert mechanical en-ergy derived from fossil fuel combustion, nuclearfission, falling water, wind, and other primaryenergy sources to produce electricity. Utilitiesoften have a mix of generating units that run ondifferent energy sources and that are suitable forbase, intermediate, or peaking loads. As shown infigure 3-7, about 56 percent of electricity gener-ated in the United States in 1990 came fromcoal-fired generation and another 21 percent camefrom nuclear units. Installed generating capacityby fuel source is shown in figure 3-8.

Generators typically produce alternating-current (AC) electricity at a frequency of 60cycles per second (60 Hertz or 60 Hz) withvoltages between 12,000 and 30,000 volts. Thefrequency of all generating units on a system mustbe precisely synchronized. Automatic voltageregulators on generating units control the unit’svoltage output, and speed governors monitorfrequency and adjust power output in response tochanging system conditions to maintain balance.

Figure 3-8—Electric Utilities Installed GeneratingCapacity 1990 (summer megawatts)

Nuclear 13°/0r-lo 7Efl Hydro 10%

N

Coal293,

/ c, 1 UCJ

\

2Pumped storag

! 15, 961>,~ \ ~ Oil 8%

/ / ’ \ 57, 964

7/“’” 140130

Dual fuel 190/0

Other utility 0°/02, 311

SOURCE: Office of Technology Assessment, 1993, based on datafrom the North American Electric Reliability Council.

e 2%


A powerplant consists of one or more generat-ing units on a site together with a generationsubstation that connects the generators to trans-mission lines. Power transformers at the substa-tions raise the voltage to higher levels for efficienttransmission. Substations also hold monitoringand communications equipment and control andprotective devices for transmission and genera-tion facilities.

Transmission lines carry electric energy fromthe powerplants to the distribution systems. Tominimize losses over long distances, transmissionlines operate at high voltages, typically between69 and 765 kilovolts (kV). Most transmission inthe United States consists of overhead AC lines,but direct current (DC) transmission lines andunderground cables are used for special applica-tions. Power transformers raise the generatorvoltage to the transmission voltage and backdown to the distribution network level (typicallyunder 35 kV) at the other end.

Transmission systems consist of interconnectedtransmission lines (the conductors (e.g., wires)and their supporting towers) plus monitoring,control, and protective equipment and deviceshoused in transmission substations and used toregulate voltage and power flow on the lines.

Most customers receive their electricity from adistribution system.64 Distribution systems op-erate at lower voltages than the transmissionsystem, typically under 35 kV, to transportsmaller amounts of electricity relatively shortdistances. Power transformers reduce the high-voltage electricity from the transmission systemto the lower distribution system level. The powertransformers are housed together with control andprotection devices in distribution substations.

The distribution system is divided into theprimary distribution system, operating at between2.4 and 35 kV, which moves power short dis-tances and serves some moderately large indus-

trial and commercial customers, and the second-ary distribution system at 110 to 600 volts, whichtypically serves groups of customers in neighbor-hoods. The primary distribution system deliverspower to distribution transformers, which reducevoltage to the secondary system voltage levels.

Protective apparatus in the distribution systemincludes circuit breakers in distribution substa-tions that open automatically when a protectiverelay detects a fault (or short circuit) and fuses onthe secondary systems that open when overloadsoccur. Many of the circuit breakers and switchesin distribution circuits are manually operateddevices, so restoring service after outages isusually done manually by dispatching a workcrew to the site.

Utilities may have a dozen or more generatingunits and transmission lines, and hundreds ofdistribution systems serving hundreds of thou-sands of customers, each with a variety ofenergy-using devices. The energy control centercoordinates the operation and dispatch of allpower system components within a defined geo-graphic region called a control area. One or moreutilities may make up a control area. The controlarea in figure 3-5 is interconnected to twoneighboring control areas through transmissionlines. There are approximately 160 individualcontrol areas in the United States.

Energy control centers use a variety of equip-ment and procedures: monitoring and communi-cation equipment (telemetry) to keep constantwatch on generator output and system conditions;computer-based analytical and data process-ing tools which, together with engineering exper-tise, specify how to operate generators andtransmission lines; and governors, switches, andother devices that actually control generators andtransmission lines. The control center equipmentand procedures are typically organized into threesomewhat overlapping systems:

~ Some vev kge elwtic consumers, such as major industrial plauts, take their power directly from the m~mission system ~ic~lY atsubtrausmission voltage levels between 23 and 138 kV. A substation containing metering, protective, and switching apparatus comects theselarge customers to a transmission line.


Utilities monitor and direct power system operations

within a control area from the energy control centershow here.

1.

2.

3.

automatic generation control (AGC) sys-tems, which coordinate the power output ofgenerators to balance supply with customerdemand;

supervisory control and data acquisition(SCADA) systems, which coordinate thetransmission line equipment and generatorvoltages; and

analytical systems, which monitor andevaluate system security and performance,and plan operations.

These three systems are sometimes integrated ina full energy management system (EMS).

Sophisticated coordinated operation and plan-ning systems control the vast complex of genera-tors, transmission lines, distribution systems, andsubstations that makes up the typical electricpower system. Coordination operation systemsinclude monitoring and communication equip-ment, devices that actually control generators andtransmission lines, and engineering models andexpertise that together specify how to operategenerators and transmission lines. Planning sys-tems focus on the selection of the technologyrequirements (generation, transmission, distribu-tion, and energy conservation/efficiency resourcesand operating and maintenance practices) to

satisfy predicted demand in an economic manner.Planning functions operate on several time horizons-from daily, weekly, or seasonal scheduling com-mitment of generation and transmission resourcesto long-term, 20- to 40-year system capacityexpansion and maintenance plans. Integratedresource planning is one planning mechan i smused to carry out utility intermediate and long-term strategic planning functions.

Backing the coordinated operation and plan-ning systems are advanced software and engi-neering models, experienced technical personnel,and a host of engineering and technical standardsand other institutional arrangements that togetherassure the safe, reliable, and economic operationof electric power systems and coordinate opera-tions with other interconnected utilities. Carryingout these various operations requires detailed andextensive information on utility systems, loadcharacteristics, and customer needs.

I Operating and Planning FunctionsTogether the coordinated operating and plan-

ning systems and procedures aid utilities in theperformance of three general functions: followingchanging loads; maintaining reliability; and coor-dinating power transactions.

In practice, utilities seek to perform thesefunctions at minimum cost. Each of these basicfunctions focuses on different time horizons anddifferent aspects of the power system. See table3-3. Some procedures are performed continu-ously, such as coordinating the energy output ofgenerating units to balance demand. Others, suchas planning generation additions and DSM pro-grams, are performed far less often. Each timehorizon beyond a few seconds requires forecastsof customer demand and performance of systemequipment. All require a tremendous amount ofinformation, computing power, and communica-tion capability, as well as extensive coordinationwithin and among the various organizationsinvolved.

. .


Table 3-3-Electric Utility Operating and Planning Functions

Function

Following loadFrequency regulation

Cycling

Maintaining reliabilitySecurity

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. Unitseasonal cycles (within commitment. Voltage control.equipment, voltage, powerlimits).

Preparing for unplanned Unit commitment (for spinningequipment 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.


FOLLOWING LOAD

The ability to follow load is central to theoperations of utility systems. Following loadrequires that at each moment the supply of powermust equal the demand of consumers and thatutilities maintain power frequency and voltageswithin appropriate limits across the utility sys-tem. Consumer demand for electricity changescontinuously and somewhat unpredictably. Someload changes tend to repeat cyclically with thetime of day, day of week, and the season. Othersresult from the vagaries of weather, economicconditions, and from the random turning on andoff of appliances and industrial equipment. Be-cause these load patterns cannot be forecastedaccurately, utilities must plan for and securegenerating, transmission, DSM, and control re-sources to meet a variety of future customer loadpatterns over the short, medium, and long term.Utilities rely on unit commitment schedules,

economic dispatch, and automatic and operatorcontrol of generation to follow loads whilemaintaining frequency and voltage.

Utilities establish detailed unit commitmentplans to ensure a sufficient supply of generationto follow loads and to provide backup powersupplies for immediate operation in case ofcontingencies such as failure of a generating unitor transmission line. The schedules are based onforecasted load changes over daily, weekly, andseasonal cycles plus an allowance for randomvariations and equipment outages.

Unit commitment schedules specify whichunits Will be warmed up and cooled down tofollow the load cycles and to provide spinningreserves. 65 Some generators in a unit commitmentschedule increase or decrease their power outputaccording to a schedule, following predictedloads; others are under AGC and economicdispatch 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 systeminstantaneously to meet additional demand or respond to outages.

.——.— . -—


purchases from other utilities are also specified.The unit commitment plan ensures that sufficientgeneration under governor control is available forregulating frequency in response to changingloads. Voltage control and reactive power deviceson the transmission system and in generatingplants are simultaneously coordinated to maintainsystem voltages as loads and supplies change.

Utilities calculate unit commitment schedulesto minimize the total expected costs of powergeneration and maintaining spinnin g reserves forreliability and to meet expected changes indemand. New unit commitment plans are typi-cally established each day or after major plantoutages or unexpected load changes.

Unit commitment planning requires a vastamount of information. Virtually all the informa-tion about generation and transmission operatingcosts and availability required by the dispatch andsecurity systems is also needed to develop thebest unit commitment schedule. In addition, thetime and cost to warmup generating units and theavailability of personnel to operate generatingunits must be considered. These factors varydepending on the type of generating unit. Unitcommitment schedules are typically developedusing computers to perform the numerous calcu-lations for identifying the minimum expectedtotal costs.

Maintaining FrequencyThe design of customer equipment such as

motors, clocks, and electronics often assumes arelatively constant power frequency of 60 Hz forproper operation. Actual frequencies in U.S.power systems rarely deviate beyond 59.9 and60.1 Hz, well within the tolerance of consumers’electronic equipment and motors. Power systemequipment is more sensitive to frequency devia-tions than consumer equipment and the controlsystems of modem power systems function bymonitoring slight frequency deviations and re-sponding to them.

Frequency fluctuations result from an imbal-ance between the supply and demand for power in

a system. In any instant, if the total demand forpower exceeds total supply (e.g., when a genera-tor fails, or as demand increases through thecourse of a day), the rotation of all generatorsslows down, causing the power frequency todecrease. A similar process occurs in reversewhen generation exceeds loads, with the gover-nors reducing the energy input to generators tomaintain frequency. Speed governors on mostgenerating units constantly monitor frequencyand regulate those units’ power output to helpbalance demand and restore the frequency.

The usefulness of a particular generator inregulating frequency varies from unit to unitbecause of differences in the vamp rate-the rateat which generator’s power output can increase ordecrease. Large steam generating units such asnuclear powerplants and large coal units gener-ally change output levels slowly, while gasturbines and hydro units are very responsive.Power system operators and planners must con-sider the responsiveness and availability of gener-ators to control frequencies in setting unit com-mitment schedules and plannin g new supplyresources.

Controlling VoltageMany types of customer equipment require

voltage to fall within a narrow range to functionproperly. For example, if delivered power voltageis too low, electric lights dim, and electric motorsfunction poorly and may overheat. Overly highvoltages, on the other hand, shorten the lives oflamps substantially and increase motor power,which may, damage attached equipment.

Unlike frequency, which is the same at alllocations in a power system, voltage varies frompoint to point. The voltages throughout a powersystem depend on the voltage output of individualgenerators and voltage control devices and theflows of power through the transmission system.

Maintaining voltage involves balancing thesupply and demand of reactive power in thesystem. Reactive power is created when currentand voltage in an alternating current system are

330-075 : QL 3 0 - 93 - 3

-.


not in phase due to interactions with electric andmagnetic fields around circuit components.66

Reactive power is often referred to as VARS (forvolt amperes reactive).

Maintaining voltages within the standards re-quired by system equipment is the function ofVAR control systems which monitor voltages andadjust generation and transmission system com-ponents accordingly. Monitoring equipment atvarious locations in the system measures andtelemeters voltages to the energy control centerwhere voltage levels are checked to ensure theyfall within the acceptable range. When voltagesbegin to deviate from the acceptable limits, bothautomatic and remotely controlled actions aretaken using a variety of reactive power controldevices. Supervisory control and data acquisitionsystems combine telemetry of voltage to thecontrol center and remote control of VAR sup-plies.

Reactive power is regulated by adjusting mag-netic fields within the generators either automati-cally or under the control of system operators.Control of generator VAR output and off-economy dispatch are common modes of voltagecontrol on the bulk power system. Other auto-matic and manual voltage control devices includecapacitors, shunt reactors, variable transformers,and static VAR supplies.

Plannin g and selecting generation and trans-mission resources and designing coordination andcontrol systems must build in consideration ofreactive power flows and VAR control to keep thesystem operating at the proper voltage.

Economic DispatchEconomic dispatch is the coordinated opera-

tion of generating units based on the incrementalcosts of generation and is a key to minimizingcost. The incremental production cost of a gener-ating unit is the additional cost per kilowatt-hourof generating an additional quantity of energy orthe cost reduction per kilowatt-hour due togenerating a lesser quantity of energy. Incre-mental production costs depend on the cost of fueland the efficiency with which the unit convertsthe fuel to electricity, and any other operationcosts that vary with the level of power output. Ineconomic dispatch, units with the lowest incre-mental costs are used as much as possible to meetcustomer demand, consistent with system secu-rity requirements. Typically, economic dispatchis entirely recomputed every 5 to 10 minutes at thecontrol area.

Automatic Generation ControlThe dispatch of generators in a control area is

handled by computerized AGC systems thatcalculate increases or decreases in each generat-ing unit’s output required to maintain the balancebetween supply and demand in the least costlyway. AGC gives utilities the capability of control-ling system operations for economic dispatch,load following, reliability, and coordinating trans-fers. An AGC system constantly monitors thepower system frequency to determine whetherincreased or decreased output is required andautomatically resets generator governors to main-tain frequency. AGC systems also monitor andreset dispatch to use low-cost generating units todisplace more expensive generation to the extentfeasible given the availability of adequate trans-

66 ~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 eachother-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 fromthat portion of current and voltage not in phase as the result of the interaction of real power flows with the eleetric and magnetic fields createdaround 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, Understandingthe pattern of voltages and reactive power flows is a complicated problem arising from the physics of electric systems.

—. —


mission capacity and system security (reliability)criteria. AGC systems control both the plannedand inadvertent power exchange between controlareas. The AGC system typically resets generatorgovernors every 5 to 10 seconds based on anapproximation of economic dispatch.

To perform effectively, an economic dispatchand AGC system needs detailed cost and perform-ance information (unit efficiency, dispatchability,capacity utilization, contract rates and terms)about each of the power system’s operablegenerating units. The economic dispatch-AGCsystem also must take account of possible trans-mission line losses, and the adequacy and availa-bility of transmission capacity to transfer powerwithin voltage and load flow limits in determini-ng the order of dispatch.

The extent of generation dispatchable underAGC systems is another factor that utilitiesconsider in scheduling unit commitment and inplanning new resource additions.

MAINTAINING RELIABILITYReliability is a measure of the ongoing ability

of a power system to avoid outages and continueto supply electricity at the appropriate frequencyand voltage to customers. To preserve reliability,utilities must plan for and maintain sufficientcapacity or power supply arrangements to coverunscheduled outages, equipment failures, operat-ing constraints for generating units, powerlinesand distribution systems, coordinating mainten-ance scheduling, and addition of new resourcesand growth in customer demand. There are twoaspects of reliability-security and adequacy.

Preparing for continued operation of the bulkpower supply after sudden system disturbancesand equipment failures is called maintainingsecuri ty.67

Bulk system outages occur when

generation and transmission are insufficient tomeet total customer demand at any instant, suchas when a lightning strike on a transmission line

or sudden equipment failure suddenly reduces theavailability of a critical generator or transmissionline. Bulk system failures account for a relativelysmall portion of customer service outages—around 20 percent. Distribution system problems,often from storm damage to distribution lines, arethe source of most power outages experienced bycustomers. Security is maintained by providingreserve capacity of both generation and transmis-sion in unit commitment schedules and security-constrained dispatch. The order of economicdispatch will be overridden if the dispatch schemewould threaten system security. Together with thecoordinated engineering of relays and circuitbreakers used to isolate failed or overloadedcomponents, they ensure that no single failurewill result in cascading outages.

The second major element of reliability ismaintaining adequacy, which is the ability of thebulk power system to meet the aggregate electricpower and energy requirements of the consumersat all times, taking into account scheduled andunscheduled outages of system components. Main-taining adequacy requires utilities to plan for andoperate their systems to accommodate a numberof uncertainties and constraints on system availa-bility. The major uncertainties that utilities mustdevelop contingencies for include: the cost andavailability of fuels, future operating costs forgenerating units, construction cost and schedulesfor new equipment, and the demand for power.‘Technical constraints on system availability thatmust be addressed to preserve adequacy include:unit commitment schedules and economic dis-patch for load following and security require-ments, scheduling maintenance requirements forsystem components, and transmission and distri-bution system capabilities.

Planning new generation and transmissioncapacity involves selecting the right mix andlocation of both generation and transmission tomeet 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 towithstand sudden disturbances such as electric short circuits or unanticipated loss of system components. ”


reliability under a variety of possible futures. Inselecting an appropriate resource mix to meetcustomer needs, system planners are supposed tobalance the value to the customer of havingreliable service with minimal outages and thecosts to the utility of providing this service.However, deriving quantitative estimates of thevalue of various levels of reliability to thecustomer and the costs to the utility of avoidingoutages under a variety of conditions has provendifficult and intractable. Therefore, in practice,engineering planners assume a variety of rules ofthumb or de facto reliability standards in systemplanning and operations. Three of the mostcommon reliability-related goals are:

1.

2.

3.

loss of load probability (LOLP) of 1 day in10 years,first (or second) contingency security, and

reserve margins of 15 to 20 percent. (Seebox 3-B.)

These reliability standards specify the amount ofcapacity to be installed (e.g., reserve margins andLOLP), and how that capacity must be operated(contingency security). Thus, they play a centralrole in determining the constraints and capabili-ties of modem power system operations andplanning. The choice of which standard to use isa matter of experience and engineering judgmentas well as system-specific characteristics forindividual utilities.

A key to security-constrained dispatch is sched-uling generation in a “defensive” mode so thatthe power system will have enough supplies readyto continue operating within emergency standardsfor frequency, voltage, and transmission lineloadings should contingencies (such as generatoror transmission failures) occur. Defensive operat-ing practices entail holding generating units andtransmission capability in reserve for the possibleoccurrence of a major failure in the system. Idlegenerating units and transmission lines withbelow-capacity power flows may mistakenlyseem to be surplus, when in fact they are essentialfor reliability.

Emergency OperationsReliability operations and planning also entails

establishing procedures for system emergencyoperations and restoring power for reliabilityemergencies. System emergencies occur whenthere simply is not enough capacity availableeither within the utility or through neighboringsystems to meet load. When voltages and frenquen-cies deviate too much as a result, relays andcircuit breakers may isolate overloaded genera-tors and transmission components from the sys-tem, exacerbating the imbalance between supplyand demand. Emergency operations involve avoid-ing cascading outages by reducing the powerdelivered to consumers. In the extreme, thisrequires disconnecting customers from the sys-tem. Plans for load shedding must be coordinatedwith the automatic isolation of generating unitsthat occurs under abnormal frequency and voltageconditions. Restoring power also requires coordi-nation of the system components and the devicesused to isolate the loads. Following systemfailures, restoration requires that some generatingunits be capable of starting on their own, called“black-start capability. ” Not all generators havethis capability, typically taking their startingpower from the system, and must be taken intoaccount in unit commitment schedules and re-source planning.

COORDINATING TRANSACTIONS

The third major function of coordinated operat-ing and planning systems is to carry out powertransactions. Interutility transactions take a vari-ety of forms, including: short- and long-termpurchases and sales with neighboring systems;purchases from suppliers within a utility’s servicearea (e.g., an independent power producer);operation of jointly owned powerplants; andwheeling of power. Coordinating transactionsinvolves scheduling and controlling generationand transmission to carry out the power transfers,as well as monitoring and recording transactionsfor 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 meetcustomer 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 customerdemands, 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 areimmediately available so that the power system will continue to operate in the event that the one (or two) mostcritical components fail. Usually the critical components are the largest generators or transmission lines, or somecomponent at a critical Iocation in the network. The reliability criterion applies at all times, even when someelements are already out of service. The criteria are established based on contingency studies and rely onengineering 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 percentageof peak load and is the oldest and most traditional measure of reliability.1

For example, in a system with a peakload 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 andunscheduled outages. However, the appropriate reserve margin to assure reliability is determined based onsystem-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 asthe 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 fewpercentage points. In practice, however, most utilities refer to their reserve margins. Capacity margins of 13 to 17percent 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. Itthird-party utilities that may be affected.

I Interutility Coordination and CooperationThe simple model of an electric utility system

like that in figure 3-5 is of a stand-alone integratedutility that serves its own needs within anexclusive, geographically compact retail servicefranchise area. The model utility generates suffi-cient electric power from its plants to meetcustomer demand and delivers it via its owntransmission and distribution systems to its cus-tomers. It exercises sole control over the opera-tion and planning of all its system componentsand derives its profits from retail power sales and

operates under the oversight of a single Stateratemaking authority. The modern-day reality ofelectric utility systems, however, is far morecomplex.

Nearly all U.S. utilities operate as part of aninterconnected regional grid and not as isolatedsystems. All these interconnected systems aremultistate operations with the exception of Alaska,Hawaii, and utilities within the Electric Reliabil-ity Council of Texas (ERCOT). The transmissioninterconnections improve electric system reliabil-ity by allowing utilities to share generating andtransmission resources, provide backup powersupplies at peak loads and during emergencies,


and engage in other bulk power transactions.While clearly conferring benefits, these intercon-nections also impose physical and legal con-straints on utility systems. Utility operations andplanning require a high degree of cooperation andcommunications among utilities on the system,and must satisfy technical performance standardsand other formal and informal obligations im-posed through control area and interconnectionsagreements, power pools, reliability councils, andvarious contractual arrangements for bulk powertransfers.

Each utility is responsible for providing thepower used by its customers without taking powerfrom neighbors, unless alternate arrangementshave specifically been made. Many utilitiesdepend on wholesale purchases of electricityfrom other utilities or public power agencies orindependent power producers for some or all oftheir power requirements. Utilities rely on whole-sale transactions because they do not have enoughgenerating capacity to meet the needs of theircustomers and/or because lower-cost power isavailable from others. Indeed, there are a largenumber of small municipal systems dependent onregional investor-owned or public power systemsfor their electricity supplies and transmissionservices. Many large investor-owned utility sys-tems support generation and transmission facili-ties not only to serve their own retail distributioncustomers, but also to meet the long-term obliga-tions to wholesale customers within their serviceareas, and to engage in short- or long-termwholesale power transactions with other utilities.

There are significant variations among utilitiesin different regions, and among utilities in thesame region, that help shape plannin g and opera-tions decisionmaking and regulatory policy. Theseinclude differences in industry structure, compo-sition, and resource base characteristics that aretraceable to patterns of population, climate, eco-nomic activity, and the history of electrificationwithin each region. Among utilities, differencesin generation reserve margins, fuel mix, loadgrowth and coordination, and access to regional

transmission systems will further shape powermarkets and resource options.

The structure of the electric power industry hasbeen changing over the past decade as utilitieshave merged, reorganized into (exempt) holdingcompany structures, and diversified into regu-lated and nonregulated ventures. One result ofthis diversification and corporate reorganizationamong investor-owned utilities is that traditionalelectric utility operations are no longer the only(or most profitable) source of corporate income.In some cases, the regulated public utility subsid-iary serving retail distribution customers couldfind itself in competition with, or purchasingfrom, unregulated independent power and energyservices subsidiaries or joint ventures of its parentholding company. These changes are introducingsubtle and not so subtle influences into corporatedecisionmakingg--how will company officers anddirectors decide between providing for long-term,least-cost resources for the regulated electricutility and pursuing potentially higher returns onunregulated ventures. The changes create newchallenges for utility regulators in policing thepotential for self-dealing and cross-subsidizationof unregulated ventures by utility ratepayers and,in many cases, transfer the regulatory venue fromState to Federal jurisdiction.

The picture is further complicated by thegrowing presence of independent power produc-ers and energy service companies as competitorswith, and suppliers to, regulated electric utilities.These unregulated entities operate under differentfinancial and regulatory regimes than traditionalintegrated utilities, and it remains to be seen ifexisting resource planning and regulatory ap-proaches will be adequate to secure reliable andreasonably priced resources from these newentrants over the longer term.

The growing split in jurisdiction over electricutilities among States and between States and theFederal Government will undoubtedly influenceresource decisions by individual utilities and byregulators. Greater reliance on bulk power trans-actions in utility resource plans will mean that

—

Chapter 3-Electric Utility Industry Structure, Regulation, and Operations 161

Federal regulators will have a more dominant rolein determining electricity costs and that Stateregulators’ control over utility costs, and ulti-mately retail electricity prices (rates), will bediminished.

As a result of these various influences, eachutility system has a unique set of operational,structural, regulatory, and geographic conditions

that drive its investment decisions and opportuni-ties for enhancing energy efficiency. This diver-sity precludes easy generalizations and one-size-fits-all policy prescriptions for utility energyefficiency. Nevertheless, most utilities generallyadhere to similar goals, performance standards,and operating and plannin g functions and proce-dures.

I

c

Using ElectricityMore Efficiently:

Demand-SideOpportunities 4

ommercially available energy-efficient technologies offerabundant opportunities to cut electricity consumption inthe residential, commercial, and industrial sectors. Themajor electricity uses across all sectors are lighting,

space conditioning, water heating, motors, drives, and appli-ances. Studies of energy efficiency opportunities have identifieda variety of technologies for each of these applications that offercost-effective savings and rapid paybacks. Still other energy-saving technologies are not currently cost-effective in mostapplications, but could prove more financially attractive ifeconomies of scale cut costs, if energy prices rise, or if policyinterventions provide additional incentives to install them.

This chapter briefly examines some of the energy efficiencyopportunities in the residential, commercial and industrialsectors, including a profile of electricity use in each sector,examples of electricity-saving technologies, estimates of poten-tial 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 inthe estimates are attributable to what measure of energyefficiency is used—maximum technical potential, cost-effectivepotential, or achievable or likely savings potential. (See box4-A.) The studies vary in assumptions about technology penetra-tion rates, energy demand, consideration of cost-effectivenessand discount rates,

The Electric Power Research Institute (EPRI) has estimatedthat if the existing stock of equipment and appliances werereplaced with the most efficient commercially available technol-ogies, projected U.S. electricity use in the year 2000 could be cutby 27 to 44 percent without any diminution of services.l (See

1 Barakat & Chamberli~ Eficient Electricity Use: Estimutes of Maximum EnergySa\’ings, EPRI CU-6746 (Palo Alto, CA: Electric Power Research Institute, March 1990),hereafter referred to as EPRI, Efficient Electricity IJse.

-/” “

I 63

.—


Box 4-A-Estimating Energy Efficiency Savings

Estimates of potential energy savings from efficient technololgies vary considerably. At least part of thedifference in estimates can be attributed to what iS being estimated. Most published estimates use one of thefollowing measures:

Maximum technical potential, or MTP, is a measure of the most energy that could be saved if all possibleefficiency improvements were made with the most efficient technologies adopted in all new and existingapplications (i.e., 100 percent penetration reached. Achieving MTP savings assumes agressive government andprivate 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 rebatesand other financial incentives.

Cost-effective potential is an estimate of the energy savings that could reobtained if efficient techndogiesare installed in new and replacement applications whenever they are cost-effective. Cost-effective potential islower than MTP and depends on projections of future marginal electricity costs and rates. Severalcost-effectiveness tests are in common use in utility planning and rate regulation. See chapter 6 for more oncost-effectiveness tests.

Likely energy efficiency savings estimates are used in utility planning and reflect judgments about thesavings from efficient technologies adopted in response to utility programs. Likely impacts are lower thancost-effective potential because of the influenoe of various factors inducting, for example: lack of customerawareness of potential savings or utility programs, customer reluctance to convert with new or differenttechnologies, and constraints on the supply or deliverabilityof the technology.

Natural occurring energy efficiency savings estimates reflect estimates about the penetration of energyefficient technologies in response to normal rnarketplace conditions and existing standards In the absence of newutility or other programs to encourage their adoption. The savings arise from installation of newer, more efficienttechnologies- but not necessarily the most efficient technologies commercially available--in new andreplacement applications. Estimates of naturally occurring savings are used by utilities to evaluate the

EPRI Base Case Usage and Maximum TechnicalPotential (MTP) From Electricity-Savings Technologies

Savings in 2000

MTP Cost-effective

—

Likely Naturallyoccuring

effectiveness of efficiency programs.Actual electricity use is compared towhat consumption would have been ifefficiency levels were frozen at a baseyear’s level and then the effects ofnaturally occurring savings are sub-tracted to yieid the savings attributableto the utility program

The figure shows a conceptual com-parison of the relative magnitude ofdifferent estimates of energy efficiencypotential.

In this chapter, OTA has adopted theMTP estimates from efficient electrictechnologies published in a 1967 re-port for the Electric Power ResearchInstitute (EPRI).1 The EPRI analysisprovides one of the few comprehen-

CU-6746(PaloAlto, CA: The Electric Power Research Institute, March 1990).The Electric Power Research - IinstituteIsa 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 ofall the existing stock of installed electric equipment; and 2)replacing Iess-efficient fossil-fired equipment with moreefficient electrotechnologies in industrial processes. EPRI’s MTP estimates compared with current and projectedelectricity 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 bestease scenario in which all applicable technologies are replaced instantaneously with the most efficientcommercialty 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 technologyadoption: an ‘optimistic” or high impact scenario assuming adoption of all commercially available technologies (i.e., noprototypes, demonstration models, or lab bench-scale technology@, and a conservative” or low impact scenarioreflecting 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 improvementsand equipment cost.

table 4-l.) (EPRI is the joint research institute lar applications or projections of future electricitysupported by funds from America’s electricutilities.) The EPRI analysis presents its best-caseestimates of the most energy that could be savedthrough efficient technologies, further improvem-ents in existing technologies, and policy initia-tives such as information programs, rebates andother incentives that make the alternatives attrac-tive to everybody. The range in their estimatesfrom “conservative low impacts” to best-case,“high” impacts reflects uncertainties in technol-ogy applicability, manufacturing capabilities, andperformance characteristics.

The analysis did not include assessments of thecost-effectiveness of the technologies in particu-

costs and rates that would strongly influencecost-effectiveness determinations. Considerationsof cost, practicality, and capital availability maypreclude attainment of the maximum savingspotential, but nevertheless EPRI believes that

many opportunities remain for substantial gains.2

The EPRI maximum technical potential estimatesare cited in this chapter to provide some measure

of prospective energy savings that can be targeted.Amory Lovins and others at the Rocky Moun-

tain Institute have estimated the maximum tech-

nical potential of efficiency savings as high as 75percent by 2010.3 Other studies have included con-siderations 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 theresidential and commerc id sectors by 2015 over a business as usual scenario. IrI fact total energy use in these sectors would decline somewhatundtx an aggressive efficiency strategy. These two sectors combined are ofta dubbed “the buildings sector” because energy use for buildingsystems (space heating and conditioning, ventilation% lighting, and watex heating) has made up the overwhelming bulk of energy consumptionin 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. GovernrmmtPrinting 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, “EfficientUse of Electricity,” Scientific Amen’can, September 1990, pp. 65-74.


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 2000Base 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. . . . . . . . . . .

159,824103,49978,12715,25415,30830,390

146,57259,779

240,861

223,024134,50990,13413,06323,70739,271

139,25548,073

353,620

71,91543,48126,265

2,4211,2403,115

30,71611,53498,242

32.20/.32.329.118.55.27.9

22.124.027,8

122,28588,99530,9964,2226,2337,132

66,89615,594

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% 351,040Electrolytic. ... , . . . . . . . . . . . . . 98,193 138,273 25,950 18.8 41,124Process heating. . . . . . . . . . . . . . . 83,008 125,274 9,928 7.9 16,606Lighting. . . . . . . . . . . . . . . . . . . . . . 84,527 114,097 19,016 16.7 38,032Other. . . . . . . . . . . . . . . . . . . . . . . . 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. . . . . . . . . . . . . . . .

77,245154,29976,95924,06816,17260,883

238,488108,447

128,322208,10696,09439,79426,38181,652

283,124177,254

16,33562,43228,82815,9175,2769,925

62,91632,228

12.7%30.030.040.020.012.222.218.2

30,333145,67448,04723,876

7,91427,857

157,29164,456

Total commercial. . . . . . . . . . . . 756,561 1,040,726 233,858 22.5940 505,448

54.8%66.234.432.326.318.248.032.440.0

45.5%

45.094029,713.333.3

0.0

38.3%

23.694.70.050.060.030.034.155.636.4

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 EnergySavings, EPRI CU-6746 (Palo Alto, CA: Electric Power Research Institute, March 1990), p. 3.

tOTA’s report Energy Technology Choices: institutional, and behavioral barriers that have

Shaping Our Future4 moderate-efficiency sce- hampered full use of cost-effective, energy-nario assumes adoption of all cost-effective savings opportunities. Under the moderate-efficiency measures (defined as measures that efficiency scenario, electricity demand in 2015repay their added incremental costs with energy would be 25 percent less than the baselinesavings over their lifetimes). The scenario also demand (which assumes some naturally occur-assumes adoption of a variety of government ring efficiency improvements, but no significantpolicy 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.


The 1991 National Energy Strategy projectsthat electricity consumption in 2010 will be about12 percent less than the current policy baselinedue to cost-effective energy savings from pro-posed initiatives to promote utility integratedresource planning (and associated demand-sidemanagement programs), building and applianceefficiency standards, and industrial conservationresearch and development.6

Other studies on energy efficiency opportunitiesin specific sectors or regions have yielded simi-lar estimates of cost-effective savings potential.

There is considerable agreement among thevarious energy efficiency potential studies aboutthe most promising strategies for achieving moreefficient use of electricity. They include:

improvements in the thermal integrity ofbuilding shells and envelopes;improvements in the efficiency of electricequipment;lighting improvements;net efficiency gains from shifting energysources from fossil fuels to electricity (electri-fication); andoptimization of electricity use through betterenergy management control systems, shiftsin time of use, and consumer behavior andpreference changes.

ENERGY-EFFICIENCY OPPORTUNITIESFOR RESIDENTIAL CUSTOMERS

The residential sector essentially consists of allprivate residences including single and multifa-mily homes, apartments, and mobile homes.Institutional residences, such as dormitories, mil-itary barracks, nursing homes, and hospitals areincluded in the commercial sector, About 22percent of total primary energy consumption inthe United States can be attributed to residentialsector energy demand. Total energy expendituresby the residential sector in 1990 were $110.5billion.7

Figure 4-1 shows direct on site energy con-sumption in the residential sector.8 Electricity atpresent supplies about 30 percent of residentialenergy needs and this share is expected to grow aselectric heating and appliance loads grow. Natu-ral gas supplies 47 percent of residential energyuse mostly for space and water heating. Theremaining residential energy consumption con-sists of oil (15 percent), coal ( 1 percent), and otherenergy sources (7.6 percent), predominantly fire-wood. 9

The residential sector accounts for about 34percent of all U.S. electricity sales. In 1990, totalresidential electricity sales (exclusive of conver-sion 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 ExpendituresPreliminary 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 AnnetteB. 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 InformationAdmmistration, 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 byelectric utilities in the generation, transmission and distribution of electricity for residential customers, eledricity accounts for some 60 percentof primary energy consumption attributable to the residential sector. The existence of these sizable conversion and delivery losses associatedwith end-use electricity consumption means that energy savings at the point of use are magnified in their impacts on utilities and overall primaryenergy 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.

. . -


Figure 4-l-Residential On-Site EnergyConsumption by Source, 1990 (quadrillion Btus)

Oil 15%1 6

Other

F

Other 80/00.8

SOURCE: Office of Technology Assessment, 1993, based on datafrom the U.S. Department of Energy, Energy Information Administra-tion, and the Gas Research Institute. Figure excludes generation andtransmission losses.

kilowatt-hours (kWh) at a cost of $72 billion. l0

Residential electricity demand growth is drivenby population, climate, number of households,the number of persons per household, regionalpopulation growth patterns, increased demand forelectricity-intensive services (e.g., air-condition-ing, clothes-dryers) and size of residences.11

Among factors that tend to limit growth are thedecline in population growth, the increased effi-ciency of new housing stock and appliances, andretrofits of existing housing units.12 Variousforecasts peg expected growth in residentialelectricity demand at from 1 to 2 percent peryear.13

Figure 4-2—Residential ElectricityUse by Application, 1987

Space heatingDishwashing 19%.

\Water heating

12“/0

L

.-

reezers7%

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 datafrom the U.S. Department of Energy and the Electric Power ResearchInstitute.

Figure 4-2 shows household electricity use byapplication.

14 Within each of the categories shown

there are a number of attractive and cost-effectiveoptions for cutting household electricity use,without diminishing the services provided.

EPRI’s analysis of maximum technical poten-tial estimated that residential electricity use in2000 could be reduced by from 27 to 45 percentif the most efficient end-use technologies cur-rently available commercially were used to re-

place the existing stock of electric appliances in

homes. The EPRI study did not include estimatesof total costs for achieving this maximum techni-cal potential, nor any analysis of the cost-

lo 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 applianceswith more efficient models. Other studies haveincluded cost-effectiveness considerations in theiranalyses and generally found considerable oppor-tunities for electricity savings in the residentialsector at a cost less than that of supplyingelectricity .15

H Residential Energy EfficiencyTechnologies

There are a variety of technologies available tocut residential energy use without diminishing theservices provided. Some of these technologies arelisted in table 4-2. The basic strategies for cuttingelectricity use in the residential sector are:

■

■

■

Improving residential building shell effi-ciency through better insulation by cuttingconductive heat losses and gains throughceilings, walls, and floors; installing stormdoors and windows; and cutting air infiltra-tion by caulking gaps and weatherstrippingaround doors, windows, joints and otherspaces.Choosing more efficient appliances for newinstallations and accelerating the retirementof older less efficient appliances.Improving the management of residentialenergy use through better maintenance, en-ergy management controls, load shifting, andchanges in occupant behavior.

Improving the energy efficiency of existingbuildings is one of the most promising and vital

areas for energy savings. Space heating andcooling account for 30 percent of residentialelectricity use. Improved thermal integrity in newand existing residential buildings can reduceheating and cooling loads and save electricity.

Replacement of existing buildings by energy-efficient new buildings is slow and expensive;most of the existing housing stock will continuein use for the next 30 to 40 years or more. Thereare over 90 million residential units in the UnitedStates, and we are adding between 1 and 2 millionunits per year. Although by the year 2000 therewill be 10 to 15 million new units, about 90percent of the units existing in 2000 have alreadybeen built, and by the year 2010 it is estimatedthat about 70 percent of homes will consist ofhousing stock built before 1985.16

The most cost-effective time to incorporateenergy-saving measures into buildings is whenthey are built, remodeled or rehabilitated. In fact,failure to make accommodation for energy-saving technology in material and design choicesat this stage causes lost energy savings opportuni-ties—for example, e.g., using the standard 2-by-4dimension lumber in exterior walls instead of2-by-6 construction that allows for more insula-tion, or not selecting the most energy efficientwindows.

Careful attention to energy efficiency featuresin the design, siting, and construction of residen-tial housing can save electricity. Over the past twodecades, because of high energy prices, buildingcode 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 LawrenceBerkeley 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 costof conserved energy below 7.6 cents/km using a discount rate of 7 percent. See J, Koomey et. al, The PotentiaJjiir Electn”city EficiencyImprovements in the U.S. Residential Sector, LBL30477 (Berkeley, CA: Lawrence Berkeley Laboratory, July 1991), pp. 35-36. Artotheranalysis of possible electricity savings in Michigan found achievable savings of 29 percent in residential electricity use by 2005 at reasonablecost over a business-as-usual baseline with aggressive conservation programs and commercially available technologies. F. Krause et al., FinalReport: 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 Statecould be cut 34 percent at a cost below that of supplying electricity-less than 7 cents/kw assuming a 6-percent discount rate. American Councilfor an Energy Efficient Economy, The Potential for Energy Conservation in New York State, NYSERDA Report 89-12 (Albany, NY: NewYork 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.


Table 4-2-Selected Energy Efficiency Technology Options for the Residential Sector

Building envelope improvements Alr-conditionersCut 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 unitsSpace heating ■ Frequent cleaning of filters and coils

Use heat pumps instead of resistance heatAir source heat pumps Refrlgerators and freezers■ More efficient models Efficient motors and controls■ Improved technology Improved gaskets and sealsGround-source heat pumps Improved insulationSolar heating Improved malntenance

■ Clean coils oftenEnergy management controls and systems■ Set-back thermostats Lighting■ Smart house/smart systems Replace incandescent with fluorescent and compact. Zoned heat systems fluorescent

Reduced wattage incandescentAir distribution systems Dimmers, controls, and sensors= Improved insulation Reflective fixtures■ Reduced duct leakage

CookingWater heating More efficient ovens and stoves

Blanket wrap of existing tanks Alternative cooking devicesMore efficient tanks ■ Microwave ovensincreased insulation for tanks and pipes ■ Convection ovensLow-flow devices . Induction cooktopsThermal trapsSet-back thermostats DishwashersHeat-pump water heaters Energy-saver cyclesAlternative water heating systems No-heat drying= Heat recovery water heaters Reduced hot water usage■ Solar water heat systemsReduced thermostat settings


efficiency, newer residential buildings make greateruse of energy-efficient features.17 In fact, newhouses built in 1985 were much more energyefficient than those built in 1973 and were betterinsulated and had more energy-efficient win-dews.lg Design features to take advantage ofpassive solar heating and daylighting can also beincorporated into new units for additional sav-ings.

The rate of replacement of major applianceswith newer, more efficient models has been slowand will continue to be so in the absence of policyinitiatives or large changes in energy prices.Major electric appliances such as furnaces, heatpumps, central air-conditioners, water heaters,and refrigerators often are in use for 10 to 20 yearsor more and are unlikely to be replaced unlessthey fail. It could take as long as 20 years torealize potential savings from currently available

17 OTA, Building Energy E@ciency, Supra note 2.

18 Ibid., p. 18.

———


19 Not installing theefficient new equipment.most energy-efficient model initially creates lostefficiency opportunities for a decade or more.Assuring the installation of the most efficientappliances and accelerating the replacement ofolder inefficient appliances offer prospects forreaping energy savings.

Building shell improvements in existing build-ings are effective means of cutting heating andcooling costs and increasing occupant comfort.The most common weatherization retrofits in-clude: installing more insulation in ceilings,walls, and floors; adding storm windows anddoors, and weatherstripping and caulking win-dows and doors. One study of home retrofitsfound variations in savings attributable to climateand differences in individual building characteris-tics. Average savings of 12 to 21 percent inheating energy demand and payback periods ofabout 6 years were found for ceiling and wallinsulation. Another intensive experiment in weath-erization cut space heating electricity use bytwo-thirds. 20 According to DOE surveys manyAmericans have already taken some steps toimprove the energy efficiency of their homes.21

Even where some weatherization measures havebeen reported it is likely that additional efficiencyupgrades are possible.

SPACE HEATINGAbout one-quarter of American homes (22

million units) depend on electric heat and eachyear more and more electrically heated units areadded. 22 Electric space heating accounts for 19percent of residential electricity consumption.There are two basic categories of electric spaceheating systems: electric resistance heat systems(including electric furnaces, baseboard heaters,

Caulking gaps around windows and doors can reduceinfiltration, and thereby reduce energy use for spaceheating and cooling.

and portable heaters) and electric heat pumps(including air-source heat pumps, and ground-source heat pumps). Electric resistance heatingsystems are virtually 100 percent efficient, that is100 percent of the energy delivered to the systemis converted to heat, so that there are few technicalopportunities to improve on their performance.

Electric heat pumps use a reversible vaporcompression refrigeration cycle to transfer heatfrom an outside source to warm indoor spaces inthe winter; in summer, the cycle reverses to coolindoor spaces by removing heat from inside anddischarging it outdoors. The most commonlyused heat pump is the air-source heat pump thatuses the ambient air as its heat source. On averageheat pumps are twice as energy efficient aselectric resistance systems. However, the per-formance of heat pumps is highly variable anddependent on sizing, climate, and the ratedperformance 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 Eficiencysupra 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 havea backup heat source, usually an electric resis-tance heater. There is a considerable range in theperformance of residential heat pumps currentlyon the market. The typical heat pump has aheating efficiency (heating season performancefactor, or HSPF) of about 6.9 Btus per watt-hourand a cooling efficiency (seasonal energy effi-ciency ratio, or SEER) of about 9.1 Btus perwatt-hour. See box 4-B for a description ofcommon energy efficiency measures. The bestunits currently on the market have efficiencies of9.2 HSPF and 16.4 SEER.23 Federal minimumefficiency standards for heat pumps sold after1992 specify 6.8 HSPF and 10.0 SEER.24

Another variant of the heat pump, the ground-source heat pump uses groundwater, or theground itself as the heat source. This technologyoffers an advantage over air-source heat pumps,in that ground temperatures seldom drop belowfreezing, thus there is no loss of heating capacityor resultant need for supplemental resistance heat.

For both heat pump and electric resistance heatsystems, improving the thermal integrity of thebuilding shell or envelope and insulating andplugging leaks in air distribution ducts can alsocut heat losses and reduce the heating loads.

EPRI estimated that a combination of envelopeimprovements, a shift to electric heat pumps, andimprovements in heat pump efficiencies couldresult in savings of 40 to 60 percent in spaceheating electricity demand in 2000 over 1987stock.

SPACE COOLINGAir-conditioning accounts for about 11 percent

of residential energy consumption and this de-mand is projected to grow as more homes are

air-conditioned. Over two-thirds of U.S. homesare now air-conditioned; 40 percent have centralair-conditioning and 29 percent have room units.Over three-quarters of new housing units havecentral air-conditioning. But this growth in air-conditioning demand has been offset by increasesin the efficiency of both central and roomair-conditioning units.

The most efficient central air units on themarket today have a SEER of 16.9 Btus perwatt-hour 25 and new Federal appliance standardsin effect in 1992 will require a minimum SEER of10 Btus per watt-hour. Just 10 years ago, theaverage efficiency for new central air systems was7.8 Btus per watt-hour. These gains were due tomore efficient fan motors and compressors, largerevaporator coils and condensers, and reducedairflow resistance. EPRI estimated that as of1987, the stock of central air units in use had anaverage SEER of 7 Btus per watt-hour—considerably below the most efficient systems onthe market. New installations and replacement ofexisting units with higher-efficiency central airunits could cut electricity use by central air-conditioners in 2000 by 29 to 34 percent or moreaccording to EPRI.

Room or ‘window’ air-conditioners have alsoimproved with the addition of more efficientmotors for fans and compressors, better fan bladedesign, larger heat exchangers, reduced airflowpath resistance and better low-temperature refrig-erant line insulation.26 Efficiencies vary accord-ing to model sizes and features, but neverthelessnew units today use about 30 percent lesselectricity to operate than units sold in 1972. Themost efficient units available today, with SEERSof 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.

—= ——. - — .— ——


Box 4-B-Measuring Energy Efficiency

Various measures are used to indicate the energy efficiency of electrical devices. The following are amongthe most common measures for residential and commercial equipment

The energy efficiency ratio (EER) Is used to measure the coding performa- of heat pumps andair-conditioners. EER is expressed as the number of Btus1 of heat removed from the conditioned space perwatt-hour of electricity consumed (i.e., the cooling output divided by the power consumption). Typical EERs forroom 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 heatpumps. SEER is expressed as the number of Btus of heat removed from the conditioned space per watt-hour ofelectricity consumed under average U.S. climate conditions. Unlike the EER, the SEER incorporates seasonalperformances under varying outdoor temperatures and losses due to cycling. Typical SEERS are 9.0 to 12.0 Btusper watt-hour.

The heating seasonal performance factor (HSPF) is a measure of the seasonal heating efficiency of heatpumps under varying outdoor temperatures, losses due to cycling, defrosting, and backup resistance heat foraverage U.S. climate conditions. HSPF is expressed as the number of Btus of heat added to the conditioned spaceper 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 usedto provide 84 gallons of hot water per day.

The annual energy coat (AEC), required by Federal appliance labeling regulations, reflects the cost ofenergy (usually electricity) needed to operate a labeled appliance for 1 year at a specified level of use. The AEClabel provides information on the costs of operating the labeled appliance and similar models over a range ofenergy 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 raisethe 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 EnergyEfficiency, OTA-E-518 (Washington, DC: U.S. Government Printing Office, May 1882), p. 68 and American Council for an Energy-EffkientEconomy, 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. Carefulper watt-hour. Using the most efficient room unitsfor new and replacement installations could cutroom air-conditioner electricity use by 19 to 32percent by 2000 according to EPRI’s analysis.

Better maintenance of air-conditioners can alsoboost efficiency. A dirty filter can cut efficiencyby 10 percent. Cleaning air-conditioner coils andcleaning or replacing dirty falters can preserveefficiency.

Heat pumps are also used for space cooling.Today’s typical heat pump has a SEER of 9, butcommercially available high-efficiency modelshave SEERS up to 16.4. New Federal standardseffective in 1992 will set minimum cooling

selection and sizing of heat pumps to matchcooling loads, especially in hot climates, canincrease efficiency.

WATER HEATINGElectric water heating is used in about 37

percent of American homes and makes up about12 percent of residential electricity consumption.Electric resistance water heaters are the mostcommon type of electric water heater in use todayand new units incorporating better tank insulationand improved heat transfer surfaces, use 10 to 15percent less electricity than models of 10 yearsago. (On average, larger size hot water tanks are


less efficient.) Other electricity-saving measuresinclude wrapping the outside of the hot water tankwith an insulating blanket, insulating hot waterpipes, and installing devices such as low-flowshowerheads, aerators, and self-closing hot waterfaucets. EPRI estimated that use of these energy-saving measures could cut water heating powerneeds by 20 to 30 percent in 2000.

Shifting to alternative electric water heatingsystems, such as heat-pump water heaters, heat-recovery water heaters, and solar hot watersystems can achieve efficiencies of up to 70percent. Overall, EPRI estimated that the range ofefficient electric water heating technologies of-fered savings of from 40 to 70 percent.

REFRIGERATORS AND FREEZERSTogether, refrigerators and freezers make up

about 24 percent of residential electricity de-mand. Both technologies have seen substantialincreases in efficiency over the past 20 years, butopportunities for significant improvements inperformance remain.

The typical refrigerator on the market todayuses just 45 percent of the electricity needed torun the average 1972 model.27 A combination oftechnological gains has produced these savings,including: more efficient fans, motors, and com-pressors; better and more compact insulation;improved door seals and gaskets; and dualcompressors. DOE researchers believe that it istechnically feasible to cut electricity needed torun today’s average new model almost 50 percentfurther. EPRI’s analysis estimates that moreefficient refrigerators could cut energy use about22 to 48 percent in 2000 over the 1987 stock.Even more efficient refrigerators are availabletoday than those assumed in the EPRI report. sothat the maximum potential savings probably

understate the potential.

Freezers account for 7 percent of residentialelectricity use and are found in about 34 percentof U.S. households. Stand alone freezers alsohave seen significant efficiency gains over thepast 20 years as a result of advances in refrigera-tion technology. The typical model sold todayuses half the electricity of the average 1972 modeland as with refrigerators, additional efficiencygains are probable.

More efficient freezers could save 24 to 32percent over energy required for the 1987 stockaccording to EPRI analyses.

Complicating the drive for more efficientrefrigerators and freezers is the need to findreplacements for the chlorofluorocarbons (CFCS)used as refrigerants and in insulation that offerequivalent or improved performance. Box 4-Cdescribes the ‘‘Golden Carrot’ award program—a contest sponsored by a consortium of electricutilities in cooperation with the U.S. Environ-mental Protection Agency to spur the commer-cialization of more efficient refrigerators.

As with air-conditioning, maintenance prac-tices can affect the efficient operation of refrigera-tors and freezers. Cleaning refrigerator coils twoto three times per year can save about 3 percent ofannual refrigerator electricity use at little or nocost. 28

LIGHTINGAbout 15 percent of household electricity load

is lighting. As in other sectors, use of moreenergy-efficient lighting products can save elec-tricity for residential customers. OTA’s recentreport Building Energy Efficiency estimated thatefficient lighting could cut residential lightingelectricity use by one-third if one-half of allresidential incandescent lights were replaced bycompact fluorescents.29 Assumin g the light isused 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.


Box 4-C-The “Golden Carrot™” and the Quest for a Super-Efficient Refrigerator

In an innovative effort to overcome market barriers that have slowed the commercialization of moreenergy-efficient consumer appliances, 25 U.S. utilities joined to offer a “Golden Carrot™” in the form of a$30-miliion award to the winner of a design competition for an advanced, energy-saving refrigerator that is freeof 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, andothers. Its member utilities provide electric service to more than one quarter of the Nation’s households. The awardwill provide the winning manufacturer with a subsidy of over $100 per refrigerator. In return, the new super-efficientrefrigerator will be delivered in participating utilities’ service areas before it is available to other distributors.

Product Research and

i , - .- -., , .,den Ca

RI MwkelAwdWmw

1

-.

Market

Among the disincentives that the SERP program and possible future “Golden Carrot™” competitions areintended to counter are consumer reluctance to try new products and the higher first cost of more energy-efficientor green products. By offering a subsidy for development of the winning design and guaranteed orders for a sizableinitial manufacturing run, SERP hopes to create a market pull for the energy-saving product, lower productdevelopment risks, and allow the manufacturer to achieve economies of scale in production. This shouldaccelerate 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 by1995.

The competition challenged manufacturers to commit to producing a CFC-free refrigerator at least 25 percentmore efficient than the 1993 Federal energy efficiency standards require and to deliver them to participatingutilities’ 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, incentiverequested, 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)


Box 4-C--The “Golden Carrot™” and the Quest for aSuper-Efficient Refrigerator-(Continued)

The winner announced in June 1993 was Whirlpool Corp., which will deliver about 250,000 SERPrefrigerators in various models between 1994 and 1$97. SERP refrigerator will be priced the same as othermodels with similar features.

EPA estimates that a super-efficient refrigerator has the potential to save 300 to 400 kWh/year over its its lifetimeand 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, July5, 1993, p. 4.

period of 1.7 years for a $20 compact fluorescentbulb.30 Compact fluorescent also last 10 to 13times longer than standard incandescent bulbs.EPRI estimated maximum potential lighting re-lated savings at from 20 to 40 percent in 2000.

Depending on applications, compact fluores-cent bulbs can cut energy use per bulb bytwo-thirds over standard fluorescent. Even stand-ard fluorescent offer energy savings over incan-descent bulbs for equivalent lighting output. Butconsumers often find fluorescent lighting unac-ceptable or unattractive for some purposes. Theextent to which energy-efficient lighting can cutelectricity demand in the residential sector ishighly uncertain and depends on consumer pref-erences and applications. Manufacturers of com-pact fluorescent continue to make progress onadapting these lamps for more common residen-tial fixtures and to improve the quality of lightprovided, which may hasten acceptance by resi-dential customers.

Other options such as lower-wattage “energy-saver’ incandescent, reflector fixtures, tasklighting, dimmers, and automatic lighting con-trols can also shave lighting energy use. Increaseduse of daylighting through windows, skylights,and clerestories can also reduce the need forinterior lighting.

COOKINGElectric ranges and ovens account for 4 percent

of household electricity demand. Newer models,particularly self-cleaning ovens are more efficientthan current stock owing to a number of changes:more insulation, better seals, improved heatingelements and reflective pans, reduced thermalmass, reduced contact resistance, and bettercontrols. The penetration of microwave ovens,convection ovens, and induction cooktops alsooffer energy savings. It is uncertain whethermicrowave ovens, which cook food with one-third the electricity required for standard electricranges and ovens, will actually result in reducedcooking loads as consumers may tend to use themmore as an adjunct to conventional appliances.EPRI estimates that replacement of the 1987stock of ranges and ovens with more efficientmodels could produce savings of 10 to 20 percentin electricity demand for cooking in 2000.

DISHWASHERSDishwashers account for about 2 percent of

household electricity use and are found in 43percent of households. Energy-saving featuressuch as better insulation, water temperatureboosters, water saver cycles, and air drying cyclescan cut electricity consumption. Total savings aredependent on the customers use of energy-saving

~ mid., p. s3. AISO assuming electricity at 7.8 cents/kWIL O kbor ~sts.


cycles. EPRI estimates that improved dishwash-ers could cut dishwasher electricity demand in2000 by 10 to 30 percent over 1987 stock.

OTHER APPLIANCESThe remaining household electric appliances,

such as clothes washers and dryers, televisions,stereos and other electronic equipment, vacuums,small household appliances, power tools, andhome computers account for about 13 percent ofpresent residential electricity use. This portion ofhousehold electricity demand is expected to growwith greater saturation of clothes washers andelectronic equipment. Newer models will be moreenergy efficient, and EPRI estimate, that thistrend is expected to result in electricity consump-tion that is 10 to 20 percent less than equivalent1987 models by 2000.

Estimating net efficiency gains from moreefficient appliances is difficult, however, becauseenergy services are growing, and households mayuse the energy savings to buy larger appliances orincrease the utilization of the equipment.

1 Obstacles to ResidentialEnergy Efficiency

Total residential energy use in 1990 was over1 quad less than it was in 1978, even as thenumber of households grew from 77 million to 94million, reflecting a steady improvement in resi-dential energy efficiency.

31Over this period the

energy intensity of new living space has de-creased and many older units were retrofitted witha variety of energy-saving measures. Major house-hold appliances use significantly less electricityto operate than comparable models of 20 yearsago.

Household electricity use also has grown from24 percent of residential energy use in 1978 to 30percent in 1990, but growth in residential electric-ity demand has been less than it might have beenwithout energy efficiency gains. These gains are

attributable to several factors in addition toevolutionary efficiency gains: higher energy pricesduring the 1970s and early 1980s; energy effi-ciency requirements in building codes; appliancelabeling and efficiency standards; governmentand utility energy education efforts; utility con-servation programs; and more awareness of en-ergy efficiency by consumers, equipment ven-dors, and building professionals and tradespeo-ple.

Even with the admirable gains that have beenmade in energy efficiency since the 1970s, thereremains a sizable gap between the most energy-efficient products on the market to day and theproducts in use in American homes. More effi-cient options exist for almost all of the majorelectricity uses at home. The potential energy andcost savings from residential energy-efficiencyinvestments are significant according to manyefficiency proponents. For many measures theenergy savings over the lifetime of the investmentwould exceed the initial cost, in some casesoffering payback periods of 2 years or less.

If energy efficiency investments are suchattractive investments, why then haven’t theybeen enthusiastically embraced by Americanconsumers? Analysts commonly cite a host ofdisincentives that have tended to dampen the paceand extent of efficiency savings. These include anumber of institutional, economic, behavioral,and practical matters.

OTA’s report Building Energy Efficiency founda confluence of factors resulted in underinvest-ment in residential energy efficiency. Decision-making affecting household energy efficiency isfragmented among: residents (homeowners andrenters); architects; developers; builders; equip-ment manufacturers and vendors; and a host ofFederal, State, and local government agencies.For all of these decisionmakers, energy efficiencyis only one of many attributes considered inmaking 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.


it competes against such characteristics as lowerfirst cost, appearance, convenience, features, andhassle-avoidance. For most decisionmakers, en-ergy efficiency has not been a high priority. In alltoo many instances, residential consumers areeffectively precluded from energy efficiencyopportunities because design and major equip-ment choices are made by others-by architects,builders, and developers for new housing, and bylandlords for the one-third of residential units thatare rented.

Although energy-efficient residences and high-efficiency appliances offer electricity savings andlower life-cycle costs over less efficient versions,these potential cost savings provide only weakfinancial incentives for several reasons.

First, residential electricity prices seem to haveonly a weak influence on energy choices for mostratepayers, and almost no influence on third-partydecisionmakers (developers, builders, equipmentvendors and manufacturers, and landlords andtenants who do not pay monthly electric bills).Residential electricity prices have declined stead-ily in real terms over the past decade. Moreover,residential rates usually do not reflect the highercosts of using electricity at times of peak demand,nor the social and environmental costs (external-ities) of generating electricity.

Future savings from energy-efficiency invest-ments are heavily discounted. Studies have foundthat residential consumers demand a short pay-back period for efficiency investments-2 yearsor less for home appliances, for example.

Many decisionmakers are driven by the desireto keep first-costs low; few pursue the goal ofminimizing life-cycle costs (the sum of capitaland operating costs over the life of the equipment—or e.g., the initial purchase cost of an applianceplus the cost of annual electric bills, maintenanceand repairs), This so-called first-cost bias isespecially strong when energy-efficient equip-

ment costs more and others (home purchasers ortenants) will reap the benefits of lower electricbills. First-cost bias is also strong for low-incomeconsumers who lack either the cash or access tocredit to pay for the more efficient and expensiveequipment.

Reliable, understandable information on en-ergy use and costs is often lacking or hard to use.Consumers that would like to give greater weightto energy efficiency in their decisions—whethermotivated by lower life-cycle costs, environ-mental concern, technological fascination-havefew alternatives. Government and private pro-grams for energy-efficiency ratings of homes andapartments are only just beginning. The effective-ness of federally required labeling for majorappliances is uncertain and has not been ade-quately assessed.32

Energy efficiency is often misperceived asrequiring discomfort or sacrifice, rather than asproviding equivalent services with less energy.The poor popular image of home energy effi-ciency as meaning cold showers, darkrooms, andwarm beers hampers consumer acceptance anddiminishes incentives for housing developers andequipment manufacturers to make efficiency aselling point for their products. Without a marketpull for efficiency, equipment manufacturers andbuilding suppliers give less emphasis to effi-ciency in product design and research.

The typical low turnover rate in the housingstock and slow rate of replacement of majorappliances mean that efficiency improvements inthe residential sector will significantly lag behindtechnical potential. Without aggressive efforts inresponse to government policy and/or an energycrisis, this lagging response will continue.33

From a somewhat different analytical perspec-tive, the Bush Administration also found progressin residential energy efficiency unacceptablyslow. 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 changingby 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.

——


(NES) found that “a number of institutional andmarket barriers’ limited consumer responses tothe higher energy prices of the 1970s and early1980s. Strongly reflecting the economic policyframework of its analysis, the NES concluded that“Our stock of housing and appliances is still farless energy efficient than would be economicallyoptimal.’ ’34 Among the ‘‘significant market bar-riers’ in the residential sector identified by theNES were:

■

✘

■

■

■

■

■

Traditional energy price regulation and rateset-ting that do not reflect the full costs to societyof energy use, thus causing individual consume-rs to undervalue energy-efficiency invest-ments and renewable resources.Failure of market mechanisms to induceadoption of economical energy-saving meas-ures by residential customers, particularly insituations where those who must pay forsuch devices cannot expect any economicbenefits.First-cost bias tendency of buyers (especiallybuilders and homebuyers) to minimizeupfront costs of residential property andmajor appliances.Mortgage lending practices that fail to con-sider the lower total cost of energy-savinghomes in calculating mortgage eligibility.Low incomes of some energy users that oftenmake them unable to finance energy-efficiency improvements no matter what thepayback period is.Absence of credible data on reliability andcost of energy-saving technologies for build-ers, architects, utility programs, mortgagelenders, and individual consumers.Fragmented and cyclical nature of homebuild-ing industry that contributes to a reluctanceto try innovative energy-saving designs,products, and construction techniques and

■

9

9

makes concerted industry-led efficiency ini-tiatives unlikely.Inadequate implementation and enforcementof energy building codes because of lack ofresources to check actual plans and construc-tion sites and to educate builders.Inadequate energy-efficiency investment inpublic sector housing because many localhousing authorities lack funds and manage-ment incentives to improve efficiency.Slow turnover of residential structures andlong lifetimes of heating and cooling sys-tems.

The premise of institutional and market barri-

ers to energy eff ic iency 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 conclu-

sion of market failure, however. They adhere to a

belief that present energy efficiency characteris-

tics represent the informed decisions of knowl-

edgeable consumers who have compared alterna-

tive investment opportunities and selected energy

conservation that offers equal or better returns. 35

As wi l l be seen in the fo l lowing sec t ions ,

Federa l , S ta te , and u t i l i ty programs have a t -

tempted to counter these constraints with varying

degrees of success. Reducing these disincentives

to energy eff ic iency wi l l be key in a t ta in ing

energy efficiency goals.

ENERGY EFFICIENCY OPPORTUNITIESIN THE COMMERCIAL SECTOR

The commercial sector consists of all busi-nesses that are not engaged in transportation orindustrial activity and includes, for example,offices; retail stores; wholesalers; warehouses;hotels; restaurants; religious, social, educationaland 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 andh4ethodologicalIssues (Washington, DC: National Association of Regulatory Utility Commissioners, December 1988),


Figure 4-3--Commerciai Sector On-site EnergyConsumption, by Source, 1990 (quadrillion Btus)

Electtr

15%1

Coal 1 0/0

0.1

Natural gas 420/o2.8

SOURCE: Office of Technology Assessment, 1993, based on datafrom the U.S. Department of Energy, Energy Information Adminlstra-tlon, and the Gas Research Institute.

and local governments. In 1990 the commercialsector accounted for about 14 percent of totalprimary energy use.36 Figure 4-3 shows energyconsumption (excluding electricity conversionand transmission losses) in the commercial sec-tor. Electricity and natural gas each supply about42 percent of commercial sector energy needs,with oil (15 percent) and coal (1 percent) supply-ing the remainder.37

In 1990 the commercial sector consumed about751 billion kWh of electricity at cost of $55billion. 38 Commercial establishments made up

about 28 percent of total electric utility retail salesin 1990. In addition to purchased electricity, agrowing number of commercial facilities haveresorted to cogeneration or self-generation tomeet some or all of their electricity demand; thisoutput is not included in commercial sectorelectricity consumption estimates, but fuels usedto produce this power axe included in overallcommercial energy consumption.39

Figure 4-4 shows commercial electricity use byapplication. Heating, ventilating, and air-conditioning (HVAC) dominates, comprising 37percent of commercial electricity use (spaceheating, percent; cooling, percent; and ventila-tion, percent). Water heating accounts for anadditional 3 percent. Lighting accounts for anestimated 29 percent of commercial load.40 Re-frigeration (7 percent); cooking (2 percent), andmiscellaneous equipment including elevators,escalators, office computers, printers, telephonesystems, and other commercial equipment (21percent). Sixty percent of electricity use incommercial establishments is for nonspace heat-ing purposes. These nonspace conditioning appli-cations are projected to grow faster than commerc-ial square footage to over 65 percent of electricload by 2010.41 The heat generated by rniscellane-ous equipment add to demands for cooling, butlowers space heating loads.

Electricity demand in the commercial sector isdriven by the growth in square footage incommercial buildings and the intensity of servicedemand-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 efficiencyof energy use in the sector, but in part means a shift of primary energy eonsum ption 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.


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 commer-

cial square footage and electricity use each grew

b y 4 5 p e r c e n t .43 E v e n s o , n e w e r c o m m e r c i a 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 electric-

ity demand.

Commercia l bui ld ing energy in tens i ty ( i .e . ,

energy use per square foot) has remained flat for

t h e p a s t t w o d e c a d e s , e v e n a s d e m a n d f o r

air-conditioning, computers and other equipment

grew. Compl ica t ing th is t rend 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 commerc-

ial 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 eadded this decade. There is great diversity in the

size and energy using characteristics of these

commercial buildings. Smaller commercial build-

ing energy systems are similar to those in houses

and small apartment buildings. Larger buildings,

h o w e v e r , h a v e c o m p l e x H V A C s y s t e m s a n d

act iv i t ies ins ide the bui ld ing- l ight ing , occu-

pancy, 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 ElectricityUse by Application, 1987

Ventilation9Y0

Heating

v

i9%

Refrigeration

7 Wate

,/’

/’Off Ice equip7%

—..Cooking

2%

r heating30/0

ment andmiscellaneous

21 “/0

SOURCE: Office of Technology Assessment, 1993, based on datafrom the Electric Power Research Institute and U.S. Department ofEnergy.

almost 80 percent of building square footage andoffer many opportunities for electricity savings.

9 Energy Efficiency Technologies for theCommercial Sector

Space-conditioning, lighting, and building shellweatherization are primary targets for improvingenergy efficiency and saving electricity in thecommercial sector. In addition, large commercialbuildings are suitable targets for utility loadmanagement programs designed to shift energyuse away from peak hours, but not necessarilyresulting in lower overall energy demand, throughinstallation of technologies such as storage heat-ing and cooling systems. There are also potentialenergy 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”stics1989,


Table 4-3-Selected Energy Efficiency Technology Options for the Commercial Sector

Heating, ventilation, and alr-condltlonlng (HVAC) systemsBuilding envelope efficiency improvements~ Weatherstripping and caulking■ Insulation~ Storm windows and doors■ Window treatments

Space heatingimproved 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 coolingMore efficient cooling systemsCool storage systemsDistrict cooling systems

Vent//at/onAir distribution systemsD Improved insulation■ Reduced duct and damper leakage= Separate make up airflows for cooling exhaust systems■ Economizer controls

Improved HVAC maintenance

Integrated HVAC systems

WaterheatIngBlanket wrap for water tanksCommercial heat pump water heatersIntegrated heating and hot water systemsHeat recovery water heat systemsIncreased insulation of tanks and pipesFlow restrictorsService/point of use water heaters

Commercial lightingDelampingLighting fixture retrofitsElectronic ballasts for fluorescentHigh-effidency lampsReflectorsIncreased use of daylightingHigh-intermit y lighting applicationsIncreased use of task lightingCompact fluorescent(LED) signsLighting control systems: timers, occupancy sensors,

photocells, dimmers

Commercial refrigerators and freezersEfficient motors and controlsImproved insulation and seals

Commercial cookingEnergy+efficient commercial electric ranges, stoves, fryers,

ovens and broilersMicrowave cookingConvection cookingInduction cooking

Miscellaneous electrical equipment and office machinesMore efficient motors and drives for elevators, escalators,

and other building systemsImproved hardware and software for office equipmentIntegrated building energy management and control

systems


Analysis of potential efficiency opportunitiesby EPRI found that commercially available elec-tric equipment could reduce commercial electric-ity in year 2000 by 22 to 49 percent from whatconsumption would be without the use of thesetechnologies if efficiency were frozen at 1987levels. Commercial applications with the mostsignificant savings potential in the EPRI analysis

were lighting, cooling, and miscellaneous electricequipment.

IMPROVEMENTS IN COMMERCIAL BUILDINGEFFICIENCY

Turnover of commercial building space is morerapid than residential, but it is evident that a largeportion of commercial space in use for the nextfew 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 hasalready been built, and 80 percent of the existingstock of commercial buildings will still be in usefor the next 30 years.45

The pace of new commercial constructionprovides opportunities for efficiency gains in bothbuilding shell, equipment, and appliances. Meas-ures to increase the efficiency of commercialbuildings include improved design, siting, andconstruction techniques, better insulation, andmore efficient equipment choices.

The remodeling and rehabilitation of commer-cial space offers additional opportunities. There isconsiderable potential for energy-efficiency im-provements in existing commercial buildings.According to DOE surveys, while 84 percent ofbuildings are reported to have installed buildingshell conservation features, there remains a con-siderable pool of buildings that have not installedbasic measures. The most frequently reportedmeasure is ceiling insulation, 67.5 percent, weath-erstripping or caulking, 61 percent, and wallinsulation, 47 percent. Storm windows and multiple-glazing were reported in 32 percent of buildings,and shades and awnings and reflective shadingglass or films were reported for 21 percent ofbuildings.%

HEATING, VENTILATION, AND AIR-CONDITIONINGSpace Heating. Just under one-quarter of

commercial buildings rely on electric heatingsystems. 47 Most of these buildings are located inthe South and West.

Installation of more efficient electric heatingequipment, such as heat pumps instead of resis-tance heat, coupled with a combination of meas-ures such as building shell improvements, win-dow treatments, heat recovery, and improvedmaintenance practices can cut electricity demand

for space heating. Further savings are possiblewith integrated heat pump systems that provideheating, cooling and water heating. These poten-tial savings are offset by the expected increase inheating load attributable to reduced internalheating gains from installation of energy-efficientlighting measures. Use of the best availableenergy efficiency measures could reduce spaceheating electricity demand in 2000 by 20 to 30percent from what would be required from the1987 stock of commercial buildings and equip-ment, according to EPRI.

District heat, in which a central plant providesheat, and often hot water for all buildings withina complex or downtown area, also offers effi-ciency opportunities, particularly if coupled withcogeneration. 48

Cooling. Commercial cooling loads are thebiggest component of summer peak load for mostutility systems. Over 70 percent of commercialbuildings have cooling systems and 96 percent ofthese systems are electric. Common commercialcooling equipment includes packaged coolingsystem, individual air-conditioners, central chill-ers, and heat pumps. Often these systems areintegrated with the building ventilation and airtransport systems. Commercial cooling load isdriven by building size, external temperature, andinternal heat gains from electric and other equip-ment and occupants. Over 6 percent of commer-cial buildings maintain separate cooling systemsfor computer areas.49

Energy-efficient cooling options for commer-cial buildings include more efficient air-conditioners, heat pumps, high-efficiency chill-ers, chiller capacity modulation and downsizing,window treatments, radiant barriers, energy man-agement control systems, and improved operationand 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.


from installing efficient lighting systems also cutscooling load. Excluding lighting-related savings,EPRI estimated that cooling requirements can bereduced by 30 percent or more in commercialbuildings. Including lighting efficiency packageswith cooling system improvements could providetotal savings of over 80 percent according to EPRIestimates. However, the need to find replace-ments for CFCS now used in cooling systemscould result in newer cooling technologies thatmay reduce some possible efficiency gains. EPRItherefore estimates maximum potential electricitysavings in commercial space cooling in 2000 tobe from 30 to 70 percent over 1987 performancelevels. 50

Another energy efficiency strategy for com-mercial cooling that may not always result in a netreduction in electricity demand is the use of coolstorage systems that shift all or part of a build-ings’ air-conditioning electricity demand frompeak to off-peak hours. Typically, ice or chilledwater is produced in a refrigeration system atnight and used to meet some or all of the nextday’s air-conditioning needs. Cool storage sys-tems offer financial savings for customersthrough lower off-peak rates and peak reductionfor utilities.51

Ventilation. Air transport and ventilation sys-tems are a critical component of modern largecommercial buildings. Improving the energyefficiency of ventilation and air transport systemscan be attained through a variety of measures:viable air volume systems; low-fiction air distri-bution designs; high-efficiency electric motors;variable speed drives; heating, cooling, and light-ing improvements; and improved operation andmaintenance practices. EPRI estimates that venti-lation electricity use can be reduced by 30 to 50percent through a comprehensive package ofmeasures.

Compact fluorescents, which use 75 percent lessenergy than standard incandescent lamps, areavailable in a variety of designs.

LIGHTING

About 29 percent of commercial electricityconsumption is for lighting. Commercial lightingrequirements are met with a combination ofincandescent, fluorescent, and high-intensity dis-charge lamps and most commercial buildingshave a mixture of these fixtures. Fluorescentlamps are already extensively used in the com-mercial sector. About 78 percent of commercialfloorspace is lit with fluorescent and high-efficiency ballasts have been installed in about 40percent of this space.52

A range of cost-effective technologies is avail-able to cut lighting loads. Ready savings can beachieved in many commercial buildings by del-amping to lower lighting levels, using lowerwattage fluorescent, and replacing incandescentwith more efficient fluorescent or compact fluo-rescent lamps where appropriate. More advancedlighting system efficiency upgrades include in-stallation of high-efficiency electronic ballasts,aluminum and silver film reflectors, daylightdimming, 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.


pressure sodium lamps instead of mercury vaporlamps in high-intensity discharge fixtures. In newconstruction and remodeling, better lighting sys-tem design and greater use of daylighting can alsocut lighting requirements.

Estimates of lighting savings involve interac-tions among package components and are notnecessarily the sum total of individual measures.Building characteristics also influence potentialsavings. In addition lighting upgrades can cutcooling costs by reducing internal heat gain, butadd to heating loads. EPRI estimates potentialelectricity savings from more efficient commer-cial lighting in 2000 to range from 30 to 60percent over 1987 stock.53

COMMERCIAL REFRIGERATION SYSTEMSCommercial refrigeration in retail stores, res-

taurants, 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. EPRIestimates that commercial refrigeration electric-ity use can be cut by 20 to 40 percent from 1987performance levels by combining a variety ofefficiency improvements. Examples include: moreefficient fan motors and compressors, multiplexunequal parallel compressors, advanced compres-sor cycles, variable speed controls, evaporativelycooled condensers, floating head pressure sys-tems, air barriers, food case enclosures, electroniccontrols, and improved maintenance practices.Electricity savings are highly site specific anddepend on previous saturation of these technolo-gies.

WATER HEATINGAbout 48 percent of commercial buildings with

hot water systems54 use electricity as the sole orsupplemental water heat source. Hot water heat-

Electronic ballasts can cut fluorescent lighting energyuse by 20 to 25 percent.

ing accounts for about 3 percent of commercialelectricity use.

There are a number of efficiency measures forcommercial hot water systems on the market.These measures include many also used inresidential applications, such as water heaterwraps, low flow devices, hot water pipe insula-tion, and installation of valves that reduce con-vection loses. Commercial heat-pump water heat-ers and heat recovery systems can provide energysavings of one-third or more over conventionalresistance systems. Integrated heat pumps canprovide heating, cooling, and hot water forcommercial buildings. Lowering the hot waterthermostat can reduce electricity use while stillproviding adequate water temperatures for mostuses. EPRI estimates potential savings in waterheating electricity use in 2000 of 40 to 60 percentover 1987 stock.55

COOKINGCommercial cooking equipment accounts for

about 2 percent of commercial sector electricityuse. Microwaves, convection ovens, and mag-

S3 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.


netic induction cooktops can cook food with lesstime and energy than more conventional electricstoves and ovens and are seeing greater use incommercial establishments. A range of techno-logical improvements are available to cut electric-ity use in commercial ranges, ovens, broilers,griddles, and fryers. Examples include: increasedinsulation, better heating elements, more precisetemperature controls, reflective pans, reducedthermal mass, and less contact resistance. EPRIestimates that by incorporating a combination ofefficiency measures, electricity use by commer-cial electric stoves and ovens in 2000 could befrom 20 to 30 percent less than that required for1987 stock.56

MISCELLANEOUS COMMERCIAL SYSTEMSAND EQUIPMENT

Residual electric systems and equipment (e.g.elevators, escalators, telephone systems, officemachines, food preparation and other equipment)account for 21 percent of commercial sectorelectricity use and will continue to grow.

EPRI estimates that overall savings from ex-pected efficiency advances in miscellaneous com-mercial sector equipment will range from 10 to 30percent. Expected improvements in hardware,software, and system operations could offermaximum potential savings of up to 50 percentfor office equipment in 2000. EPRI also calcu-lates maximum potential savings of up to 35percent in 2000 from the use of high-efficiencymotors and adjustable-speed drives in elevatorsand escalators.57

The Federal Government, through the Environ-mental Protection Agency’s green programs andFederal procurement policies, is seeking to over-come some of the market barriers to moreenergy-efficient computer equipment. (See box4-D.)

I Barriers to Energy Efficiency in theCommercial Sector

There remains a significant gap between theelectricity-using characteristics of the presentstock of commercial buildings and equipment andthe energy-saving potential of the most efficientbuildings and equipment marketed today. As withthe residential sector, many economic, institu-tional, and behavior influences hamper greatercommercial sector investment in energy effi-ciency.

Some influences are shared with other sectors.The normally slow turnover in commercial build-ings and major equipment, albeit more rapid thanin the residential sector, means that actual effi-ciency savings lag considerably behind technicalpotential. Relatively low energy prices that do notreflect all societal and environmental costs ofenergy production and use also lead to undervalu-ing of energy and underinvestment in efficiencyby commercial consumers. (This persists eventhough commercial customers are in general moreprice-sensitive than residential customers, andutility bills for commercial establishments can bequite large.) Choices affecting commercial en-ergy demand are made by a large number ofdecisionmakers — architects, designers, develop-ers, building owners, tenants, equipment manuf-acturers and vendors, and local building authori-ties. The plethora of decisionmakers and theabsence of any direct economic benefit in effi-ciency for many of them lessens the impact ofexisting weak financial incentives and fragrnentsthe potential constituency for efficiency improve-ments.

Several factors contribute to limited financialincentives to invest in efficiency. Energy costs ofbuildings can often be a small fraction of totalbusiness expenses and thus gain little manage-ment 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 costsper 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 ofcommercial 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 energyefficiency, unlike portable or laptop models that incorporate a number of energy-saving measures to save batterypower. if desktops were equipped with technologies that allowed them to “nap” or shutdown when not in use andreturn quickly to full power capability when needed, EPA estimated that such computers could save 50 percentof the energy used to run them. Green computers thus became one of the first commercial consumer productstargeted by EPA’s pollution prevention programs to increase consumer and manufacturer awareness of energyefficiency 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 withmanufacturers of computers, peripherals, and microprocessors. Manufacturers agree to produce products thatmeet certain efficiency improvements and sign a mernorandum of understanding with EPA. The manufactures arethen eligible to use the “Energy Star™-EPA Pollution Preventer” logo in themarketing and displaying of the prod-ucts. For example, personal computerswith the capability of switching to a lowpower mode of 30 watts or less (about75 percent less than current models)qualify for the EPA logo that identifiesnew high efficiency equipment. EPA isexpanding the use of such voluntaryagreements for related computer prod-ucts including printers, monitors andother pieces of office equipment.

By May 1993 EPA had reachedagreement with an impressive array ofcompanies producing personal com-puters and related products. Charterpartners in EPA’s Energy Star™ com-puter program represent 60 percent of

Energy Star Computers could save enough electricity eachyear to power Vermont and New Hampshire, cut electricitybills by $1 billion, and reduce CO2 pollution equivalent toemissions from 2.5 million autos.

the U.S. market for computers and monitors, and 60 percent of the laser printer market. An Energy Star™ alliesprogram 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 technologiesinto 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 toconsumers, the economy, and the environment. The cost of operating a typical 150-watt personal computer 24hours 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 433kWh/year. Using technology that conserves power when the machine is not active during the day could cut coststo $1 7/year for 216 kWh/year. EPA estimates that green computers could save a total off $1.5 to $2 billion in annualelectricity bills and avoid emissions of 20 million tons of carbon dioxide, 140,000 tons of sulfur dioxide, and 75,000tons 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 StarComputers: The Next Generation of Office Equipment,” in American Council for an Energy-Efficient Economy, ACEEE 1992 Surnmer Studyon 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


Energy efficiency is only one consideration indecisions affecting energy use--first-cost, ap-pearance, comfort, and other performance fea-tures may overshadow potential lifecycle costsavings from efficiency. Building owners andtenants tend to place greater emphasis on occu-pant comfort and productivity and may be reluc-tant to make any changes that might affectbuilding operations. One-quarter of commercialspace is leased and lower energy bills offer noincentives for building landlords when the tenantsare responsible for paying electric bills. Wherelandlords pay utility bills and energy prices areincluded in rent, building occupants may havelittle financial incentive to choose high-efficiencyequipment or to invest in energy-savings mainte-nance.59

When efficiency investments are considered,commercial sector decisionmakers also tend torequire short payback periods of 1 to 3 years. Lackof resources or access to capital can discouragesome possible commercial sector efficiency in-vestments, particularly for nonprofit institutionsand small businesses. Cost-effective, low-riskmeasures that could cut operating costs are oftengiven low priority in government facility manage-ment. Even when government facility managersare aware of potential savings, budgetary andprocurement constraints limit investments inefficiency for government owned or occupiedfacilities. 60

The energy efficiency industry is still in itsinfancy and the small pool of trained vendors,installers, and auditors available to serve com-mercial establishments and utility programs canlimit achievable energy savings at least in theshort term. The relative newness of the industryand absence of a proven track record of deliveringsavings may make many in the commercial sectorreluctant to make significant investments in

energy efficiency. Indeed, savings from earlybuilding retrofit investments have been less thanexpected on average, and unpredictable for indi-vidual buildings, adding to the perceived riski-ness of the investment.61

Nevertheless, the commercial sector remains aprime and potentially profitable target for utility,private sector and government efforts at improv-ing energy efficiency.

ENERGY EFFICIENCY OPPORTUNITIESIN THE INDUSTRIAL SECTOR

The industrial sector includes both manufactur-ing enterprises (i.e., businesses that convert rawmaterials into intermediate or finished products)and nonmanufacturing enterprises, such as agri-culture, forestry, fishing, construction, mining,and oil and gas production. The industrial sectoris characterized by the diversity of energy uses,equipment, and processes and is the largestenergy sector, consuming 37 percent of U.S. totalprimary energy use in 1990. Patterns of industrialenergy use are further complicated by the use ofoil, gas, and coal as feedstocks and for cogenera-tion. Figure 4-5 shows industrial energy use forfuel and power only.

Industrial energy use is variable, reflectingeconomic conditions, structural changes, inter-fuel competition, and rate of investment. Patternsof industrial energy use and energy intensity ofindustry also vary significantly by region. Price isthe major determinant in most industrial energychoices, and head-to-head competition amongfossil fuels is intense. Price however is not thesole consideration—availability, reliability, andquality also drive industrial energy decisions.Another trend is the growth in industrial cogener-ation, which is generally viewed as a positivedevelopment for efficiency, but, which in effecttransfers 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.


sector and utilities. Moreover there has been ageneral trend toward electrifying many processtechnologies and a shift in energy and electricintensity of manufacturing. The relationship ofefficiency gains and structural changes in U.S.industry was examined in detail in an OTAbackground paper, Energy Use and the U.S.Economy.

62 A companion new OTA report,

Industrial Energy Efficiency, was published insummer 1993.

There are five major fuel and power demandsin the industrial sector: process steam and powergeneration (36 percent), process heat (29 percent),machine drive (14 percent), electrical services(4percent), and other (including off-highway trans-portation, lease and plant fuel use, and mining)(16 percent).63 The industrial sector derives 40percent of its fuel and power needs from naturalgas, 25 percent from oil, 15 percent from pur-chased electricity, 9 percent from coal, and theremaining 9 percent from waste fuels and othersources. Electricity competes with other fuels,particularly natural gas, for direct heat applica-tions. 64 For other uses, purchased electricitycompetes with the options of self-generation orcogeneration. It is estimated that in 1989, theindustrial sector produced about 153,270 gigawatt-hours of electricity on-site. Surplus electricityproduction was sold to local utilities.65 To avoiddoublecounting, fuel used for industrial self-generation or cogeneration is usually attributed toprimary fuels.

In 1990 industrial consumers purchased 946billion kWh from electric utilities at a cost of $45billion.66 Sales to industrial users accounted for35 percent of electric utility revenues from salesto end-users/ultimate customers. Electricity con-sumption in the industrial sector is divided among

Figure 4-5--industrial Energy Use for Fuel andPower, 1989 (quadrillion Btus)

Natural gas 39%

Ott

14%\ / 2.8

Electricity 160/!3.1

SOURCES: Office of Technology Assessment, 1993, based on datafrom the Gas Research Institute.

the manufacturing enterprises (87 percent); agri-culture (5 percent) and construction and mining (8percent).

The major industrial electricity uses are motordrive, electrolytic, process heat, and lighting (seefigure 4-6). Table 4-4summarizes EPRI estimatesof 1987 industrial energy consumption for theseapplications by industrial subsectors (SIC codes),manufacturing loads and nonmanufacturing loads.

The most electricity-intensive manufacturingactivities (including on-site generation) are chem-ical products, primary metals, pulp and paper,food, and petroleum refining, together accountingfor more than half of manufacturing electricityuse. 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.


$ $ ~0 0 0 0 0 0 0 0 0 0 0 0 0 lqb.~0 0 0 0 0 0 0 0 0 0 0 0 0 -old

F m

0 0 0 0 0 0 0 0 0 0 0 0 0

$!Too0)00

OIm 9 ) 0 0m- 8

*-s!

Ea)ut)n

$!l-oomooqqqooo(&ooc&ooor-ooo

$ $0 0 0 00 0 0 0

0 0 0 0

08

Eo&

10za-0

. . . . . . . . . . . .. . . . . . . . . . . .. . . . . . . . . . . .,... . ..+. . . . .. . . . . .. . . . . !. . . . .[”

. . . . ..-. . :

. . . . :-L.L. . . . ., . ..: . x-

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

. “ .

. “ .

. . .

. . .

. “ .

. . .

. . .

. . .

. . .

.’.

. “ .

. . .

. .

I


subsectors have significant cogeneration capa-city-mostly freed by waste fuels.

Figure 4-8-industrial Electricity Useby Application, 1987

9 Efficient Industrial TechnologiesThere are several strategies for improving

energy efficiency in the industrial sector, includ-ing making existing electricity applications moreefficient, shifting industrial processes from fossilfuel to electrotechnologies for net energy savings,and using more industrial cogeneration for netenergy savings over purchased electricity.

EPRI estimates that application of more effi-cient industrial equipment and processes offerspotential savings of from 24 to 38 percent of theirprojected base-case electricity use in 2000.67 Themost promising targets for potential efficiencygains are high efficiency electric motors andvariable speed drives, improved electrolytic proc-esses, industrial process waste heat recovery, andmore efficient lighting technologies. (See table4-5.) All but electrolytic technologies have a wideand diverse range of potential applications acrossthe industrial sector.

ENERGY-EFFICIENT ELECTRICMOTORS AND DRIVES

There is great diversity in industrial applica-tions of electric motors and drives: pumps, fans,compressors, conveyors, machine tools, and otherindustrial equipment. Motor drive end-uses ac-count for an estimated 70 percent of electricityload inmotors(ASDS)tential.

manufacturing. High-efficiency electriccombined with adjustable-speed drivesoffer significant electricity savings po-

ctrolytlcs12%

I -/0 Lighting Process heat10“/0 10“/0

SOURCE: Office of Technology Assessment,from the Electric Power Research Institute.

Electric motors are available

1993, based on data

in standard andhigh-efficiency models and energy efficiency ofboth vary according to size. In general, largermotors are more efficient than smaller ones inboth standard and high efficiency models. Thehigh-efficiency models cost from 10 to 30 percentmore than the standard versions,68 but haveefficiency increases of 8 percent for smallermotors and 3 percent for larger motors.69 Energy-efficient motors typically have longer operatinglife than standard motors. The initial capital costsof electric motors are usually only a fraction oftheir operating costs. For example, annual energycosts for an electric motor might run as much as10 times its initial capital cost; increasing itsefficiency 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 StateEnergy Resmch and Development Authority, November 1990), p. 48.

@ EPRI, DL5’M Technology Alternatives, supra note 26, P. e~l.


Table 4-5-Selected Energy Efficiency TechnologyOptions 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 processingChlor-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 LightingDelampingLighting fixture retrofitsElectronic ballasts for fluorescentsHigh-efficiency lampsReflectorsIncreased use of daylightingHigh-intensity lighting applicationsincreased use of task lightingCompact fluorescentsLED signsLighting control systems-timers, occupancy sensors,

photocells, dimmers

industrial eiectro-technologiesPlasma processingElectric arc furnacesInduction heatingindustrial process heat pumpsFreeze separationUltraviolet processing/curing

industrial cogeneration systemsHigh-efficiency industrial boilersIntegrated process heat/steam and power production


savings of 50 to 60 percent of its capital costs ina single year.70

Many industrial motors are often run at lessthan maximum power because of varying loads.

Electronic adjustable speed drives allows anelectric motor to operate at reduced speed whenmaximum power is not needed, saving energy.ASDS are appropriate in applications with highoperating hours where motors are often operatedat less than full load.

There are three targets for displacing standard-efficiency motors with high-efficiency motors:selecting new or replacement motors, rewindingof existing motors, and retrofitting of existingmotors that do not need repair or replacement.

High-efficiency variable-speed motors offertremendous potential for efficiency. Various stud-ies have yielded estimates of potential savings of20 to 50 percent depending on circumstances forapplication of ASDS. Use of high-efficiencyelectric motors can provide savings of an addi-tional 3 to 10 percent. Overall efficiency improvem-ents in motor drive of 35 to 50 percent over1987 equipment were assumed in EPRI’s analy -sis.71 Motor drive improvements offered nearly80 percent of estimated savings in their analysis,with over 90 percent of these savings in just a fewindustry categories.

WASTE HEAT RECOVERYWaste heat recovery systems improve energy

efficiency by using heat from fuel combustion orexcess thermal energy from a process steamproduct. An estimated one quarter to one-half ofthe process heat used by industry is discharged ashot gases or liquids.72 There are various ap-proaches to capturing energy from these sourcesof waste heat. The choice depends on characteris-tics of the heat source, process needs, andeconomics. Heat exchangers are used to transferheat from a high-temperature waste exhaustsource, such as combustion gases, to a coolersupply stream such as steam for lower tempera-ture 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 PrintiwOffIce, 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

c a n be u p g r a d e d t o s u p p l y h e a t f o r h i g h e 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 overal l 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 construc-

tion or modernization projects and most applica-

tions have been custom designed. Heat recovery

devices d isp lace convent ional 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 as-

sumed an average of 10 to 15 percent savings.

ELECTROLYSIS

An estimated 12 percent of industrial electric-

ity 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 pri-

mary metals processing industry and the produc-

tion of chlorine and caustic soda from salt brines

in the chemical products industry.

Electr ic i ty is the most cost ly mater ia l in

aluminum production. In the century-old Hall-

Heroult 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 carbonlined steel cells or pots, In each pot a direct

current is passed from an carbon anode suspendedin the cell through the bath to the carbon lining ofthe cell producing a chemical reaction. Moltenaluminum is siphoned from the bottom of the potsand is then formed into aluminum ingots orfurther refined and/or alloyed into fabricatingingot. A single potline can consist of from 50 to200 cells with a total voltage of 1,000 volts atcurrents of 50,000 to 250,000 amperes. U.S.smelters use from 6 to 8 kWh to produce eachpound of aluminum.

The efficiency of aluminum production hasimproved steadily. Following World War II about12 kWh of electricity was needed to produce onepound of aluminum; today, through greater econ-omies of scale and process controls, the mostefficient smelters use half that electricity perpound.74 Further efficiency gains are promised byadvanced electrolytic reduction methods includ-ing bipolar cells, inert anodes, and wettablecathodes. None of these technologies, however iscurrently installed, but EPRI estimates that theycould potentially yield efficiency savings by year2000 of some 30 to 50 percent over currentmethods. These improvements are highly attrac-tive given the high electric intensity of aluminumproduction and are significant for regions wheresuch production is concentrated, such as thePacific Northwest.

Chlor-alkali production is second to aluminumin terms of electricity consumption and usesabout 30 percent of electric power used forelectrochemical production .75 Chlorine and caus-tic soda (sodium hydroxide) are produced fromsalt brine by electrolysis in either the diaphragmor mercury cell. Mercury cells account for about20 percent of U.S. capacity. Throughout thiscentury economies of scale have produced steadyefficiency gains in chlor-alkali production asnewer 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.


drive the chemical reactions.76 In the membranecell, different constituents of the solution areseparated by selective diffusion through themembranes. EPRI analyses estimated that use ofmembrane cells to replace diaphragm cells couldsave 10 percent of electricity used in chlor-alkaliproduction. Other analyses have estimated sav-ings of up to 25 percent over current methods.

Adaptation and improvement of electrolyticseparation methods, including electrodialysis whichuses electric current to accelerate membraneseparation, for other inorganic and organic proc-esses also can yield efficiency gains over conven-tional methods.

LIGHTINGLighting accounts for about 10 percent of

electricity use in the industrial sector. As in thecommercial and residential sectors, more efficientlighting technologies offer promises of electricitysavings across the industrial sector too, Industriallighting efficiency upgrades such as delamping,reduced wattage fluorescent, high-efficiency bal-lasts, reflective fixtures, occupancy sensors, re-placing incandescent lamps with compact fluo-rescent, and greater use of daylighting. EPRIanalyses estimate that lighting efficiency pack-ages offer savings of from 36 to 49 percent.Lighting upgrades can also lower cooling loads,but increase heating loads.

ELECTRIFICATION OF INDUSTRIAL PROCESSESElectrification offers the potential for net

savings in fossil fuel use even as it increaseselectricity demand in the industrial sector. Therehas been a continuing trend toward electrificationof many industrial processes and end-uses. Costhas been a major factor, but increasingly, reliabil-ity, flexibility, and reduced environmental im-pacts on-site have made electrification an attrac-tive option for improving industrial productivity.There are a variety of electrotechnologies that

could boost industrial electricity use over the nextseveral decades, while providing net savings infossil fuel consumption. EPRI looked at thepossible net energy savings from five suchtechnologies.

Freeze concentration uses refrigeration proc-esses to separate and concentrate constituentsfrom mixed dilute streams. Separation of constit-uents from process streams is a major energy usein the industrial sector and many techniques suchas distillation rely on high temperatures producedby burning fossil fuels. It takes less energy (about150 Btu) to freeze a pound of water than the 1,000Btu needed to boil it.77 Shifting to freeze separa-tion could cut overall energy consumption anddisplace industrial fossil fuel use. More energy-efficient refrigeration technologies add to theattractiveness of freeze concentration as an alter-native separation technique. Currently used fortreating hazardous wastes, concentrating fruitjuices, and purifying organic chemicals, thetechnique is being investigated for broader indus-trial application.

Industrial process heat pumps can replaceindirect resistance heating for certain low temper-ature applications (below 280 to 3000 F) inlumber, pulp and paper, food, chemical, andpetroleum subsectors.

Electric arc furnaces allow direct melting ofraw steel and uses less energy than fossil-freedfurnaces. Electric arc furnaces have alreadygained a significant foothold in the steel industryaccounting for an estimated 34 percent of steelproduced in 1985. Continuation of this trend to 56percent or more by 2000 was projected. Electricarc furnace foundries are also used to producesteel castings and increased use of this technologyalso promises net fossil fuel savings.

Plasma processing uses a high intensity elec-tric arc to generate ionized gases at temperaturesup 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.


2,800 0 F practical limit for fossil fuel combus-tion.78 The technology offers high energy densityand temperature capability, controllability, andfuel flexibility compared with conventional com-bustion technologies. Plasma processing can beexpanded in already established uses for cutting,welding, heat treating, and burning and intopromising new applications in electric arc furnacedust processing, cupola refits with plasma torches,ferroalloy production, and ore reduction. Use forchemical production also is said to have futurecommercial potential.

Ultraviolet curing uses ultraviolet radiationproduced by ionizing gases in an electrical arc ordischarge, such as in a high-pressure mercuryvapor lamp, to change the molecular structure ofa coating to make it a solid. UV curing offers largeenergy and cost savings compared with thermalcuring and is expected to gain increasing marketpenetration especially in quickcuring applica-tions. An additional and significant environ-mental and health benefit is the elimination ofsolvents in the curing process.

Potential Savings. EPRI estimates that allthese technologies offer strategic load growth toelectric utilities, while resulting in net savings infossil fuel use overall. Maximum application ofthese technologies could add 319 trillion Btu offossil fuel in electric utility generation, but at thesame time yield a net savings of 290 trillion Btusin these industrial processes.

COGENERATIONCogeneration is the simultaneous or sequential

production of both electrical or mechanical powerand thermal energy from a single energy source.79

On-site industrial cogeneration has grown signifi-cantly since the late 1970s as a result of higherenergy prices, volatile energy prices, and uncer-tainty over energy supplies. Implementation ofthe Public Utility Regulatory Policies Act of 1978(PURPA), which required electric utilities to

provide interconnections and backup power forqualifying cogeneration facilities and to purchasetheir excess power at the utilities’ avoided cost,reduced institutional barriers to the expansion ofcogeneration. PURPA was intended to promoteindustrial cogeneration as a means of improvingefficiency especially in the use of premium fossilfuels (gas and oil) and encouraging the use ofwaste fuels.

In most industrial cogeneration systems, fuel isburned frost to produce steam that is then used toproduce mechanical energy at the turbine shaft orto turn the shaft of a generator to produceelectricity. The steam leaving the turbine is thenused to provide process heat or drive machinesthroughout the host industrial plant and relatedfacilities. From an energy policy perspective, theattraction of cogeneration is the ability to improvefuel efficiency. Cogeneration systems achieveoverall fuel efficiencies 10 to 30 percent higherthan if power and heat were provided by separateconventional energy conversion systems, i.e., lessenergy than if the fossil fuel were burned in anindustrial boiler to provide process heat and at anoff-site utility power plant to generate electricityto be transmitted to the industrial site. (Thisaspect of cogeneration efficiency depends on thefuel that is burned to produce electricity) Cogen-eration can also be attractive as a means ofquickly adding electric generating capacity atsites where thermal energy is already beingproduced.

Industrial cogeneration is concentrated in thepulp and paper, chemicals, steel, and petroleumrefining industries. Often the industrial cogenera-tors can take advantage of waste fuels to fire theirboilers for heat and power. Natural gas has beenthe fuel of choice for many qualifying cogenera-tion plants under PURPA.

Cogeneration does not always provide signifi-cant efficiency advantages, however. Almost theentire 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.


gas-fired cogeneration systems is electric powergeneration with little steam for process applica-tions. In this case, there is a much smallerefficiency gain from cogeneration and a net shiftin primary fuel demand from the utility sector tothe industrial sector. Thermal conversion lossesin electric utility and industrial combined cyclegenerating units are similar, there are some smallsavings in avoided transmission and distributionlosses. If a significant portion of the cogeneratedpower is sold to the local electric utility, thesetransmission and distribution gains would largelydisappear.

Industrial cogeneration makes up the over-whelming bulk of the explosive growth of socalled independent power producers in the pastdecade. While cogeneration was initially viewedby many utilities as a threat to their market share.It is increasingly accepted as an alternative powersource and has been integrated into some utilitiesload management and resource plans. In fact anumber of utility companies have independentpower subsidiaries or affiliates that are partners inindustrial cogeneration projects.

In 1989, Edison Electric Institute estimatedthat cogeneration accounted for about 73 percentof the operating capacity of nonutility powerplants. 80

Industrial cogeneration plants will benefit frommany of the same efficiency improvements asutility generation as many use the identicaltechnologies. In addition, better integration ofindustrial cogeneration and utility system opera-tions through planning and dispatch offers netimprovements to system efficiencies.

1 Constraints onIndustrial Sector

There have been

Efficiency Gains in the

significant energy efficiencygains in the industrial sector over the past twodecades. Industrial energy use per unit of output(energy intensity) has been declining since 1970.At the same time, more and more industrialprocesses have been electrified. Even so, OTAfound that opportunities for further gains inenergy efficiency have by no means been ex-hausted. 81

The industrial sector faces some of the sameconstraints as other sectors: low energy prices,failure of energy prices to reflect societal andenvironmental costs, multiplicity of decision-makers, and reluctance to adopt unproven newtechnologies. Energy efficiency choices tend tobe made in new investments and when equipmentmust be repaired or replaced which creates anormal lag time between the development of newelectricity-saving technologies and their disper-sion throughout industry. But certain barriers areless applicable-for example, the disconnectbetween those who pay for energy-efficient im-provements and those who benefit is rarelypresent. Of all sectors, the industrial sector isprobably the most responsive to price signals, sothat the argument that there are market failuresresulting in an underinvestment in energy effi-ciency here (from the perspective of myriadindustrial consumers) is hardest to make. Never-theless, certain characteristics of industrial deci-sionmaking about energy choices can result inlower adoption rates for energy-efficient equip-ment than might be desirable from a societal orutility 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 reportIndu.rm”alEnergy Eflciency, to be published in summer 1993. Other OTA reports include IndWrialEnergy Use (1983), supra note 70, EnergyTechnology 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 InformationService, NTIS Order #PB83-180457.)


Economic considerations dominate investmentdecisions in the industrial sector. For mostindustries energy costs and electricity costs areonly a small part of operating costs and thus maynot enjoy a high priority. Industries that are highlyenergy and electricity intensive have a strongerincentive to invest in efficiency, while others donot even though there may be substantial and costeffective opportunities. Most firms regard energyefficiency in the context of larger strategicplanning purposes. Investments are evaluated andranked according to a variety of factors: productdemand, competition, cost of capital, labor, andenergy. Energy-related projects are not treateddifferently from other potential investments andmust contribute to increased corporate profitabil-ity and enhanced competitive position. As a resultincentives aimed at reducing energy demandgrowth or improving efficiency in the industrialsector must compete with other strategic factorsand therefore have to be substantial to make asignificant impact.

In addition to lack of strong financial incen-tives and management indifference, industrialenergy efficiency gains are also hampered by lackof information, and shortages of skilled designers,installers, and auditors. Highly specialized andplant- or application-specific analyses are oftenrequired to identify optimal and appropriateenergy savings improvements because of thediversity of industrial processes, equipment, andenergy applications. President Bush’s NationalEnergy Strategy report found that the industrialsector tended to underfund investment in energyefficiency R&D because of the belief that compe-titors could quickly adopt process or technologyadvances, thus minimizing any potential competi-tive advantage.83

overall, in past studies OTA has found that thebest way to improve energy efficiency in theindustrial sector is to promote general corporateinvestment in new plant and equipment-newergenerally means more energy-efficient.

83 National Energy Strategy: Powerful Ideas for Amen”ca, supra note 6, P. 56.

UtilityEnergy

EfficiencyPrograms 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 notsurprising that energy efficiency has become the

bywor for cost-conscious consumers, regulators, and utilitiesseeking new ways to hedge future strategies. The potential ofenergy efficiency as a means to lessen the environmental impactsof energy use has also attracted the interest of conservationists.The prospective new business opportunities have garnered theattention of energy service companies and equipment manufac-turers and vendors, as well as utilities.

This chapter looks at utility programs to influence customerenergy use and how they are incorporated in utility resourceoptions. State government efforts and regulatory treatment ofutility-sponsored conservation and efficiency programs arediscussed in chapter 6.

SCOPE OF UTILITY ENERGY EFFICIENCY PROGRAMSU.S. utilities and State regulators have now had more than a :

---- ~>. * #idecade’s worth of experience with utility-sponsored energyefficiency programs. Broadly speaking, energy efficiency pro-grams are aimed at reducing the energy used by specific end-usedevices and systems without degrading the services provided.Such savings are generally achieved by substituting technicallymore advanced equipment to produce the same level of energyservices (e.g., lighting or warmth) with less electricity.1 Energyefficiency programs are sometimes referred to as energy conser-vation programs. However, because to some people the term

1 Eric Hirst and Carol Sabo, Electn”c Utility DSM Programs: Terminology andReporting Formats, ORNL/CON-337 (Oak Ridge, TN: Oak Ridge National Laboratory,October 1991).

I 99

—


conservation implies an overall reduction inelectricity use and energy services, many industryanalysts prefer to use the more neutral andinclusive term energy efficiency. Energy conser-vation measures can be included in efficiencyprograms.

Demand-side management (DSM) programsare organized utility activities intended to affectthe amount and timing of customer electricity use.In theory, successful DSM programs can reducethe need to build powerplants by controllingdemand for electricity and thereby creating roomfor expansion without providing additional sup-ply resources.

Utility load management programs are closelyrelated to energy efficiency DSM programs. Loadmanagement programs refer to utility programsintended to influence customer demand througheconomic or technical measures usually with theobjectives of reducing demand during peak peri-ods, and/or encouraging demand during off-peakperiods). 2 In pursuit of the frost goal, loadmanagement programs can include many of thesame technologies and measures used for overallreductions in electricity use. Load managementprograms usually employ a combination of loadmanagement incentives, metering to measure thetime and quantity of customer electricity use, andload control equipment. Because of the time-shifting aspect of load management programs,they may be targeted at peak loads and notnecessarily at an overall reduction in electricityconsumption. Load management programs canalso be directed at retaining load or customers,and expanding customer loads. Box 5-A showscommon utility load management strategies andtheir load shape objectives. These same loadshape objectives are used for utility DSM pro-grams.

Electric utilities have used load control meas-ures for more than 50 years, but interest in these

measures increased significantly in the 1970s and1980s. Over this period, interest in load controlwas high among utilities that purchase most oftheir power from others (primarily municipalutilities and rural cooperatives) because loadcontrol offered an additional means to reducewholesale power costs.3

Utilities can have many goals for DSM andload management programs. Maximizing energysavings is one. Others, and perhaps more impor-tant to different utilities, are maximizing cus-tomer satisfaction, minimizing lost revenues (util-ity revenues lost when consumers reduce electric-ity use), mininizing free riders, or minimizing thecost per kilowatt (kW) or kilowatt-hour (kWh)saved.

The development of utility energy efficiencyprograms coincides with the trend toward adop-tion of integrated resource planning (IRP) proc-esses by electric utilities. IRP involves a compre-hensive and open utility planning process thatincludes greater consideration of potential demand-side measures on a par with generation and othersupply-side additions in order to meet projectedloads. The prospect of greater reliance on demand-side measures to delay the need for new power-plant construction requires that potential energysavings be estimated with greater certainty andthat actual savings be validated. Adoption of IRPhas created new challenges for electric utilitiesplanners and their regulators in incorporatingrapidly expanding DSM programs into the re-source mix.

INFLUENCING CUSTOMER BEHAVIORElectric utilities, with the approval and encour-

agement of State regulatory bodies, have adopteda variety of mechanisms to influence customerelectricity use: load controls, differential or in-centive rates, rebates, loans, grants, shared-savings agreements, energy audits, technical as-

2 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 classicforms of bad management. Peak dipping is generally consider‘ ed as the reduction of peakbad by using direct bad control. Direct Ioad control is most commonly practiced by directutility control of customers’ appliances. While many utilities consider this as a means toreduce peaking capacity or capacity purchases and consider control only during the mostprobable days of system peak, direct load control can be used to reduce operating costand dependence on critical fuels by economic dispatch.

VALLEY FILLING is the second classic form of bad management. Valley fillingencompasses building off-peak loads. This may be particularly desirable where thebrig-run incremental cost is less than the average price of electricity. Adding properlypriced off-peak bad under those circumstances decreases the average price, Valley fillingcan be accomplished in several ways, one of the most popular of which is new thermalenergy storage (water heating and/or space heating) that displaces loads served by fossilfuels.

LOAD SHIFTING is the last classic form of load management. This involves shifting loadfrom on-peak to off-peak periods. Popular applications include use of storage waterheating, storage space heating, coolness storage, and customer load shifts. In this case,the bad shift from storage devices involves displacing what would have beenconventional appliances served by electricity.

STRATEGIC CONSERVATION is the load shape change that results from utility-stimulated programs directed at end-use consumption. Not normally considered loadmanagement, the change reflects a modification of the bad shape involving a reductionin sales as well as a change in the pattern of use. In employing energy conservation, theutility planner must consider what conservation actions would occur naturally and thenevaluate the cost effectiveness of possible intended utility programs to accelerate orstimulate those actions. Examples include weatherization and appliance efficiencyimprovement.

STRATEGIC LOAD GROWTH is the bad shape change that refers to a general increasein sales beyond the valley filling described previously. Load growth may involve increasedmarket share of loads that are, or can be, served by competing fuels, as well as areadevelopment. in the future, load growth may include electrification. Electrification is theterm currently being employed to describe the new emerging electric technologiessurrounding electric vehicles, industrial process heating, and automation. These have apotential for increasing the electric energy intensity of the U.S. industrial sector. This risem intensity maybe motivated by reduction in the use of fossil fuels and raw materialsresulting in improved overall productivity.

FLEXIBLE LOAD SHAPE is a concept related to reliability, a planning constraint. Oncethe anticipated load shape, including demand-side activities, is forecast over thecorporate planning horizon, the power supply planner studies the final optimumsupply-side options. Among the many criteria used is reliability, Load shape can beflexible-if customers are presented with options as to the variations in quality of servicethat they are willing to allow in exchange for various incentives. The programs involvedcan be variations of interruptible or curtailable bad; concepts of pooled, integrated energymanagement systems; or individual customer load control devices offering serviceconstraints.

PEAKCLIPPING

A

$

VALLEY

““7%LOADSHIFTING

-nSTRATEGICCONSERVATION

STRATEGICLOADGROWTH

A

FLEXIBLELOAD

n

● * ● * ●

SHAPE ● ● ● ● “*● ** ● * ●

● ● ● * ● ● ● ● .● *

● ● ● ● *. ,ba.● .** ● *** . . . ● . “.

● ● , .-** ● - . ● ● ● . . .. .*

SOURCE: U.S. Congress, Office of Technology Assessment, 1993, adapted from Battalle-Columbus Division and Synergic ResourcesCorp., Demand-Side Management, Volume 3:Technology Alternatives and Market Impkmmntatkm Methods, EPRI EAVEM-3597 (Palo Alto,CA: Electric Power Research Institute, 1984 ).


sistance, direct equipment installation and re-placement, comprehensive energy managementprograms, and so forth. Many of these programsare of recent vintage and limited in scope, butoverall the initial savings have been promisingeven though not as high as expected. Certainissues have recurred in the design, implementa-tion, and evaluation of these programs, including:cost-effectiveness determinations, choice of ef-fectiveness tests, free riders, measurement ofsavings, persistence of savings, customer partici-pation rates, utility cost recovery, and financialincentives.

All utility DSM programs fit into one or bothof the following programs: 1) those affecting theway energy-using equipment is operated, and 2)those that focus on the installation of efficienttechnologies. Utilities typically operate separateprograms for commercial, residential, and indus-trial customers.

Load control measures differ based on thedegree of control and input exercised by the utilityand the customer. They range from programs inwhich the utility asks customers to reduce loadand the customer individually decides whichappliances to turn off, to direct load controlsystems that are highly automated and have littlecustomer input.

Direct control systems are by far the mostcommon form of load control. They typicallyconsist of a communications system that links thecustomer’s equipment with the utility and adecision logic system (i.e., a computer program)that dispatches commands to the customer equip-ment in response to information on utility and/orcustomer loads. In a residential load managementprogram, equipment might be installed to allowthe utility to cycle participating home air-conditioners and water heaters on and off brieflyduring times of peak load with little or nodisruption to the customer. With widespread

participation, this represents a critical strategictool for utilities to shave peak load. Typically thecustomer enters into an agreement with the utilitythat gives them either lower rates and/or a smallmonthly payment for participation in the pro-gram. For example, Potomac Electric PowerCompany (PEPCO) offers a credit of $110 tohouseholds that join its “Kilowatchers PlusClub” and allow the company to shutoff their airconditioning for short periods of time to offsetsummer peak loads if needed. Some 100,000members of PEPCO’S “Kilowatchers Club”receive a $45 credit for allowing the utility tocycle their compressors off and on for briefperiods. PEPCO estimates that by 1995, cyclingwill pare 170 megawatts from its summer loads.4

Utilities and regulators have experimentedwith various incentive rates in an attempt toencourage greater efficiency in electricity use.They have instituted variations in rates by charg-ing more for peak load and higher volume usageto reflect the increased costs of providing suchservice. There has been a great deal of activityinvolving time of use rates for large industrial andcommercial customers, but only limited experi-ence with time of use rates for residentialcustomers. Participation in time of use ratesgenerally requires installation of meters thatallow measurement of both the quantity and timeof customer electricity use.

Information programs are intended to alertcustomers about potential electricity savings meas-ures. Examples include informational advertisingcampaigns, energy audits, and bill enclosures.According to an analysis of utility DSM programsprepared by the American Council for an Energy-Efficient Economy (ACEEE) for New York State,information-only programs that provide custom-ers with general information about energy effi-ciency opportunities and/or combine informationwith 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 arethe free energy audits coupled with post-auditfollowup. According to ACEEE, the programscan achieve high participation rates (60 to 90percent) and energy savings among participatingcustomers of 6 to 8 percent.6 Revamped informa-tion programs are reported to be achieving greaterlevels of participation.

Rebate programs provide money to custom-ers, contractors, homebuilders, vendors, or otherswho make equipment choices to help defray someor all of the cost of DSM measures. Rebateprograms are the most common utility programoffered. The form of rebate mechanism can becash, discount coupons, or bill credits. ACEEEfound that the most successful rebate programs intheir survey reached about 10 percent of eligiblecustomers (and about 25 percent of the largercustomers with peak demand of 100 to 500 kW)over a period of 3 to 7 years. The most successfulprograms cut electricity use by 5 percent at utilitycosts of $0.01/kWh saved. The most effectivetargets have been lighting and heating, ventila-tion, and air conditioning (HVAC) equipmentimprovements. Rebate programs have not histori-cally been very effective at promoting systemimprovements-those involving the interactionof many pieces of equipment. Generally, partici-pation levels are moderate, as are energy savings.They effectively cut utility peak demand andelectricity sales by about 1 percent/year in suc-cessful cases surveyed in the ACEEE study.Some analyses indicate that participation dropsoff after several years of aggressive programpromotion; however, more analysis is needed ofthis possible pattern according to ACEEE’Sstudy.

The “Super Good Cents” Program, sponsored by theBonneville Power Administration and northwesternutilities, provides certification for new residentialbuildings and manufactured homes that meet stringentenergy efficiency standards. The program qualifies thebuyers for rebates from participating utilities.

Loan programs provide cash to finance energy-savings investments and are attractive for custom-ers who lack cash. The program may allow thecustomer to repay energy efficiency investmentson the monthly utility bill, often at a low interestrate. They are offered by only a few utilities.Studies of consumer loan programs found thatcustomers offered a choice of rebates or low-interest loans have generally opted for the re-bates. 7

Increasingly, utility programs bundle variousDSM approaches into a single package. Forexample, the City of Fort Collins Light and Poweroffers residents of Fort Collins the Energy ScoreHome Energy Rating Service that combinesinformation, 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 bdManagement Programs for Commercial and Industrial Customers Final Repo@ Energy Authority Report 90-8 (New York, NY: New YorkState Energy Research and Development A&mm“ “stratio% April 1990). Hereinafter refcmed to as Lessons Learned. This report provides ananalysis 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 andinterview conducted circa 1987.

6 Ibid.~ ~~som ~arned, supra note 5* P“ 5-5”


mortages. Homeowners, builders, sellers, or pur-chasers of new or existing homes can contact anindependent utility-certified rater to inspect andreport on a home. The rater provides a compre-hensive home energy efficiency analysis coveringthe orientation of the lot, insulation, windows,doors, air leakage, heating and hot water systems,and other factors influencing energy use. Thehouse is given a rating from O to 100, with 100being the most efficient. The cost of the rating is$100 to $175 and the city utility picks up $50 ofthe cost. Homes with higher energy efficiencyratings (G-70 for gas-heated homes, and G-65 forelectric heated homes) may be eligible for a 2percent ratio increase on an energy efficientmortgage from participating lenders, increasingthe purchaser’s buying power. The rating alsoidentifies opportunities for efficiency improve-ments and may qualify the homeowner for theutility’s zero-interest “Zilch” home improve-ment loan to finance the upgrades.

Performance contracting programs offer pay-ments based on the amount of energy saved as aresult of efficiency improvements. They gener-ally rely on energy service companies (ESCOS) orother vendors to recommend, install, and financeefficiency measures. Utilities can also contractdirectly with large customers. According to theACEEE study, the most successful of theseprograms have included high incentives, but haveachieved significant savings. On the whole theseprograms have been more costly than some othertypes of programs. Experience has indicated thatESCOS have tended to focus on the largestcustomers and the most lucrative measures (espe-cially lighting and cogeneration) to achievesavings. ESCO contracts provide one mechanismfor reaching some of the most cost-effective,energy-efficient opportunities with significanteconomies of scale. Other approaches can targetand achieve these same savings opportunities.Initial experience with performance contractingand ESCOS has been mixed. Many utilities aresubstantially revising their performance contract-ing programs or are complementing them with

other types of programs. Performance contractingwith ESCOs or with large customers still remainsan attractive alternative for financing and install-ing energy-saving technologies.

Comprehensive programs combine regularpersonal contacts with customers, comprehensivesite-specific technical assistance, and financialincentives that pay the majority of the installationcosts of efficiency measures. According to theACEEE study, these programs were highly suc-cessful, but also tended to be among the mostexpensive at a typical cost of $0.03/kwh saved.There is little experience with large-scale pro-grams over time. The analysis suggests that thistype of program maybe particularly appropriatefor serving small customers and for new construc-tion (where there is a one-time opportunity tocapture substantial savings at only the marginalcost of efficient equipment over standard equip-ment).

r <, / --

I rLighting Design Lab in Seattle. This resource center issupported by a consortium of Federal and Stateagencies, electric utilities, and conservation groups. Itaids commercial designers, architects, engineers,contractors, facilities managers, and others in thedesign and selection of efficient lighting applications.

Request for proposal (RFP) and biddingprograms have been in operation for severalyears. Under these programs, the utility issues arequest for proposals to provide demand-side

Chapter 5-Utility Energy Efficiency Programs and Experience 1105

resources and receives and evaluates proposalsfrom ESCOS and customers. After evaluating thebids, the utility negotiates contracts with thewinning bidders for specific energy savings andload reductions. Based on preliminary resultsanalyzed for the ACEEE New York study, theseprograms offer the promise of significant savings(up to 1.5 percent of peak demand after 2 years).The success has been tied to reaching largecustomers directly or through ESCOS who partic-ipate in the process. The programs generally areless than utility avoided cost, but a tendency hasbeen noted for bids to approach utility avoidedcosts. Much of the initial experience with DSMbidding programs was in Maine and New York.As utility competitive resource procurementshave expanded, so too have the number of biddersoffering demand-side installations. Moreover,these demand-side bids are proving to have ahigher success rate in winning bids than conven-tional supply options.8

Fuel switching programs involve incentivesto utility customers to reduce load by switching toan alternative energy source for all or some of theservice provided by electricity. Examples includethe installation of a gas-powered air conditioningsystem in a large commercial office complex orswitching from an electric resistance to a gaswater heater. Fuel switching and electrificationmeasures generally involve complicated site-specific tradeoffs, and no generalizations can asyet be made about their overall performances andcosts.

MEASURING ENERGY SAVINGS ANDEVALUATING EFFECTIVENESS

There has been over a decade of experiencewith utility load management and DSM programsaround the country. Substantial dollar and energysavings have been claimed, but much remains tobe learned.

To be successful from the perspective ofleast-cost planning objectives, the programshould achieve maximum long-term, cost-effective net energy and demand savings (net ofwhat would be required in absence of the utilityprogram). Generally this means a long-termstrategy aimed at serving the most customers(including all but the very smallest). This is toassure maximum savings and to minimize equityissues of cross-subsidization. In addition, thestrategy should promote efficiency/load manage-ment measures that customers are unlikely toinstall without utility efforts in the short term andfor longer-term measures with long-Lives or thathave a high probability of replacement.

The ACEEE study found that utility DSMprograms as a whole had not yet had a dramaticimpact. The programs surveyed were reachingless than 5 percent of target customers on acumulative basis and were reducing their energyuse by less than 10 percent. As of 1989-90, it wasestimated that utility peak demand had beenreduced by less than 1 percent. They did find anumber of highly successful programs, however.A few reached 70 percent or more of eligiblecustomers—with customer energy savings of 10to 30 percent, and reductions in utility peakdemand of up to 5 percent. Many of the mostsuccessful programs, however, were still in pilot-or small-scale programs and had yet to be appliedon a large-scale basis. The good news is that all ofthe energy savings reported came at a cost toutilities of less than $0.04/kWh saved evenincluding free riders. These reported costs wereless than many utilities’ avoided costs to generatenew power, making it likely that the programswould prove cost-effective using the utility costtest.9

Since the ACEEE study was published, utilityDSM programs have continued to grow, andmany utilities are now projecting significantsavings 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.


Oak Ridge National Laboratory, based on reportsto the Energy Information Administration, foundthat existing utility programs are projected tooffset 14 percent of the growth in electricitydemand by the year 2000.10

D Measuring SwingsThe savings from a DSM program are esti-

mated by comparing energy demand both beforeand after the program is implemented. Evaluatingthe success of utility DSM programs is difficultboth on a local and a national basis. Most savingsestimates reflect engineering estimates, and moresophisticated measured and validated estimatesof savings are rare. Engineering estimates gener-ally rely on simple rules of thumb calculationsusing manufacturers data, or engineering simulat-ions. Engineering estimates can be fairly accu-rate for some simple DSM actions (e.g., domesticwater heater wraps). However, in practice, engi-neering estimates have been found to overesti-mate actual electricity savings.11 As experiencewith DSM programs increases, and energy sav-ings are subjected to more rigorous impactevaluation, it should be possible to develop othertechniques, or at least more accurate engineeringrules of thumb, to support reliance on this

technique to es t imate potent ia l savings . Unt i l

then, such es t imates should be viewed wi th

caution.

In order to show the effectiveness of efficiency

m e a s u r e s , i t m u s t b e d e t e r m i n e d h o w m u c h

electricity use is actually reduced over what it

would be in the absence of the measure. Depend-

ing on the goal of the program, monitoring usageby 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 (collect-

ing data on) electricity use and the impacts of

efficiency improvements: monthly customer bills,spot metering (either on a short-term before andafter retrofit or permanent basis), whole buildingload research monitoring, and end-use load re-search monitoring. See box 5-B.

Measuring exact savings is not necessary in allcases and could become prohibitively complex asthe number and extent of DSM programs in-crease. For simple measures, where there issubstantial experience (more efficient residentialrefrigerators, for example), past measurementsand engineering estimates may suffice to calcu-late savings for the program. For more complexand site-specific DSM measures (e.g., retrofittingand relamping a large commercial building),detailed site-specific measurements of specificload shapes may be needed to estimate savings.

Comparison of customer billing data is themost straightforward and least expensive methodfor many applications, but is not adequate for newconstruction or for large and complex installa-tions. In the former case, bill data will be absent,thus engineering calculations or comparisonswith similar buildings for which data are availablemight be used. In the latter case, normal fluctua-tions in energy use could mask the effects ofefficiency improvements and so specific end-usemetering that tracks the time and quantity of

electricity may be required.

Once total end-use savings have been deter-

mined, the impacts on utility load shape andsupply must be calculated. In general, because oftransmission and distribution losses, the actualkilowatts saved at the powerplant from customerefficiency measures are about 8 percent higherthan that saved on site. Kilowatts saved by thecustomer may also reduce utility reserve margins,i.e., customer savings plus the reserve margin

percentage (a l lowance for powerplant down-

lo 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,’ EnergyProgram 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 de-year before and a year after electricity use, permits ad- mand (kW) reductions un-participation, adjust annual justment for changews in weather less customers face demandelectricity use for weather and other factors, and re- charges. Analysis of monthlyand other relevant factors, quires little primary data col- billing data can yield ambig-and compute the difference lection. uous results. Estimates ofbetween pre- and post- kWh savings affected byparticipation use in kWh/ changes in facility use unre-year. lated to devices installed.

spot metering of Monitor electricity use be- Measures electricitysavings Could yield estimates of sav-electricity use fore and after participation (both kWh and kW) for well- ings not realized if meas-

for short times (e.g., a few defined, short time periods. urernents taken incorrectlydays); also measure other Modest cost. or at atypical times, or ifrelevant factors (e.g., oper- building use changes. Diffi-ating hours for equipment cult to apply to devioes thatand heating degree days) are season-or weather-for a longer time (e.g., up to dependent.a year).

whole-building load- Monitor electrlcity use of facil- Measures actual electricity Expensive and time con-research 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 mayother data to adjust for be affected by changes inc h a n g e s i n w e a t h e r a n d f a c i l ifactors. ment installed.

End-use, load-research Monitor specific circuits af- Measures actual electricity Most expensive and timemonitoring 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 so-and 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 byand other factors. changes in facility use unre-

lated 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 savingsend-use efficiency savings and documentation of from efficiency measures is also important. Someactual reductions in utility-generating demand measures may prove to be fairly reliable andover time may contribute to less uncertainty about long-lived (for example building insulation thatdemand-side measures in utility resource plan- the customer is unlikely to remove). But otherning. measures may be affected by declines in the


technical performance of equipment, the lifetimeof the measure, user replacement of measureswhen they wear out, changes in operating condi-tions induced by the DSM program, or market-related changes in electricity use. 12 The energy-savings benefits of a compact fluorescent lightmay disappear, if when it is worn out, the userreplaces it with a standard incandescent lamp.Similarly, an occupant might be induced to raisethermostat settings to take advantage of improvedbuilding insulation or an efficient space heatingsystem, thus, at least partially offsetting theefficiency gain. This phenomenon of losses inefficiency gains because of customer behavior isoften referred to as takeback.

M Participation RatesThe success of DSM programs often hinges on

the number of customers and/or trade allies(businesses that sell or influence choices ofenergy using equipment such as architects, de-signers, builders, appliance dealers) that partici-pate in the program. Participation rates are theratio of the number of participants to the numberof eligible customers. In many cases, determina-tion of the pool of potential participants is fairlystraightforward and based on information a utilityreadily has at hand (e.g., commercial officebuildings, all residential customers). However,for more specialized programs, additional marketresearch may be needed to identify potentialparticipants, for example, homes with electricresistance heat, or industrial motor applications.

As a practical matter, most estimates of DSMprogram participation rates generally include freeriders. Free riders are customers who participatein a program, but would have undertaken the same

conservation actions even if the program were notoffered. 13 (Some discussions also brand as freeriders ratepayers who benefit from conservationprograms, but do not participate; however in thisreport we include only program participants.) Thepresence of free riders tends to overstate programresults. Some economists maintain that free ridersshould not be eligible for program incentives andwill drive up program costs and ratepayer impactsto an unacceptable degree.14

The presence of free riders, setting aside theissue of whether they should be eligible forfinancial incentives, complicates evaluations ofthe effectiveness of utility DSM programs. Indetermining g whether the program has actuallyhad an impact on customer energy use, the focusmust be on net savings-calculated by determin-ing the share of free ridership and excluding theassociated savings.

But the presence of a high portion of free ridersin a program is not necessarily an indication thatthe program is not effective for several reasons.

First, one should expect a high degree of freeriders early in the program and then as theprogram becomes more successful and participa-tion increases, the free rider share should ap-proach a floor defined by the penetration of theefficiency measure in the market place or themarket share of efficient devices versus standarddevices in absence of the program.l5

Second, many estimates of free ridership arebased on self-identification by those who say theywould have adopted the measure anyway, thustending to overestimate actual free ridership. Thebias problems with surveys are well documentedand show a tendency of respondents to give theperceived “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 tieDSM prograrn-wcommended actions, but do not participate directly in the program (i.e., claim rebates). The absence of fkee drivers will resultin 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 workingmotors and 5 to 35 percent for new motors).


rather than the ‘‘true’ answer. Additionally,while a participant might be favorably disposed toinstallation of the efficiency measure in theabsence of the program, it is difficult to estimatewith any accuracy how many of the self-identifiedfree riders would actually have installed themeasure without the program or the extent towhich the existence of the program acceleratedtheir actions.

I Costs of DSM ProgramsMonitoring and estimating the costs to utilities

and customers is necessary to determine whetherthe costs of efficiency programs are outweighedby their benefits, and to provide for adequate costrecovery in regulatory proceedings.

For newly authorized programs, very littleactual cost data may be available, but as experi-ence increases, costs should be calculated withgreater accuracy. The ACEEE review of 58existing utility DSM programs found that re-ported cost figures per kilowatt and kilowatt-hourfor efficiency measures were only approximate,and often ignored customer costs, and sometimesrelying on rough estimates of indirect utilitycosts. The lack of accurate cost data is troublingwhen one considers that over $2 billion wasinvested in utility energy efficiency programs in1991 and that by the end of the decade someexperts estimate that DSM could be a $30billion/year industry.

16 Moreover, more reliableand detailed cost data are needed for DSMresources to be more fully integrated into utilityresource planning processes.

9 Determining Cost-EffectivenessThere is a wide variation in how different

utilities and State regulators calculate the cost-effectiveness and costs of DSM programs. Thecost-effectiveness of DSM measures is com-monly estimated from either the utility, customer,

or the societal perspective. For more on cost-effectiveness tests, see chapter 6 of this report.

The utility perspective considers the utility’scosts and benefits for program, including rebateand other costs, avoided energy and capacitybenefits. It excludes customer costs and the valueof revenues lost by the utility because of energysavings.

The total resource cost perspective (adopted inNew York State) includes money paid by pro-gram participants for materials, installation, andmaintenance (including credits for reducing cus-tomer costs, such as reduced maintenance costs inaddition to factors considered from the utilityperspective). In practice, the total resource costtest suffers from the fact that extensive data oncustomer costs are not generally collected byutilities.

There are several alternative units used inestimating cost-effectiveness. Cost per kilowatt-hour saved simply uses program expenses dividedby kilowatt-hours saved). Other measures calcu-late levelized cost per kWh saved (discounting thecost over time) to provide a long-term costestimate. More rigorous approaches involve cal-culation of total levelized costs of the programand comparison with avoided total costs of theenergy saved (avoided energy costs plus levelizedvalue of annual capacity cost divided by 8,760hours/year).

1 Evaluation of DSM ProgramsEvaluation is the systematic measurement of

the operations and performance of DSM pro-grams and should rely to the extent possible onobjective measurements and well-defined andexecuted research methods. Program and impactevaluations of DSM and load management pro-grams are critical components of both utility andgovernment assessments of the cost-effectivenessand success of efficiency measures. Programevaluation 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* ~dgeNational Laboratory, December 1991).


relies on social-science research methods andtechnical data to provide valid and reliabledocumentation and quantification of programresults and costs and to analyze their usefulness.Good impact evaluation efforts are not cheap oreasy to perform, and yet are an indispensableelement of any expansion of efficiency programs.Adequate funding of evaluation and monitoringcan amount to 10 percent of the costs of utilityprograms. As the costs, extent, and expectationsof utility energy efficiency programs grow, theresources devoted to monitoring and evaluationwill have to expand and the evaluation techniquesmust also become more technically sophisticatedand reliable.

MIXED RESULTS FROM UTILITYENERGY EFFICIENCY PROGRAMS

While there are clearly successful utility en-ergy efficiency programs with demonstrable en-ergy savings, experience so far indicates that theenergy savings achieved fall far short of the fulltechnical potential that is cost-effective to endusers.

The ACEEE review of 58 utility programsfound evidence for this conclusion in low partici-pation rates and in actual savings well belowcost-effective technical potential.17 programs withthe highest participation rates reached only 10 to70 percent of eligible customers. Among partici-pating customers, the programs with the highestenergy savings were found to yield only 20 to 60percent of the cost-effective technical potential.Cost-effective technical potential was defined asmeasures having equipment and installation costsless than $0.05 kWh saved, i.e., less than the retailcommercial and industrial electricity rates and/or

utilities’ long-run avoided costs. The gap betweentechnical potential and actual savings was largefor the best programs and larger still for typicalprograms.

Low participation and savings rates are typicalof the startup stage of most programs, and manyprograms were still limited in scale and had onlya few years experience. However, other utilityprograms have been operating for some time andit is reasonable to expect better performance.

No utility operates state-of-the-art programs inall areas. The largest commercial and industrialefficiency programs were found to have reducedkilowatt-hour sales by only 2 to 14 percent-farless than the estimated 35 percent cost-effectivesavings potential (from the consumer perspec-tive) found in the ACEEE study of New YorkState potential.18 These performance shortfallsraise questions about the viability of ambitiousState and utility efficiency goals.

Some economic analysts are challenging utili-ties and regulators cost-benefit equations andquestioning the claimed successes of DSM pro-grams. One controversial analysis performed forthe U.S. Environmental Protection Agency dis-carded the more commonly used cost-benefit testsand applied an alternative cost-benefit measure toDSM program savings calculated by two utilities.The report examined a total of 16 separate DSMprograms operated by the two utilities and con-cluded that none of the programs passed its‘‘conventional’ economic cost-benefit test ifenvironmental benefits were excluded from thecalculations .19

The New York State Energy Plan sets a goal forutility conservation and load management pro-grams 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 inNew York State from Utility Demand-Side Management Programs, Energy Authority Report 9018 (Albany, NY: New York State EnergyResearch 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~ Spring1993.

Chapter &Utility Energy Efficiency Programs and Experience I 111

percent by 2008. To do this, ACEEE estimatesthat DSM programs will have to reach 50 to 70percent of customers and achieve savings amongparticipants of 20 to 30 percent.

Nevertheless, many utilities have now enthusi-astically embraced DSM programs. The NewEngland Electric System (NEES) has been anearly leader in utility DSM programs, spurred inpart by financial incentives adopted by Stateregulators in Massachusetts, New Hampshire andRhode Island. For 1990, NEES reported thatpotential system profits from DSM programswere $10 million. Estimated savings were a totalof 194,300 megawatt-hours saved and 116.5megawatts of demand reduced.20

NEES’S third resource plan adopted in 1991relies on DSM programs to displace a total of 850megawatts by 2000, constituting more than 12percent of the utility’s capacity resources. NEESresource plan will also achieve a 45 percentreduction in net air emissions by 2000 through itsresource strategies including DSM, converting/repowering an existing plant to natural gas,accelerating environmental compliance, powerpurchases from nonutility generators and Cana-dian hydroelectric facilities, and various initia-tives to offset greenhouse gas emissions.21

Pacific Gas & Electric Company, the Nation’slargest utility, also has long experience in DSMprograms. PG&E plans to spend about $2 billionon customer energy efficiency in the 1990s andcut their energy growth by half and peak demandby 75 percent (2,500 megawatts). PG&E projectsthat these savings can be achieved at a cost offrom $0.03 to $0.04/kilowatt-hour-less than halfthe cost of building new fossil generation.22

H Elements of Successful ProgramsEven though no utility was found to perform at

state-of-the-art levels in all of its efficiencyprograms, a number had demonstrated notablesuccess. 23 They shared certain program elementsthat are believed to contribute to above-averageparticipation and savings:

Marketing strategies that use multiple ap-proaches (direct mail, media, etc.) combinedwith personal contacts with the target audi-ence. Particularly successful are those thatdevelop regular, person-to-person contactsand followup contacts after installation toassure that the measures are working prop-erly and to promote additional measures.Targeting of program approaches and mar-keting strategies to different audiences (cus-tomers, architects, equipment dealers, engi-neers, developers) and for different types ofinvestment decisions (new construction, re-modeling, replacement, retrofitting). Includ-ing target audiences in program design isespecially successful in producing a programthat meets consumer needs.Technical assistance to help targeted cus-tomers assess efficiency opportunities andidentify and implement DSM measures. As-sistance might include energy audits, adviceon equipment, contractors, computer model-ing of possible savings alternatives, informa-tion on new state-of-the-art technologies.Detailed technical assistance is generallyonly cost-effective when coupled with incen-tive programs that induce high levels ofcustomer participation and savings.Simple program procedures and materialsthat 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, NewEngland Electric System; Pacific Gas and Electric; Southern California Edison; and Wisconsin Electric. See Lessons Learned, supra note 5.


g,.-fn

.a—

*..

An energy audit team makes a site visit to a Pacific Northwest lumber mill to study operations to help developmentof an industrial energy efficiency program.

understand program potential and to partic-

ipate. Examples are one-s tep appl icat ionprocedures, assistance in filling out forms,

packaged rebate programs.

F i n a n c i a l i n c e n t i v e s t h a t a t t r a c t c u s t o m e r

attention and reduce first costs of imple -

ment in ,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 cos t ) genera l ly appear to pro-

duce higher participation rates than moderate

incentives (one-third of a measure’s cost).

Moderate incentives may not produce higher

participation rates than low incentives, how-

ever.

Multiple measures available for customersto choose from that increase the l ikel ihood

that c u s t o m e r s will f ind a measure o r - p r o -

gram that i s appropr ia te for t h e i r n e e d 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

al lowing cus tomers to propose the i r own

qualifying measures tend to boost participa-

tion 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 genera-

tion technologies. A high percentage of free

riders (about 30 percent) have been found

with <t ime technologies , especia l ly 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 cus-tomers may be unfamiliar with and wary ofnew, advanced energy-saving technologies,programs that focus on them may requiresubstantial marketing efforts to boost typicallow initial participation rates.Additional factors that contributed to thesuccess of utility DSM programs were: topmanagement commitment to energy effi-ciency measures, staff and organizationalcommitment, skills, support, creativity, andflexibility. Personal contact marketing andfollowup by utility personnel are also key tosuccessful programs. Lastly, the most suc-cessful utility programs have been thosewhere utilities are offered incentives forsuccessful programs.

I Problem AreasThe ACEEE study identified several problem

areas that must be addressed if DSM programs areto have a significant effect.

Most utility commercial and industrial DSMprograms have had only a limited focus. Theprograms must expand beyond lighting and smallHVAC improvements to include advanced light-ing and motor technologies and comprehensiveindustrial system improvements. There is noone-size-fits-all comprehensive demand-side pro-gram. Regulators and utilities must developpackages of programs tailored for the utility, load,and customer characteristics if the initiative is tobe a success. Many utilities in an effort tostructure their services to enhance customervalues are examining ways to provide morecomprehensive energy efficiency services,

Participation rates have been low. Marketingefforts must be expanded to reach and persuademore customers to participate.

More data and research are needed to supportDSM program development and evaluation. Pro-gram design and evaluation is hampered by the

lack of credible data on energy use and targetpopulations (building characteristics, motors andother equipment), and by the lack of accessibleand useful documentation and evaluation ofexisting programs. Information on actual percent-age reductions in energy use is rarely collectedand yet would be of invaluable assistance toutilities, regulators, and consumers.

Additionally, because energy and load man-agement efforts have been limited in scope andlong-term experience is lacking, mistakes will bemade. But utilities may fear to publicize mistakesand shortcomings for fear that regulators willpunish them. There is, however, much to belearned from mistakes. Therefore unsuccessfulprogram experiences should be investigated andthe results publicized so that others might avoidthese pitfalls.

1 Need for ComplementaryState and Federal Efforts

Even the best DSM programs cannot achieveall the cost-effective savings. Some customerswon’t participate, no matter what incentivesutilities offer. Many will not adopt all cost-effective measures. Because of this tendency,utility programs need complementary approaches--e.g., building codes and appliance and equipmentefficiency standards-in order to maximize theoverall adoption of energy-efficient technologies.The California Energy Commission analysis ofthe effectiveness of utility DSM measures in 1983found the reduced peak demand of 2,718 mega-watts was due 45 percent to utility programs, 37percent to building code requirements, and 16percent to various appliance efficiency stand-ards.24 Federal and State efficiency initiatives canalso boost the availability of energy efficiencyproducts in the marketplace. See chapters 6 and 7for discussion of these efforts.

24 California Energy Coremission, Conservation Report (Sacramento, CA: 1986), p. II-11.


INCORPORATING ENERGY EFFICIENCY INTOUTILITY OPERATIONS-THE ROLE OF IRP

IRP has become the main process throughwhich utilities incorporate DSM measures intotheir mid-and long-term resource planning. As aplanning tool, IRP allows a utility to incorporatea variety of information about load, systemcharacteristics, demand growth, resource options,and corporate goals into an analysis that explicitlyevaluates supply- and demand-side resources in aconsistent manner and expressly confronts theuncertainties inherent in utility planning to pro-duce a flexible resource plan for meeting cus-tomer needs at least-cost. IRP also generallyincludes opportunities for public involvementand regulatory review, as well as consideration ofenvironmental and other social impacts of utilityresource alternatives.

By mid-1993 utilities in at least 41 States wereactively involved in some sort of IRP process. Atleast 33 States require IRP or least-cost planningby their utilities. Under Federal law, utilities thatpurchase power from the Bonneville PowerAdministration, the Western Area Power Admin-istration, and the Tennessee Valley Authority alsomust adopt IRP planning principles as a conditionof their power contracts. Information on State andFederal IRP initiatives may be found in chapters6 and 7 of this report.

Resource planning is an integral part of utilityoperations and is driven by the three fundamentalgoals-serving customer load reliably, minimiz-ing customer costs, and maintaining the financialstability of the utility (see chapter 3). Today’s IRPprocess evolved from traditional utility planning,which focused narrowly on supply-side resourceadditions to meet ever-growing customer de-mand. With experience, IRP planning processesare continuously evolving in both theory andapplication. Each utility’s IRP process is different—reflecting its system characteristics and planningneeds, corporate culture and organization, andregulatory environment. However, every IRPprocess follows a general framework in evaluat-

ing a broad range of resource options to developalong-term resource plan typically covering 20 to30 years, and an action plan covering from two tofive years. New or revised integrated resourceplans are prepared on average every two to fiveyears. Figure 5-1 shows a simplified IRP process.

The process typically begins with preparationof long-term load forecasts projecting both en-ergy sales (megawatt-hours) and peak demand(megawatts) over the planning period. The fore-casts are based on historical consumption data,weather, population, and economic data, andelectric equipment use. The load forecasts mustalso take into account expected load growth andpotential changes in energy consumption patternsdue to new technologies, DSM programs, andother conservation measures. The detailed fore-casts are used for financia1 and resource planningto identify an appropriate mix of generation,transmission, distribution, power purchase, andenergy efficiency options to meet system needsunder a range of alternative future scenarios.

Using the initial load forecasts, utility plannersthen survey potential demand- and supply-sideresource options to identify appropriate measuresfor inclusion in the integrated resource planningportfolio.

For supply-side options, planners will considerexisting generation, transmission and distributionresources, utility generating plant additions, lifeextensions and efficiency upgrades, plant retire-ments, power purchases, and improvements totransmission and distribution facilities. Duringthis initial evaluation, planners will compare theresources on considerations of: load profiles,reliability and dispatch capabilities; capital, fuel,operating, and maintenance costs; environmentaland siting requirements; and capital availability.The result will be a supply-side resource stack.

Demand-side options will be identified basedon considerations of existing customer use pat-terns, availability of energy-efficient technolo-gies, demographic data, and evaluations of exist-ing utility DSM programs. Planners will estimate


Figure 5-1-Simpl

Supply side

Supply-sideoptions

F

L!W!S!!!!!L

ified Integrated Resource Planning Framework

Demand side[ 1

4 Load forecasting

kL

A

vI Resource

planning ~

nDetailedanalysis

IA

rlIntegratedresource plan

Action plan ~1

vI

1Demand-side

options

A

I

4 Implementationand 1

evaluation ~


costs, load impacts, and participation rates toproduce an initial stack of demand-side resources.

The IRP process then proceeds to detailed anditerative evaluation of the potential resourceoptions to identify the best resource mix takinginto consideration the utility’s strategic goals,load profile impacts, production and capital costs,revenue requirements, rate impacts, environ-mental and other regulatory requirements, andother planning uncertainties. Planning uncertain-ties related to demand-side resources includeparticipation rates, and the costs, effectiveness,durability, and verification of efficiency meas-ures. For supply resources, uncertainties includeconstruction time and costs, regulatory approvals,fuel availability and costs, operating and mainte-nance costs, and public attitudes towards thetechnology and the specific facility proposed.Overall uncertainties complicating resource plan-ning affecting load growth and costs includeimpacts of inflation and interest rates, changing

economic conditions, availability of purchasedpower, and changes in environmental and eco-nomic regulatory policies. During the process,resources may be added or removed from theportfolio based on the initial evaluation.

The typical IRP process includes opportunitiesfor participation by the public and by regulators.The extent and type of participation vary. Someutilities have relied upon a collaborative consulta-tion with interested parties over the entire courseof plan preparation. Others may prepare a draftplan and then solicit public and regulatory com-ment before preparing a final plan.

The costs and benefits of alternative resourceoptions are compared individually and in combi-nation and they are ranked according to theappropriate cost-effectiveness test and planninggoals. This cost-benefit ranking may be con-ducted under a number of separate scenarios withdifferent assumptions about factors affectingenergy demand, financial conditions, or regula-

. . . . .


tory requirements. In selecting a final integratedresource stack, planners must balance manydifferent and sometimes competing goals andexpectations about the future. Because resourceplanning involves many qualitative and strategicjudgments, a least-cost plan will not always be theoption that minimizes power production costs.Considerations of reliability, flexibility, resourcediversity, and business strategy/policy may out-weigh options that are the cheapest alternatives atthe time the plan is developed.

The integrated resource plan lays out theutility’s least-cost long-term strategy. It is cou-

pled with a short- to mid-term action plan thatdetails the specific actions and resource additionsthat the utility will take to carry out the planobjectives. Based on the plan, the utility, with anynecessary regulatory approvals, will proceed toplan and acquire the preferred supply- and demand-side resources to meet customer loads. Duringimplementation of the plan, adjustments can bemade to reflect changing conditions using theplan as a guide. The utility’s experience inimplementing the action plan and evaluating itsresults are then used in the next round of the IRPprocess.

StateEnergy

EfficiencyInitiatives 6

I n the past decade many States and utilities have experi-mented with changes to the utility regulatory environmentthat have brought energy efficiency to the forefront. Underthe traditional rate-of-return regulation, State regulatory

bodies set the price of electricity to include the costs of providingservice and a fair return on investment. This approach has beencriticized as creating a strong disincentive to energy-savinginvestments. To counter this tendency, States have adopted avariety of incentives to foster energy efficiency. Utilities have acritical role in implementing these emerging policies as they canhelp overcome the barriers that have hampered many energyefficiency improvements at low cost. However, the incorporationof demand-side investment into the utility portfolio presents newchallenges for both utilities and regulators.

This chapter provides an overview of State energy efficiencyinitiatives relating to resource planning and demand-side man-agement (DSM). It provides a review of various State energyplans and current integrated resource planning (IRP) programs.The economic cost tests commonly used to define the costs andbenefits of demand-side resource options are presented. Thechapter concludes with an examination of State regulatorycommission efforts to authorize recovery of DSM program costsand lost revenues, and create performance incentives that rewardutilities for above-average efficiency programs.

PLANNING FOR FUTURE ELECTRICITY NEEDSLong-term resource planning that projects future demand and

assesses options for meeting customer needs is an integral part ofutility operations. Utility resource plans have long been submit-ted to State regulatory commissions, often in conjunction withrate 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 onsupply resources to meet the ever growing elec-tricity demand. Generally, this meant buildingnew generating capacity and adding transmissionlines and other supply-side technologies. To theextent that these plans included consideration ofdemand-side efficiency, it was usually for contin-gency measures or in response to pressure fromregulators.

The turbulence in energy markets in the 1970sprompted changes in how both utilities andcommissions view planning. The resource plan-ning process came to be seen as a tool forintegrating the many factors affecting electricitydemand into the consideration of future resourceadditions and as an opportunity for regulators andothers to influence utility choices. Among thetrends precipitating this shift to a more flexibleand open planning perspective were: a slowing indemand growth, inflation in construction costs,overbuilding of capacity, troublesome nuclearprograms, cost recovery disallowances, steep ratehikes, and new environmental requirements. In-creasingly, States are requiring one or a combina-tion of the following elements in utility long-termresource plans:

■ Public hearings to review the plan beforefinal adoption,

■ Formal regulatory body approval of the plan,and

■ Regulatory certification of the need forpowerplants linked to the resource plan.1

H State Energy PlansA number of States prepare comprehensive

State energy plans that go beyond the utility realmto cover all aspects of energy use in the state. Theutility companies perform only a portion of theactions necessary to implement a statewide plan.States vary in the level of detail of prescribedaction in their plans. Utility responsibility to State

plans range from fulfilling stated requirements tofollowing general guidelines. State plans fromNew York, California, and Texas illustrate thevariety of approaches. Table 6-1 shows Stateswith energy planning requirements.

NEW YORKNew York State’s energy plan sets the frame-

work for State energy decision-making and itsutilities have concrete recommendations to con-sider. The general objectives are to promoteenergy efficiency, stimulate competition amongenergy services, and promote long-term growth inan environmentally prudent manner. Specifically,the plan’s goal for electric power is a 8 to 10percent reduction in peak demand by 2000, to befollowed by a 15 percent reduction in 2008.Recommendations to utilities include:

Energy efficiency programs to capture lostopportunities for savings in new construc-tion,Expanded delivery systems for DSM pro-grams,Use of evaluation results for better design ofDSM programs,Standard formats for DSM evaluations,Development of long-run avoided costs esti-mates appropriate for DSM program evalua-tion,Development of strategies to obtain conser-vation emissions allowances under the CleanAir Act Amendments of 1990,Increased research and development on end-use renewable energy technologies, andEncouragement for an increase in capitalbudgets to implement cost-effective power-plant efficiency.2

The New York plan details actions for utilitiesto follow if they are to comply with the statewideplan.

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

ml

%

nCr

I z

>

z

>

>

>

I

z

z

z

z

z

I

I

I

Z>>z I

I

I

I

I

z

I

I

I

I

I

I

I

I

Zz

Z z

Zz

WiUcr

>>

I Z z z z

I I > > > > z>z> Zz>z

!$Zu

>Z

Z z

.,. .. .. .. .. .. .. .. ,. .

. .,.. .. .

Zz

>>>>> zrr>>>>>)->mZz

>Zz>

. . . . . . . . . . . . . . .. . . . . . . . . . . . . . .. . . . . . . . . . . . . . .. . . . . . . . . . . . . . .. . . . . . . . . . . . . . .. . . . . . 2.....””.

. . . .. . . .. . . .. . . .. . . .. . . ..-. .. . . .. . . .

. . . . . ..,, . . .. . . . . .. . . . . .. . . . . .. . . . . ....,... . . . .. . . .. . . .. . . ..., ,. . . .. . . .... ,. . .

330-075 : QL 3 0 - 93 - 5

Table 6-l-State Resource Planning Requirements-(Continued)

Statewide Source of State Publicenergy 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 . . . . . . . . . . . . . . .

NYYYYYNNNYYYNNNYN

NYRYYRYNNYYYYYNYN

NRegsRegsRegsRegs

NRegs

NN

BothRegsBothRagsBoth

NBoth

N

YN—NN—Y

—N—

NNY—

Y—

NN—NN—N——N—NNN—N—

Y IRP submittal ordered in one case.Y—NN—N.—N—YYY—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 regulatoryaction, Regs = State regulatory commission action. State Approval: Y = State regulators formally approve utility resource plans and N= no approval required. Public Hearing: Y= Public hearingrequired 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: EdisonElectric 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:NationalAssociation of Regulatory utility Commissioners, January 1993); and Office of Technology Assessment staff research.

Chapter 6--State Energy Efficiency Initiatives I 121

CALIFORNIACalifornia’s eighth State energy plan was

released in 1992 and was approved by theGovernor to be the State’s official energy policy.The plan is supported by five technical reportscreated after extensive public review. The 1992-93 plan includes 12 policy recommendations and66 specific actions. The policy recommendationsaffecting utilities are:

■ Increased efficiency should supply most ofCalifornia’s new energy needs.

■ California should continue to capture energysavings in new buildings and appliances ascost-effective technology and design im-provements occur.

■ California should promote building retrofitprograms.

■ The State should require the most cost-effective and efficient operation of its exist-ing electricity generation, transmission, anddistribution systems.

■ California should continue to pursue diverseenergy supplies and the commercializationof new technologies to improve energysecurity and environmental quality.3

Other policy recommendations were directedat the State and local governments, the transporta-tion sector, and the marketplace. The plan iscomprehensive, covering many aspects of energyuse. The utility sector’s role is detailed in thespecific actions that accompany the recommenda-tions.

TEXASAlthough Texas has a statewide energy plan, it

does not make specific recommendations forelectric utilities. Instead, the commission reviewsa utility plan’s compatibility with the State planbefore approving a certificate of need for a new

generation facility. Box 6-A highlights severalState plans.

1 Collaborative Planning EffortsThe collaborative process allows traditionally

adversarial groups an opportunity to reach con-sensus and avoid litigation. Several States haveexplored the use of DSM collaborative todevelop suitable DSM policies and programs.Collaborative groups have brought together par-ties representing industrial customers, utilities,environmental organizations, energy conserva-tion groups, consumer advocates, and State gov-ernment agencies. The number of parties involvedin collaborative efforts has ranged from 2 to 28.The length of the process has also varied sig-nificantly--from 6 months to several years toongoing. The cost has proved to be significant.Through 1991, nine major collaborative effortsspent an estimated total of $12 million to coverthe technical expenses of nonutility parties andstaff time for both utilities and the nonutilityparties. Utilities usually provide the funds fornonutility parties to hire technical consultants.“DSM collaborative are resource-intensive butpromise to save time and money in the long-termand lead to outcomes that are qualitativelysuperior to the expected results of litigation. ’

Frequently, States turned to collaborativeafter litigation on DSM or other issues hadoccurred. Nearly all the collaborative took placein States where public utility commissions hadaggressively promoted DSM prior to the collabo-rative. Common components of collaborativehave been:

■ A focus on designing DSM programs andresolving related policy issues,

■ A proactive approach to planning to avoidlitigation,

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.


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 ofgross State product. To reach this goal, the State has focused on energy efficiency. Actions include requiringinvestor-owned utilities to obtain 300 megawatts of renewable resources by 1998 so that renewable are part oflong-term resource contribution. Utilities have also been requested to meet new energy needs throughdemand-side management and competitive bidding.

California

The California energy plan covers all sources of energy, from transportation to electricity generation. Usinga series of recommendations supported by action steps, the State’s comprehensive energy plan reflects threepolicy 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 oftechnologies to maximize the load-carrying capacity of the system, and coordinating transmission systems to optimizeuse.

SOURCES: Office of Technology Assesment, 1903, from New York State Energy Plan, vol. 1, February 1992, a nd Callforn ia EnergyCommlsslon, 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 REQUIREMENTSthrough 1991 concluded that the process wassuccessful along a broad array of criteria. Thestudy also points out that there some issues thatthe process is more adept at handling, such astechnical issues surrounding program design andapplication of DSM policies. At the other end,issues that collaborative have shied away frominclude fuel switching and consideration of exter-nalities.

6

Collaboratives, though resource intensive, haveproven to be a viable alternative to litigation. Thefact that only two rulings on collaborative planshave been appealed to courts is an indicator thatthe diverse parties have found the process accept-

IRP is a planning process used by utilities andregulators to assess alternative supply and de-mand resources to assist them with optimalresource selection. As currently defined, IRP is arefinement of longstanding utility and regulatorypractices and requirements. By early 1993 at least33 States had passed legislation or initiatedregulations to promote IRP. Figure 6-1 shows theprogress of IRP implementation across the States.State IRP requirements vary but the essentialelements include:

■ Consideration of both supply- and demand-side resources in a consistent manner thatminimizes long-run costs,

5 Ibid., pp. 17-27.

6 Ibid., pp. 27-31.


Box 6-B-The Massachusetts Collaborative

The Department of Public Utilities (DPU) in Massachusetts initiated one of the first collaborative planningefforts in August 1966 after extensive intervention in demand-side management (DSM) proceedings. Thecollaborative 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 programperformance.

Phase I gave the parties 6 months to come to an agreement on the design of DSM programs adaptable toeach 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 withits other objectives within the set timeframe.1 The utilities paid dose to $400,000 to hire technical consultants forthe nonutility parties. Paying for outside consultants was considered necessary to avoid a significant disparity intechnical expertise betwen the utilities and the nonutility parties. The nonutility participants formed a coalition thatremained stable during the course of many important issues, Phase I concluded in December 1966 with aconsensus that detailed 25 different generic program designs. The time constraints were a useful tool to ensurethat the collaborative wasn’t stalled by excessive delays. DSM expenditures in Massachusetts increased 4 to 15percent with the filing of the collaborative agreement.

Phase II was structured differently. Interested utilities voluntarily formed a Phase II collaborative with thenonutility 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 DPUdid not participate in the collaborative process, the agreement failed to address the regulators’ concerns and majorchanges 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 DSMexpenditures. DPU also required use of the societal test for determining cost-effectiveness instead of the ratepayerimpact measure.

SOURCE: Office of Technology Assesment 1993, from Jonathan Raab and Martin Schweitzer, Public Involvement in I n t e g r a t e dResource Panning: A Study of Demand-SideManagement Collaboratives,ORNL/CON-344 (Oak Ridge, TN: Oak Rldge NationalLaboratory, 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 similari-ties in the content of the plans. The majority of

■ Increased attention to uncertainty andrisk.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 orAcquisition 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 implementationU Not under active considerationU Under considerationEfil Program under development= Program in implementationB IRP requirements in practice

SOURCE: Office of Technology Assesment, 1993, based on data from National Association of Regulatory UtilityCommissioners, Incentives for Demand-Side Management (Washington, DC: National Association of Regulatory UtilityCommissioners, January 1992).

■ Descriptions of computer models used inplan preparation.8

1 What Makes a Least-Cost Plan?The fundamental goal of utility planning proc-

esses is the development of resource plans thatprovide reliable service and minimize costs whilepreserving financial stability. However, with theinclusion of demand-side resources, the diversityof options has increased multifold. Cost, equityand customer participation are key determinantsin selecting the resource mix, yet the definition ofcost reflects policy as well as economic choices.The “lowest-cost’ resource mix is heavily influ-enced by the selection of a cost-effectiveness test

as well as how the resources are compared onother characteristics. To some, lowest-cost meansminimizing the price of electricity, while to othersit is minimizing cost of energy services.

Regulators have prescribed the tests utilitiesmust use to determine the cost-effectiveness oftheir resource plans in order to have a consistentmethod for evaluating the costs and benefits ofresource options. Table 6-2 shows the prescribedtests for utility resource plans in selected States.There is controversy over the appropriate eco-nomic tests to use when evaluating DSM pro-grams that improve customer energy efficiencyand therefore reduce electricity purchases. Thedesirability 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 aNationwide 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-anddemand-side resource options have been put up for bid. By August 1993, utilities had issued more than 124requests for proposals (RFPs) for new resource additions. These RFPs elicited over 3,500 proposals for over250,000 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 ofintegrated resource planning, the trend toward competitive procurement is likely to accelerate as utilities specifywhich technologies interest them.

According to an analysis of bid competitions, through May natural gas projects and coal projects dominatedthe winning bids, with natural gas totaling 47 percent of winning bids. Proposals for repowering existingpowerplants, 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, justslightly behind coal.

Energy conservation proposals doubled between 1991 and 1992 and winning bids, primarily bidsemphasizing commercial and industrial measures, increased 21 percent the same year. In 1993 winning bids forDSM measures were up by 63 percent over 1992 results. There have been many fears about bidding fordemand-side resources. For instance, the fear that demand-side projects will fail without enough time for utilitiesto develop economically viable alternatives seems to be unfounded. To date canceled conservation projects wereterminated 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, August1993.

contingent on the economic test selected. The cost measure, and the societal cost measure (seeapplication of cost-effectiveness tests to demand-side resources is more complex than for supply--side resources for two reasons. First, manyenergy-saving demand-side measures belong tocustomers, not the utility. As a result, the costsand benefits are distributed differently for demand-side measures than supply-side measures. Sec-ond, demand-side resources exhibit differentoperating characteristics, system impacts andavailability than traditional supply-side resources.9

ECONOMIC TESTS FOR EVALUATINGDSM PROGRAMS

There are four commonly applied perspectivesused for assessing the relative costs and benefitsof resource options. The perspectives are the totalresource cost, the rate-impact measure, the utility

box 6-D). Several other tests are available, but areapplied less frequently.

Total Resource Cost TestThe total resource cost test (TRC) measures the

net benefits of a program from the point of viewof the utility and its ratepayers as a whole in orderto maximize welfare. The test determines whetherthe program being evaluated will increase ordecrease the total costs of meeting the customersservice needs. Programs that pass this test mini-mize total cost of electric energy services. MoreDSM programs will pass the TRC test than therate impact measure (see below) because it is notrestricted by possible adverse rate impacts. Crit-ics of this test argue that the utility is put atcompetitive risk should implemented programs

g Florentin Krause and Joseph Eto, hwrence Berkeley Laboratory, Lzast-Cost Utility Planning Handbook @ Public UtilityCommissioners, vol. 2, prepared for the National Association of Regulatory Co missioners, December 1988, p. III-1. Hereafter referred toas Krause and Eto, Least-Cost Utility Plamu”ng Handbook.


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 CurrentCompetition, voi. 3, No. 2, May 1992.

Table 6-2—DSM Cost-Effectiveness Tests Mandated bySelected Public Utility Commissions

Ratepayer TotalImpact resource Societal Utility

State measure cost test cost test cost test

Arizona. . . . . . . . . . . . . . . . . . . . . .California. . . . . . . . . . . . . . . . . . . .District of Columbia. . . . . . . . . . . .Hawaii. . . . . . . . . . . . . . . . . . . . . . .Maine. . . . . . . . . . . . . . . . . . . . . . .Maryland. . . . . . . . . . . . . . . . . . . . .Massachusetts. . . . . . . . . . . . . . .New Jersey. . . . . . . . . . . . . . . . . . .

—YNYY—N—

—YYYYYYY

Y

—YY—

—Y—YY—

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.’ 7992Sourcebook (Washington, DC: Edison Electric institute, 1992), p. xii.


Box 6-D--Overview of Cost-Effectiveness Tests for DSM Programs

Total Resources Cost Test/All Ratepayers TestPerspective

Measure of the total net resource expenditures of a DSM program from the point of view of the utility and theratepayers 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 measuredAvoided supply costs of anticipated reduction in energy load.

Costs measuredUtility 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 totalcosts to a utility resulting from the DSM program if the change in revenues is larger or smaller than the changein 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 TestPerspective

Measure of the change in total costs to the utility that is caused by a DSM program, i.e., the change in revenuerequirements. Also measures the change in average energy bills across all customers.

Benefits measuredUtility avoided costs.

Costs measuredProgram costs, including incentive payments to customers and custorner direct costs.

Societal TestPerspective

Measure of the net benefits of a DSM program fromthe point of view of society as a whole. Attempts to captureall the benefits and costs of a DSM program, including externalities, by using societal discount rate rather thanutility specific rate.

SOURCE: Office of Technology Assemessment 1993.


increase rates. Additionally the TRC test does notconsider whether the programs will result incross-subsidization of customer classes.l0 At leastseven States have designated the TRC test forcost-effectiveness and four rely on it exclu-sively.11

Ratepayer Impact MeasureThe ratepayer impact measure (RIM), also

known as the nonparticipant test or the “nolosers” test, focuses on the impacts a programwould have on nonparticipating utility ratepayersand thereby minimizes electricity prices. The testevaluates programs based on whether rates areincreased for nonparticipating customers by theproposed program because of additional revenuerequirements. A program is deemed cost-effective only if it reduces revenue requirements.It fails the test when its adoption would create arevenue deficit for the utility that would berecovered through a rate increase. Adoption ofprograms that fail the RIM require that nonpar-ticipants subsidize the participants’ acceptance ofthe program. This test is considered compara-tively restrictive for DSM programs comparedwith the other three tests. Opponents of RIMargue that its use increases overall costs of electricenergy services. They also argue that the testresults in the uneven treatment of investments,and shifts spending away from DSM. For instanceall customers are participants in supply-sideinvestments by the nature of the investment,whereas demand-side investments will have fewerparticipants.

12 Utilities in eight States are cur-

rently applying this test, and three regulatorycommissions require its use in conjunction withother tests. Other States have specifically rejectedthe test to screen DSM programs, or given it asecondary role.13

Utility Cost TestThe utility cost test is an accounting measure

for utilities’ costs. It measures the differencebetween the utility’s avoided cost and the cost ofprogram implementation to the utility and doesnot incorporate the cost to the ratepayers. As such,many DSM programs pass this test since part ofthe program cost assumed by the ratepayer is notincluded. However, supply-side measures evalu-ated under this test will be at a disadvantagebecause the full cost of supply measures is borneby the utility .14 California, Hawaii and Maine usethis test in conjunction with other perspectives.15

Societal Cost TestThe societal cost test is similar to the TRC;

however, it incorporates environmental external-ities when evaluating the costs and benefits of aprogram. The other distinction from the TRC testis that the societal test uses a societal discount raterather than an utility specific one. Arizona,Hawaii, and Maine have each specified use of thesocietal test.l6

Cost Test ComparisonsSome States request that programs are evalu-

ated with more than one test. For instance, if aprogram narrowly fails the nonparticipant test,

10 mid., pp. III-8-9 and Eleefric power Research Institute, Ed-Use Technical Amassment GIU”dk, VOI. 4, H CU-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 TRCtest. If it passes the second test, the utility maybeable to adopt the program after making adjust-ments to minimize rate impact and cross-subsidization. The Maine Public Utility Commis-sion stated that a DSM program that:

. . . is reasonably 1ikely to satisfy the AllRatepayers Test [the TRC] is cost effective.$. Any program that is reasonably likely tosatisfy the All Ratepayers test and to fail the RateImpact Test [nonparticipant test], but only to theextent that the utility’s present value of revenuerequirements per kilowatt-hour (kWh) do notincrease by more than 1 percent over the durationof the program, maybe continued or implementedwithout prior program specific Commission ap-proval. 17California, Florida, Nevada, New York, Ohio,

and Vermont also use combinations of tests toevaluate proposed programs.


STATE INCENTIVES FORUTILITY DSM INVESTMENTS

Advocates of least-cost planning believe utili-ties should pursue efficiency options because theyare often less expensive than supply-side altern-atives. However, utilities do not necessarily viewcheaper as better unless it also results in greaterprofits, A 1990 survey of utility management andState regulators found that the two generallyagree on the reasons for DSM incentives. Bothagreed that there is a need for incentives toprovide a bonus to stimulate DSM, to get utilitymanagement to focus on DSM, and to overcomethe lost revenue problem. Utility representativesalso considered compensation for lost profit apriority, while regulators emphasized a levelplaying field.18

States have authorized a variety of rate mecha-nisms to overcome constraints to investments incustomer energy efficiency via DSM programs.Regulators are not the only parties to proposethese rate mechanisms. Utilities themselves aswell as intervener parties have also been in-volved. The most active promoters have adoptedseveral mechanisms that work together not onlyto remove the disincentives to DSM, but also tomake DSM desirable by using a reward compo-nent. Innovative rate designs have included:

Decoupling mechanisms that separate salesand rate of return,Cost recovery mechanisms to overcome thelag in recovering DSM program expenses,Last revenue mechanisms to compensate forDSM program impacts on profitability, andPerformance incentives to improve perform-ance of DSM programs.

1 DecouplingDecoupling removes the disincentive of pro-

moting energy efficiency when it directly reducesutility profitability. Decoupling mechanisms sep-arate the fixed cost recovery from kilowatt-hoursales. Traditionally, electricity sales are measuredover a test year, or forecast if a future test year isused, and then the estimated sales level is used todesign rates. Once established, the sales assump-tion remains fixed until the next rate case. Therates provide for recovery of freed costs and areturn on investment. Aggressive DSM can sub-sequently reduce sales below the level assumed inthe rate case resulting in under-recovery of fixedcosts and a reduction in shareholder return.

A number of States are using or experimentingwith various degrees of decoupling. The firstapproach, 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 EficiencyofBuil&”ngs, vol. 8 (Washington, DC: i%nerican Council for an Energy-Efficient lkonomy, 1992), p. 8.89. Quote is from Ma.ine Fublic UtilitiesCommission ‘‘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 ElectricInstitute, December 1990.


intended to eliminate the utility’s incentive toincrease sales, preventing sales fluctuations fromimpacting on a utility opportunity to earn its rateof return. The intent is revenue neutrality, i.e. toprovide no financial incentive to increase ordecrease sales. The other approach combines anincentive for investment in cost-effective DSMwith a disincentive when sales increase.19 Addi-tional States adopting decoupling are Connecti-cut, New York, and Washington. Colorado andVirginia are investigating the option.

California’s ERAM (Electric Revenue Adjust-ment Mechanism) is the most well known decou-pling mechanism of this type. ERAM eliminatessales fluctuations as a factor in determiningrealized profits. It accounts for many factorsaffecting electricity sales other than DSM pro-grams, including weather and general businessconditions. The mechanism reconciles actual andforecast net revenues, based on future test yearused in rate design. To accomplish its goal,ERAM periodically adjusts rates in order torestore the balance established by the rate case.Proponents of this mechanism argue that itencourages the financial health of the utility byreducing the risk exposure in sales fluctuations.Other justifications include eliminating the disin-centive to conservation and the incentive tounderforecast sales in a rate case.20 Washingtonhas also adopted an ERAM-type mechanism forone of its utilities.

However, ERAM also has some disadvantages.The incentive to underspend on conservationmeasures remains. Spending less than budgetedon a program will in turn increase earnings.21 For

the utility, the risk is the potential increase incustomer “bypass.” In the case of a bypass, alarge energy consumer, such as a major industrialfacility, removes itself from the customer base bysupplying its own power-bypassing the localutility. If there is a significant ERAM deficit in agiven year, the following year’s rates would risewhich would increase the likelihood that thecustomer might seek an alternate source of power.The end result of bypass for the utility isunderutilized capacity, fewer customers, andhigher rates to recover freed costs from thecustomers that remain. If load reductions aresignificant enough, the utility may be forced toremove unused facilities from its rate base andlose its opportunity to recover a portion of itscapital investment. However, evidence to date hasnot shown that ERAM has enough impact on ratesto induce appreciable bypass.22

The Maine commission has approved a 3-yearexperiment with a lost revenue mechanism simi-lar to ERAM for one utility in the State. Theexperimental approach makes an adjustment forrevenue attrition rising from higher than expectedDSM program savings. It has also changed theaccounting rules for the fuel revenue account bysetting the nonfuel revenues from marginal walesat zero. As a result, any incremental sales do notadd to profits.23

Connecticut has allowed one utility a “partialsales adjustment clause’ that collects marginsassociated with sales falling below the test yearforecast or returns profits to ratepayers if they arehigher than expected sales. However, the partialadjustment 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~uCommis sioners, November 1989), p. 13.

m c my ~ GA. Coma, &zw&”ng for conservation: The Call~ornia ERAM experience, LBL-28019 (Berkeley, CA: hwnceBerkeley I.Aoratories, March 1990), pp 3-4. This report also notes that an additional motivation for California’s ERAM was to bolster thefinancial health of utilities.

21 Ibid. p. 35.

22 Ibid., pp. 16-21.23 David Moskovi~ supra note 19, p. 13.


normal risks of doing business such as economiccycles, weather, and competition.24

New York has added a decoupling mechanismfor three of its utilities. Consolidated Edison willdetermine net lost revenues based on studies ofsales reductions during the program implementat-ion year. The company estimates freed costs thatwill not be recovered due to DSM programs,which are then retrieved in the fuel adjustmentclause. The studies take into account the effects offree-riders and will be used to reconcile DSMprogram results with sales forecast.25

1 Recovering Demand-Side EnergyEfficiency Investments

As DSM expenditures grow, utilities andregulatory bodies are faced with the issue of howto recover costs. When DSM was in its infancy,expenditures could easily be expanded annuallywithout adversely impacting the financial well-being of the utility. However, with aggregateutility DSM expenditures having escalated toover $2 billion a year in 1991, the manner andextent to which DSM costs are recovered hasbecome a priority. DSM program costs includeadministrative and operating costs, customerrebates, and other customer incentives. UtilityDSM expenditures are not fully recovered in rateswhen DSM programs surpass the budget amountset in the ratemaking test. It is important to notethat cost recovery mechanisms do not overcomethe utilities’ incentive to sell maximum amountsof kilowatt-hours and earn a return on the amountsold. However, the combination of recoveredDSM expenses and compensation for lost revenueremoves the risk that successful DSM programswill threaten profits.

Most operating costs in the utility industry arerecovered as expenses in the year that they areincurred. Expenses are simply passed through tocustomers and do not earn a rate of return. A

simpler accounting method than the alternativeratebasing, expensing results in lower costs withcertain discount rates and tax treatments. It alsoallows for a faster cash flow and removes theuncertainty over which costs will be included inthe rate base. When DSM programs were small,outlays were easily handled though expensing.

However, many now argue that expensing is nolonger appropriate and the DSM expendituresshould be ratebased. Expensing does not provideenough security for the utility to develop pro-grams, as the risk of penalty for disallowing costsis stronger than the incentive. As many of theDSM programs include long-lived measures thatare expected to provide savings for many years,proponents of ratebasing believe the programsshould be accorded equal treatment with supply--side options in the ratebase. There are threerecovery methods in use by the States for DSMexpenditures:

Deferment to rate case—variations not ac-counted for in rates are deferred until the nextrate case.Flow through to rates-expenditures notaccounted for flow through to rates via a fuelclause, surcharge, rider or other adjustmentmechanism to rates.Ratebased recovery expenses including gen-eral and administrative costs associated withplarnning and managing DSM programs areadded to ratebase.

DEFERMENT TO RATE CASEThe cost recovery problem is partially ad-

dressed if States allow utilities to defer theamount above the budget until the next rate casewhere it will be considered for the following rateperiod. However, if no carrying charges areallowed, the utility loses any adjustment for thetime value of money. Additionally, the possibilityof 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 RATESSome States have responded by instituting a

balancing account where the utilities recover theoutlays from DSM. The account provides amechanism for the utility to collect from itsratepayers the actual DSM expenditures, withinterest. The accounting may be done througheither the fuel adjustment clause, which recon-ciles actual fuel costs with projected expendi-tures, or a separate account. The balancingaccount ensures recovery, yet does not provide aprofit for underspending. Expensing and costrecovery do not account for revenues losses fromsales foregone because of DSM.

A recent study sponsored by the NationalAssociation of Regulatory Utility Commissioners(NARUC), which surveyed DSM options inMichigan, concluded that balancing account ex-pensing offers advantages over other methods ofcost recovery.

26 The policy g rOUP r e c o m m e n d e d

that Michigan allow receipts to be adjusted up ordown in relationship to expenditures. This wouldbe accomplished by modifying the conservationsurcharge mechanism currently in place. Thistreatment of expenditures minimizes the utility’srisk of cost disallowance and allows timelyrecovery and flexible spending levels. The reportnotes that this mechanism for recovery should belinked with a performance incentive to maximizevalue.

RATEBASED RECOVERYRatebased recovery allows the utility to in-

clude DSM investments in the rate base. Sinceratebased items earn a return, DSM items will aswell. DSM expenditures are capitalized and havean amortization period over which they earn areturn. This allows the benefits to be charged overthe lifetime of the investment. Ratebasing pro-

vides a fair return to shareholders, making iteasier to attract necessary capital. However, it isunlikely that ratebasing alone can stimulate DSMinvestment because every additional kilowatt-hour sold may add to revenues and profits.

Ratebasing of DSM resources creates new risksfor the utility. The potential of cost disallowancein a prudence review may make investors wary.With the perception of risk, needed capital maybecostlier. DSM may be particularly susceptiblesince much of it is not backed by utility-ownedassets unlike the investment in supply-side meas-ures, like powerplants.

There are also considerations for the regulators.There is a higher revenue requirement fromratebasing. It also does not provide any inherentincentive to control costs, except for utility fear ofsubsequent disallowances. Utilities may invest inthe most expensive efficiency measures to maxi-mize their return (’ ‘goldplating’ ‘). Alternatively,in situations where a measure achieves lesssavings than authorized, the utility sells theunanticipated kilowatt-hours and recovers DSMcosts that were not lost.

H Status of State Cost Recovery ProvisionsA 1992 study by the Edison Electric Institute

found that 13 States have authorized deferredrecovery, 19 States have approved a flow-through-to-rates mechanism and 17 States have allowratebasing of DSM programs.27 Table 6-3 showsall the States, but the following States illustratethe diversity of approaches taken to date:

■ Indiana has authorized its utilities to deferDSM program costs with carrying chargesuntil the next rate case and the utility will beallowed to recover costs that appeared cost-effective 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.


Table 6-3-State Regulatory Initiatives for Demand-Side Management, 1992

Ratebase Lost Higher rate SharedState recovery = revenue b Decoupling c 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— — —

—xxx

— — — —xx—

x x —— — — —x—x

x—

x—

———

xx

—x— — —

— — — — —xx

—xx

— —x

— ——x

— —— — — —xxx—

—xx—

— — — ————

— — —xx—

———

—x

— — — —— — — — — —xxxxx

xxx

x xx—

— ———

— —xxx

—x— — —

xx — —— — — —

——

— —— — —— —

x——x

x— ———

——xx

— — —xx

— —x— —

— — — — ——

—x x x x x


expenditures through the fuel adjustmentclause. Any monthly variances will betracked and accrue interest. Cumulative vari-ances will be added to or subtracted fromprojected DSM costs for then next year.31

Colorado has approved ratebasing for thePublic Service of Colorado with a 7 yearamortization period, including expendituresused for load research.32

New Jersey and North Carolina have adoptedregulations to provide for deferred costs,with a return.29

Hawaii, New Hampshire, Ohio, and RhodeIsland have exclusively chosen a balancingaccount for cost recovery for DSM pro- ■

grams. 30

The New York Public Service Commissionwill 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.


Table 6-3-State Regulatory Initiatives for Demand-Side Management-(Continued)

Ratebase Lost Higher rate SharedState recovery. revenue b Decoupling c of return d Bounty • savlngs f

Nevada. . . . . . . . . . . . . . . x x — x — —North Carolina . . . . . . . . — — — — —

North Dakota . . . . . . . . .

—x — — — —

Ohio. . . . . . . . . . . . . . . . . —

—x — — x

Oklahoma . . . . . . . . . . . .

—x — — —

Oregon. . . . . . . . . . . . . . .

— —

x x — — — xPennsylvania. . . . . . . . . . x — — — — —

Rhode Island . . . . . . . . . . — — — — xSouth Carolina . . . . . . . . . —

—— — —

South Dakota . . . . . . . . . . —

— —— — — —

Tennessee . . . . . . . . . . . . ——

— — — —Texas. . . . . . . . . . . . . . . .

—x — — x

Utah. . . . . . . . . . . . . . . . . —

— —. — — — —

Vermont. . . . . . . . . . . . . . x x — — — xVirginia . . . . . . . . . . . . . . . — — — —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: 1992Sourcebook (Washington, DC: Edison Electric Institute, June 1992); National Association of Regulatory Utility Commissioners, Incentives forDemand-S/de Management (Washington, DC: National Association of Regulatory Utility Commissioners, January 1992); and Office of TechnologyAssessment staff research.

■

■

■

The District of Columbia has authorizedratebased recovery of costs over a 10-yearperiod. 33

Iowa has a statute authorizing ratebasing ofDSM, in addition to recovery outside ofgeneral rate cases and adjustments up ordown based on perforrnance.34

Maryland has approved ratebasing for one of

At least ten States give the utilities a choicebetween ratebasing and expensing.36

■ In Massachusetts DSM programs costs canbe expensed or capitalized as they areincurred dollar-for-dollar and are tracked bya separate account. Actual DSM expendi-tures are charged against the fund monthly.The commission has stated that cost-

its utilities with a 5-year amortization period recovery will be linked to performancefor 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 ACEEESummer 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)

Underrecoveryof costs andearnings

Revenues(contributions tofixed costs andearnings)

Fixed costs(includingaIlowedearnings)

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 theauthorized return on the rate base. This is shown above as the intersection of the two lines labeled fixedcost andcontribution to fixed rests and earnings. If sales are lower than assumed for the test year, theutility will not recover its fixed costs or earn its authorized rate of return (shaded area to left of intersectionpoint). If, however, sales are higher than projected, the utility will recover its fixed costs and earn morethan 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 Manage-mentIncentive Regulation: Status and Current Trends (Washington, DC: Edison Electric Institute, March 1991 ), p. 8.

Vermont has established an account entitledthe Account Correcting for Efficiency, amechanism for the recovery of DSM expen-ditures which can be ratebased or expensed.38

Washington allows net conservation costs tobe placed in rate base, earning a rate ofreturn, although the return can only beapplied to pre-identified conservation amountssubject to review. Any conservation invest-ment made after the cutoff date will not beallowed in the rate base, but will be allowedto accumulate a carrying charge equal to thecompany net-of-tax return.

Cost recovery approaches are a frost step toremoving the barriers to investments in demand-side efficiency. Both ratebasing and expensingwith a return address regulatory lag, allowingutilities to recover freed costs. However, the

inherent regulatory incentive to sell rather than tosave power remains .39

1 Lost Revenue Incentives

Lost revenue is a primary constraint to utilityadoption of significant DSM programs. Thelosses arise when the utility under-recovers itsfixed costs due to a successful DSM program thatreduces kilowatt-hour sales. The utility sells lesspower than is forecasted and receives lowerrevenues, directly reducing profits. The moresuccessful the DSM program, the greater the loss(as shown in figure 6-3). Such programs undertraditional ratemaking work against the utilities’financial interests. While some States have ad-dressed 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.


21 other States have authorized utilities to recoverthe lost revenue attributed to DSM success.40

DSM SPECIFIC ADJUSTMENTThis mechanism provides a method for the

utility to recover the estimated amount of lostrevenue specifically attributable to DSM. Fre-quently, it involves an incentive/disincentivecombination. One way it works is to set a DSMgoal for the utility. If the goal is met, the utilityreceives the lost revenue. However, if perform-ance is not met, the utility forgoes the lost revenueto the ratepayers. States including Indiana andMaryland have allowed for recovery of lostrevenue. The other States are listed in table 6-3.

Although DSM specific adjustment removesthe disincentive to investment in DSM, the utilitystill benefits from selling additional kilowatt-hours. The most profitable programs under thisadjustment alone are those that look good onpaper and save nothing.

Indiana has approved recovery of lost revenuefor a utility, PSI Energy. The utility is authorizedto defer, with carrying charges, recovery of therevenue attributable to DSM programs. There isa stipulation that the DSM programs be prudent.Then, at the next general rate case, recovery isconsidered. 41 For Southern Indiana Gas andElectric, another utility in the state, a “lostmargins tracker’ mechanism was approved, op-erating similarly to a fuel adjustment clause.

The Maryland commission has authorized lostrevenue recovery for the Potomac Electric PowerCompany (PEPCO) to be incorporated into thecost recovery mechanism. Lost revenues areestimated through the reduction in demand andenergy consumption attributed to the DSM pro-grams. The revenue recovery mechanism is the

‘‘DSM Surcharge,’ which is calculated annuallybased on program cost projections and the fore-casted sales. The surcharge rider is then appliedon years when PEPCO’S return on rate base isbelow the authorized return. If the return on ratebase is greater than the authorized return, allprogram costs, including lost revenue, are de-ferred until such year the rider is applicable.42

I Performance IncentivesStates have begun to combine the mechanisms

to reimburse expenses and lost revenues withfurther incentives to encourage better perform-ance in DSM programs. Some States rewardutilities shareholders with a monetary bonus orreward for successful DSM efforts. Proponents ofshareholder incentives say that the mechanismsstimulate expanded utility development of con-servation and load management programs. On theother hand, opponents of the incentives say thatthe mechanisms may lead to increased customercosts and that DSM development could drive upshort-term rates.

Since Wisconsin first passed a shareholderincentive in 1987, 17 States have authorizedincentives for a total of 36 utilities. An additional5 States have approved generic incentives and 5more States have proposals under considera-tion.43 However, the Florida commission decidednot to initiate a rulemaking on incentives. Itshould be noted that utilities, State collaborative,and State legislators have also been the initiatorsfor incentive proposals. Wisconsin was also thefrost State to determine that DSM in 1992 hasdeveloped to the extent that shareholder incen-tives were no longer necessary. The States thathave 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: AmericanCouncil for an Energy Efficient Economy), p. 8.23.

“ ——


that are historically receptive to regulatory inno-vation. 44

Studies have shown that utilities with incen-tives have increased their DSM expenditures andsavings. Diverse approaches have been tried inorder to stimulate performance including varyingbonuses on rates of return, bounties, and shared-savings mechanisms.

RATE OF RETURN ADJUSTMENTSThe rate-of-return adjustment, either on the

total return or just to the equity portion, is linkedto a DSM target level of performance. Under thisapproach, the regulatory agency adjusts the returnbased on the performance of DSM programs-ahigher return with better performance and a lowerreturn with poorer performance. Although theconditional bonus requires increased oversightfrom regulators, it offers advantages over otherrate-of-return adjustments. Its structure is com-patible with the least-cost policy by discouragingoverly expensive, ineffective DSM programs.

Rate Base PremiumThis mechanism allows a return over and above

the rate allowed on supply-side investments forratebased DSM expenditures. This is the moststraightforward approach applied by commiss-ions. A utility is provided an incentive to investin DSM when it is granted an overall increase inits return. Rates are maintained as with conven-tional regulation, except ratebased investment inDSM has been included and a higher rate of returnhas been allowed. It is also a strong penaltymechanism when overall return is decreased dueto an absence of DSM investment. Although thepenalty is regarded as effective, this approach isviewed by some as too liberal an incentive.Hawaii, Idaho, Michigan New York, Texas, andWashington have each instituted this incentive(see table 6-3).

Incentive mechanisms approved in 1989 and1990 in New York for seven utilities providebonuses of 5 to 20 percent of net savings fromDSM in addition to lost revenue adjustments,although the incentive has been capped at anamount equal to an additional 0.75 percent returnon equity. The Orange and Rockland Company,a utility in New York, is operating under aformula that determines rate of return based onnet savings in both dollars and kilowatt-hoursresulting from DSM. The utility has a goal ofcutting electricity consumption 8 to 10 percent. In1990, the utility estimated that it would spend$4.3 million on DSM, with avoided cost benefitstotaling $658,000. Orange and Rockland wouldcapture $45,000 in bonus the first year.45 TheNew York Commission is reviewing the incen-tives to determine a way to develop a uniformincentive for all New York utilities, primarily forequity and greater administrative ease.46

Return-on-Equity Adjustment

This mechanism adjusts the allowed return onequity to reward or penalize a utility based itsrelative progress in developing DSM programs.Under this approach, the penalty or bonus is onlyapplied to the return on the DSM portion of therate base, The reward is more in step with what isconsidered appropriate, but a penalty could bemeaningless, Should a utility not pursue DSM,the consequences would be minimal since theportion of the rate base affected by the penaltywould be inconsequential. Like the first approach,the cost-effectiveness of programs has not beenincorporated.

Connecticut, Hawaii, Kansas, Montana, andWashington all have statutes permitting a bonusreturn on DSM (see table 6-3). Washington’s1980 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.


basis points above other utility investments.47

Connecticut’s 1988 statute authorizes an addi-tional 1 to 5 percent rate of return on ratebasedDSM. In a 1990 order, Connecticut also imple-mented a variable bonus of 1 to 3 percent basedon program cost-effectiveness and a partial salesadjustment mechanism.%

BountyUsing a bounty mechanism, the utility is given

a predetermined payment for exceeding a set goal.The goal can be in terms of estimated savings oractual savings and the reward can be eithercents/kilowatt-hour or dollars/block of powersaved.49 It is similar to adjusting the rate of returnfor performance, in that program success is thecritical factor. States adopting this approachinclude Massachusetts, Michigan, Minnesota,New Jersey, and Washington.

In Massachusetts, any savings above 50 per-cent performance is rewarded through a bonus oneach additional kilowatt and kilowatt-hour saved.50

Massachusetts Electric, for example, could re-ceive $5.25 million in bonuses if it fully meets its1990 DSM impact targets. Michigan is similarexcept that it adds a sliding scale to the bonus.51

Shared SavingsThis 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 forprogram success. Shared-savings arrangementsare best suited for retrofit and some new construc-tion measures since those involve hardware witha measurable energy value. It has frequently beenselected by both regulators and utilities.

However, the incentive requires a high degreeof regulatory supervision to monitor results. Themechanism has three components: the cost of theprogram, the amount of attributable energy sav-ings, and avoided cost.53 Since the mechanismworks by allowing the utility to keep a portion ofthe difference between the costs of the DSMresources and avoided cost of an alternativesupply resource, quantifying is very important. Atotal of 17 States, as shown in table 6-3, haveapproved this incentive for their utilities. Exam-ples of approved mechanisms follows:

9

9

■

In Rhode Island with a committee consistingof utilities, commission staff, and governor’sstaff approved a plan that provides a bonusbased on shares of gross and net programsavings (5 and 10 percent respectively). Thebonus is earned after a savings threshold ofapproximately 50 percent of program goalshas been achieved.54

An Iowa utility can earn up to 25 percent ofnet benefits.55

Maryland permits a bonus of 5 percent ofsavings if performance exceeds the programgoals 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.


California after experimenting with severalincentive mechanisms has decided that all ofits utilities will be eligible for a shared-savings incentive.57

Vermont authorized a shared-savings bonusthat allows utilities to retain 10 percent of netprogram savings.58

1 PenaltiesSome States have coupled the performance

incentives with penalties for poor performance orcostly DSM programs. The risks of prudencereviews and cost recovery disallowances havetraditionally been associated with investments insupply-side investments. However, with growingDSM expenditures, adequate results from invest-ments are essential. The States that have pairedthe penalty with the incentives are the ones withfull-fledged IRP plans. The penalties are associ-ated with shared-savings programs, return-on-equity adjustments, and megawatt savings tar-gets.

The penalty associated with shared savings isattached to failing to meet minimum performancestandards in California and Maine. California’smajor utilities are each subject to penalty. TheState utility commission granted Pacitic Gas andElectric a shared-savings incentive conditional onits meeting minimum performance standards. Thestandard was set at a predetermineed level of netpresent value of lifecycle benefits. If the minim-um standards are not met, the utility pays apenalty equal to 15 percent of the variance. ForSan Diego Gas & Electric, the penalty is alsoassociated with the shared-savings incentive.However, instead of the penalty being assessed onnet present value, the penalty is equal to the fill

total resource cost value of the gap. In 1991, thepenalty equaled 40 percent of the difference. Inaddition to the performance standard there is alsoa cost standard. If the utility exceeds its programcosts, set by a dollar/kilowatt-hour, it must pay 20percent of the difference as a penalty .59

In New York and Michigan, the penalty isassessed on the utility’s return on equity whenannual goals are not met. The New York commis-sion assesses a return-on-equity-based penalty ifthe utility fails to meet annual goals establishedfor DSM. In order for Consolidated Edison andOrange and Rockland to avoid a set number ofpercentage points downward adjustment, theymust achieve 40 percent of their energy savingsgoals.60 The Michigan commission went a step

further. Consumer Power’s potential penalty isgreater than its potential reward and is based onreturn on equity. If the utility does not meet theminimum cost-effectiveness target, it is subject toa 2 percent return-on-equity penalty, while if itexceeds the target it will receive a 1 percentreturn-on-equity reward. The commission stated:

Consumers (Power) is. . .a regulated monop-oly with an obligation to meet its customers’needs. The penalty for failure to meet thisobligation should therefore be greater than anyadditional incentive for achieving the goal.61

The Washington commission has yet anotherapproach. Puget Power and Light must achieve aminimum of 10 average megawatts saved. Foreach megawatt not saved below that amount, theutility will pay $1 million. If the utility fails tocapture 6 megawatts of savings the penalty iseven greater, $1.25 million per average megawattbelow 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.


Table 6-Hate Energy Research and Development Programs

Fund ing- Program focus useState agency Established Type ($ OOOlyr) Source of fundsb

New York State EnergyResearch and DevelopmentAdministration

California institute forEnergy Efficiency

California Energy Commission

Florida Solar EnergyCenter

Iowa Energy Center

Kansas Electric UtilityResearch Program

Minnesota Building ResearchCenter

North Carolina AlternativeEnergy Corporation

Wisconsin Center forDemand-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 overchargetrust fund

Nonprofit 3,100 Utility contributions

Nonprofit 2,200e Utility contributions

Energy supply & end-use,waste management researchand development (R&D)

Electric & gas end-useefficiency R&D

Renewable and con-servation technologies,commmercializationmatching grants & loans

Solar, renewable, end-useefficiency

Efficiency and renewableR&D

Electricity supply andend-use R&D

Building energy use effi-ciency and indoor air quality

Efficiency and renewablesR&D and outreach

R&D on DSM technologiesand program savings; mar-ket 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 EnergyEfficiency 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 perform-ance penalty and incentive measures are a recentaddition in the regulation of demand-side invest-ments.

ENERGY EFFICIENCY RESEARCH ANDDEVELOPMENT PROGRAMS

In addition to regulations and statures, Stateshave also established programs that support

efficiency utility DSM programs and other energyefficiency efforts through research and develop-ment. There are currently eight States with energyresearch and development programs. Total spend-ing by these programs has been $39 millionannually.63 Table 6-4 describes the characteristicsof the existing programs. These programs primari-ly focus on implementing new efficiency tech-nologies. Box 6-E highlights aspects of Stateprograms.

63 Jefieyp. WS, Arthur H. Rosenfeld, Cad Blurnstein, and John wOne, ‘‘Creating Institutions for Energy Efficiency R&D: New Rolesfor States and Utilities, ” ACEEE 1992 Summer Sfudy on Energy Eficiency in Buikiings, vol. 6 (Washington DC: American Council for anEnergy-Efficient Economy, 1992), p. 6.91.


Box 6-E—Profiles of Selected State Energy Research and Development Programs

New York State Energy Research and Development Authority (NYSERDA): NYSERDA established in1975, is one of the oldest State energy research arms. It is also one of the largest supporting a staff of around80. There are four research programs: industrial efficiency, building systems, energy resources and municipalwastes. 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 energyresearch arm It primarily funds medium to long-term projects though the State university system and nonprofitresearch centers including the national laboratories in the State. All projects must have an element of technologytransfer to be approved. The multiyear projects make up two-thirds of the budget and must include two or moreresearch centers. Current efforts inc!ude projects on building energy efficiency, potential for end-use efficiency toimprove air quality in urban areas, and end-use resource planning. Although none of the multiyear projects areyet complete, progress reports note success. For example, a project on thermal performance and air leakage inresidential ducts has already developed new measurement methods, better techniques for quantifying overallenergy 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 includeall renewable and energy-efficient technologies. Unlike may of the other State research centers, FSEC work isprimarily done in-house with a staffof 137. Research efforts include energy-efficient buildings, photovoltaics, solarthermal systems, other advanced systems for renewable energy and end-use efficiency, field monitoring, andeducation and training.

Wisconsin Center for Demand-Side Research (WCDSR): The WCDSR is an independent, nonprofitorganizatlon established in 1990. It sponsors and coordinates applied research in demand-side management. Thismission includes support for the development of demand-side technologies and markets, for the evaluation of utilityprogram 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 Rolesfor States and Utilities,” ACEEE 1992 Summer Study on Energy Efficiency in Buildings, vol. 6 (Washinglon, DC: Arnerican Council for anEnergy-Efficient Economy, 1992), pp. 6.91-6. 102.

— —

FederalPrograms 7

T he Federal Government sponsors a wide range ofprograms that support electric utility energy efficiencyinitiatives. Most of the programs are concentrated in theU.S. Department of Energy (DOE), however several

other Federal agencies, including the Environmental ProtectionAgency (EPA), the Rural Electrification Administration (REA),and the Tennessee Valley Authority (TVA), also administerenergy efficiency efforts. Federal programs include those thatdirectly encourage the development and adoption of utilityintegrated resource planning (IRP) and demand-side manage-ment (DSM) efforts such as DOE’s Integrated Resource Planningprogram and the initiatives of the Federal power marketingadministrations. Other programs with a more indirect contribu-tion to utility energy savings include energy supply and demandresearch 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 morenotable Federal programs.

THE FEDERAL GOVERNMENT AND ENERGY EFFICIENCYThe strong Federal interest in energy efficiency arises from the

importance of reliable and economic electric power productionto the economy, concerns over the environmental impacts ofpower production, and the Government diverse roles ofwholesale power producer, utility regulator, and utility customer.The Federal mission for encouraging energy efficiency throughelectric utilities is based on both legislative and executiveactions. Over the past two decades, Congress has passed anumber of laws that either directly or indirectly affect consumerelectricity demand or utility resource planning and operations.

I 143


For example, electric utility involvement inhelping customers to save energy was givenimpetus by the National Energy ConservationPolicy Act,l which required utilities to provideinformation on energy conserving measures totheir residential customers and to offer energyaudits. The act also established Federal minimumenergy efficiency standards for appliances such asrefrigerators and fluorescent lamp ballasts, even-tually contributing to lower electricity consumpt-ion per unit. Table 7-1 lists some of the majorlegislation shaping Federal energy efficiencyprograms and policies. The Energy Policy Act of1992 builds on many of these existing programs,for example, expanding Federal support for Stateand utility energy efficiency efforts and extendingbuilding and appliance energy efficiency stand-ards. 2

On the executive side, President Bush’s 1991National Energy Strategy (NES) embraced en-ergy efficiency as a key resource in meeting futureenergy needs. The NES set forth two goals forFederal programs related to electricity generationand use: to “encourage efficiency and flexibilityin electricity supply and demand choices, ” and to“promote diversity of electricity technology andfuel choices. ”3 It listed a variety of policyinitiatives to achieve those goals. Among themwere DOE-led efforts to support reform of Fed-eral and State utility regulation to encouragewider use of IRP and DSM and an expandedcommitment to R&D on improved methodologiesfor measurement and evaluation of IRP and DSM

efforts. In other areas, Federal R&D and demon-stration activities designed to improve the relia-bility of electrotechnologies and the cost-effectiveness of energy resources, including re-newable energy technologies, could contribute toimproved efficiency of electricity use and produc-tion.4

Federal support for energy efficiency R&D (asidentified in the NES) is shown in table 7-2. Outof total funding of some $1.2 billion requested inFY 1993, only about $6 million was allocated todirect support for electric utility energy efficiencyinitiatives. Some indirect contributions to utilityenergy efficiency efforts may flow from theroughly $150 million in consumer energy effi-ciency under building energy R&D programs andfrom the hundreds of millions of dollars expendedfor R&D in fossil, nuclear, and renewable energypower generation.

The Clinton Administration has also givenenergy efficiency a high priority and has proposedincreased spending on several Federal energyefficiency programs as part of its economicstimulus plan and budget requests

US. DEPARTMENT OF ENERGYPROGRAMS

DOE’s responsibility for formulating nationalenergy policy and implementing energy conser-vation and efficiency programs make it the leadFederal 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 millionfor the low-income weatherization assistance, and $19 million for model projects for commercializing building energy conservationtechnologies. The proposal would also allocate $14 million to improved energy efficiency in Federal Gov ernment facilities and $23 millionfor 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 Law94-163, December 22, 1975, 89 Stat. 870, 42U.S.C. 6201 et seq., as amended)

Energy Conservation and Production Act (PublicLaw 94-385, August 14, 1976, 90 Stat. 1125, 42U.S.C. 6801 et seq., as amended)

National Energy Extension Service Act (PublicLaw 95-39, Title V, June 3, 1977, 91 Stat. 191, 42U.S.C. 7001 et seq., as amended)

National Energy Conservation Policy Act (PublicLaw 95-619, November 9, 1978, 92 Stat. 3206, 42U.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, asamended)

Energy SecurityJune 30, 1980, 94

Act 1980 (Public Law 96-294,Stat. 611 )

Pacific Northwest Electric Power Planning andConservation 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 mandat-ory).

Establishes State Energy Conservation Program.

Provides Federal technical and financial assistance for developmentand implementation of State energy conservation plans.

Establishes Weatherization Assistance Program to fund retrofits forlow-income households.

Required mandatory building energy efficiency standards for all newbuildings (later made voluntary for nonfederal buildings).

DOE to support innovative electric utility rate design initiatives anddemonstrations to encourage energy conservation.

At State request, authorizes DOE to intervene or participate in Stateratemaking proceedings.

Provides financial assistance for State consumer services offices toparticipate in State regulatory hearings.

Establishes Energy Extension Service to fund State and local energyinformation, training, and demonstration programs.

Establishes Residential Conservation Service and institutional Conser-vation Program.

DOE to approve State plans requiring regulated utilities to implementresidential energy conservation programs offering audits, information,and financing.

Extends residential mortgage credit for energy conservation and solarenergy improvements through Federal housing finance programs.

Imposed restrictions on use of natural gas and oil as primary fuels inexisting and new powerplants (most provisions later repealed).

Amends Federal Power Act to require State public utility commissionsto consider adopting various energy conservation and ratemakingstandards.

Amends Energy Conservation and Production Act to provide Federalgrants to States to carry out new requirements.

Requires utilities to interconnect with and purchase power fromqualifying small power producers and cogeneration facilities.

Amends National Energy Conservation and Production Act residentialconservation programs to require warranties for conservation measu-res, cap audit fees at$15, and limit utility installation of conservationmeasures.

Establishes DOE residential energy efficiency demonstration program.

Establishes Commercial and Apartment Conservation Service (CACS).

Establishes the Pacific Northwest Power Planning Council to developregional conservation and electric power plans to guide BPA resourceacquisition.



Table 7-l-Selected Federal Legislation: Energy Efficiency and Electric Utilities+Continued)

Omnibus Budget Reconciliation Act (Public Law97-35, 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 (PublicLaw 99-412, August 28, 1986, 100 Stat. 932)

Powerplant and Industrial Fuel Use Act of 1978,Amendments (Public LawStat. 310)

00-42, May 21, 1978, 101

National Appliance Energy Conservation Act of1987 (Public Law 100-12, March 17, 1987, 101 Stat.103)

Renewable Energy and Energy Efflciency Technol-ogy 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 withthe regional plan and to encourage cost effective energy conserva-tion and renewable energy resources.

Gives priority to conservation and renewable energy sources inBPA resource plans.

Requires Council and BPA to collaborate on and implement a fishand wildlife protection plan.

Amends the Powerplant and Industrial Fuel Use Act to allow DOEto ban the use of oil or natural gas in new powerplants wherealternatives exist.

Requires electric utilities using natural gas as a primary source toimplement a conservation plan that will reduce at least 10 percentof 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 non-federal buildings under the Energy Conservation and ProductionAct.

Requires Western Area Power Administration long-term firm powerservice contracts to require customers to develop and implementenergy conservation programs.

Amends National Energy Conservation Policy Act.

Reforms the Residential Conservation Service and extends itsexpiration to 1989.

Eliminates requirement that utilities arrange for conservation meas-ures installation and related loans.

Allows States to develop alternative conservation plan for residen-tial buildings.

Abolishes the Commercial and Apartment Conservation Service.

Repeals and amends certain sections of the 1978 Act restrictingutility use of oil and natural gas.

Requires that no new electric powerplant may be constructed oroperated as a base load powerplant without the capability to usecoal or other alternative to petroleum as a primary energy source,unless it receives an exemption.

In absence of DOE implementation, establishes mandatory mini-mum energy efficiency standards under Energy Policy and Conser-vation Act and requires DOE to update standards periodically.

Adds additional appliance categories for which standards must bedeveloped.

Directs DOE to participate in cost share joint venture demonstra-tions of renewable energy and advanced district cooling technolo-gies.

Establishes cost and performance goals for Federal wind, pho-tovoltaic, and solar thermal research programs.


—..


Table 7-2—National Energy Strategy Funding Levels for Energy Research and DevelopmentFiscal Years 1991-93 ($ millions)

FY 1991 FY 1992 FY 1993 FY 1991-93Research area actual enacted requested percent change

Surface transportation efficiencyTransportation 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 IndustryIntegrated resource planning. . . . . . . . . . . . . . . .Industry efficiency. . . . . . . . . . . . . . . . . . . . . . . . .Alternate industry feedstocks. . . . . . . . . . . . . . . .Buildings energy technologies. . . . . . . . . . . . . . .

Total. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Advanced electric technologyMunicipal solid waste. . . . . . . . . . . . . . . . . . . . . . .Cogeneration. . . . . . . . . . . . . . . . . . . . . . . . . . . . .Photovoltaics. . . . . . . . . . . . . . . . . . . . . . . . . . . . .Other solar and renewable. ... , . . . . . . . . . . . .Superconductivity. . . . . . . . . . . . . . . . . . . . . . . . .Advanced light-water reactors. . . . . . . . . . . . . . .Advanced reactor concepts. . . . . . . . . . . . . . . . . .Advanced reactor facilities. . . . . . . . . . . . . . . . . .

Total. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Grand total. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Total DOE.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

$21,615.825.0

7.623.012.058.0

$163.0

$51.635.0

$86.6

$13.628.731.715.9

$89.9

$ 3.078.90.3

44.9$127.1

$ 0.04.1

46.4103.4

18.644.361.391.1

$369.2

$835.8

$660.2

$23.516.842.9

9.627.520.092.0

$232.3

$63.032.0

$95.0

$ 17.434.836.912.6

$101.7

$ 3.992.2

0.549.4

$146.0

$ 1.63.2

60.4123.022.062.559.597.8

$ 430.0

$1,005.0

$ 782.5

$26.417.575.311.537.528,0

123.0$319.2

$68.046.0

$114.0

$31.746.446.540.0

$164.6

$ 6.095.7

2.054.5

$158.2

$ 4.03.5

63.5113,622.558.750.095,1

$ 410.9

$1,166.9

$ 878.4

22.20/010,8

201.251.663.0

133.3112.195.8%

31 .8%31.431.670

133.1 %61.746.7

151.68 3 . 1 %

1 00.0%21.3

566.721.424.50/.

NA-14.6%36.99.8

21.032.5

-18.44.4

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 forAmerica: One Year Later,” DOE/S--92008000, February 1992, p. 5.


at electric utilities.6 The primary DOE programsinvolving electric utilities are under the 0ffice ofthe Assistant Secretary for Energy Efficiency andRenewable Energy (formerly Conservation andRenewable Energy). The R&D and technologytransfer efforts of the Office of Fossil Energy, theClean Coal Technology Program, and the Officeof Nuclear Energy, also offer some benefits forincreasing the energy efficiency, cost-effective-ness, and environmental compatibility of utilitypower generation options.

Federal support for energy conservation andefficiency has varied significantly, usually re-flecting shifting political priorities. From FY1980 to 1990, appropriations for DOE conserva-tion R&D, where much of the utility-relatedenergy efficiency R&D is focused, fell by morethan half. The Bush Administration and Congressreversed that trend, but in real terms, DOE’sconservation R&D budget in FY 1991 was only60 percent of what it had been in FY 1980.

In FY 1992, DOE budgeted an estimated $426million on programs that the General AccountingOffice (GAO) identified as promoting conserva-tion and efficiency in the use of electricity andother forms of energy.7 While marking an in-crease over prior years, this budget level was only11 percent of the $3.8 billion in funds allocated toenergy supply technology R&D. Adjusted forinflation, DOE’s FY 1992 conservation R&Dbudget was some 18 percent lower than in 1980.8

Moreover, within the conservation R&D pro-grams, the emphasis has shifted fro buildingsand utility systems technologies to transportationand renewable energy technologies and to longer-term, high-risk research on industrial processesand materials, and superconducting materials.9

Determining g what portion of Federal spendingactually supports electric utility energy efficiencyinitiatives or technology development is not easy.DOE programs have multiple goals, and improvi-ng energy efficiency is often a minor objective ofDOE energy supply and demand technologyprograms. According to a GAO analysis, DOE’sFY 1993 budget request to Congress reflectedsome $2.1 billion in civilian R&D identified byDOE as supporting the NES objective of “im-proving electric efficiency.”l0 A more detailedbreakout of the proposed spending showed $1.2billion related to various DOE civilian nuclearprograms (including light water reactors, high-efficiency and ultrahigh-efficiency power sys-tems, fusion energy, first repository, monitoredretrievable storage facility, and nuclear facilities).The Clean Coal program and renewable energysystems accounted for an additional $644 million.Altogether, demand-side efficiency programs (in-cluding $50 million for unspecified ‘‘utilitydemand efficiency,” $26 million for industrialprograms, and $27 million for buildings effi-ciency programs) made up less than 0.5 percent ofthe 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 ageneiesunder a single department. DOE absorbed the Energy Research and Development Administration the Federal Energy Administ.ratioq theFederal 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 FederalPower 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 byPetroleum 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 EnergyEfficiency). See also, Fred J. Sissinc, Congressional Research Service, “Energy Conserv at.ion: ‘Rd.nieal Efficiency and ProgramEffectiveness,” 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.


rI I

I PowerAdministratlons

4 ‘--- ‘ -- “ -Alaska

k—-~ Southeastern

-i Southwestern.—

~ Bonneville

I 1--- ----------‘- { Western Area.———— ——— ——

Figure 7-l-Organization Chart of DOE’s Assistant Secretary forEnergy Efficiency and Renewable Energy

A Assistant Secretary

I Principal Deputy

Office ofManagement and

Resources

IOff Ice of

I Alcohol Fuels

L-—

1

-[ -

---r---:Off Ice of

Utillty

LTechnologies

Office ofIndustrial

Technologies

—IntegratedResourcePlanningProgram

I Office of-1 Waste

L

ReductionTechnologies

-LOffice ofRenewable

EnergyConversion

~–

Off Ice of)- Solar Energy

1

Conversion

~–—–I Office of

-1

:

EnergyManagement

I,-- --

I

Y Off Ice ofI n d u s t r i a l

ProcessesL - - — — – – — J

Assessment J

T— ‘- — - - - ‘-1

J Off Ice ofI Transportation

Technologies

I Off Ice of+ Propulsion

I ~---- 1I Office of

-–1 A l ternateFuels

Off Ice ofAdvanced.—

Transportation~ Materials—.

I office ofBuilding

Technologies

IOffIce ofBuildingsEnergy

Research

-i

Off Ice ofCodes andStandards

L –-.— . .

Off Ice ofFederalEnergy

Management

~-. .~Off Ice of

r

Technical andFinancial

Assistance

LrOff Ice ofNational

J!!!a:s–—.

Off Ice of— Grants

Management—

——— . — ..——~ Off Ice of

,—.

1. - - - - - -

TechnicalAssistance

—-

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 marketingRenewable Energy agencies and Federal technical and financial

assistance programs.11 As shown in figure 7-1, the

The Office of the Assistant Secretary forEnergy 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 Trans-

renewable energy technologies, end-use energy portation Technologies, plus Technical and Fi-

efficiency, 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 ofUtility Technologies, FY 1992

AppropriationsPrograms: ($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. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

86.721.1

4.460.4

1.2

4.0

37.73.15.05.4

22.01.40.8

50.621.4

1.026.2

2.0

SOURCE: Office of Technology Assessment, 1993, based on datafrom U.S. Department of Energy, Assistant Secretary for Conservationand Renewable Energy, “Conservation and Renewable Energy Technologies for Utilities,” DOE/CH10093-865 (prepared by the NationalRenewable Energy Laboratory, Golden, CO), April 1992, p. 5.

The Office of Utility Technologies a dministersprograms dealing with utility systems, IRP, DSM,and renewable energy technologies R&D. Otherprograms also fund activities that can contributeto utility energy efficiency efforts. The Office ofBuildings Technologies and the Office of Indus-trial Technologies direct programs that are de-signed to improve the energy efficiency ofbuilding and industrial systems and related proc-esses primarily through support of R&D andinformation projects. The 0ffice of Technical andFinancial Assistance promotes the use of renew-able energy and energy-efficient technologies andpractices through technology transfer, grants,

cooperative activities with State and local gov-ernments and private and nonprofit organizations.

Office of Utility TechnologiesThe Office of Utility Technologies, created in

the FY 1990 DOE restructuring, manages variousprograms to encourage the development andadoption of cost-effective energy efficiency andrenewable energy technologies (see table 7-3).12

The office has four utility-related research, devel-opment, demonstration, and technology transferprograms:

The Integrated Resource Planning Program,which deals with all aspects of utility plan-ning and operations;The Office of Solar Energy Conversion,which promotes the development and adop-tion of solar thermal, photovoltaic, andbiomass energy technologies;The Office of Renewable Energy Conver-sion, which promotes wind, hydroelectric,geothermal, and ocean energy systems; andThe Office of Energy Management, whichmanages research to improve the efficiencyand reliability of electricity delivery andstorage systems.

of the foregoing programs share the broadgoals of ensuring that energy conservation andDSM programs are considered equally with newsources of supply, reducing institutional con-straints deterring adoption of energy efficiencyand renewable energy technologies, and expand-ing cooperative efforts with utilities and privateindustry to realize the large market potential ofthese energy resources.13

Integrated Resource Planning ProgramThe IRP Program was established to encourage

the development and implementation of IRPprocesses to ensure that cost-effective energy

12 U.S. wp~ent of Energy, Assistant Secretary for Conservation and Renewable EnerW, “Conservation and Renewable EnergyTbclmclogies 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.


conservation and DSM programs are consideredequally with new sources of supply .14 The IRPProgram encourages utilities and State regulatorsto use resource planning and regulatory ap-proaches that emphasize electricity conservationand efficiency.

The IRP Program has evolved from the Least-Cost utility Planning Program (LCUP), estab-lished in 1986 in response to congressionaldirectives. The LCUP Program was setup to aidthe adoption of least-cost planning through tech-nology transfer to utilities, regulators, consumers,and government agencies. 15 The current structureof the IRP Program has gradually evolved overthe past 8 years to support three activity areas:

E Planning Processes--developing methodsthat will integrate regulatory and DSMprograms into utility planning;

■ Demand-Side Management—working to easeadoption of DSM by utilities; and

■ Regulatory Analysis--examining the eco-nomic regulatory environment and its barri-ers to demand-side investment.

The IRP Program has a very small staff (2full-time equivalents in FY 1993), and thus, littleinstitutional presence; its program efforts focuson channeling Federal funds for technical assist-ance and information transfer to State regulatorsand utilities. Program activities are primarilycarried out through arrangements with severalnational laboratories to direct research, to managegrant applications and awards for cooperativeresearch efforts and other cost-shared research.l6

The IRP Program has underwritten various con-ferences, workshops, publications, and trainingprograms on IRP and DSM in collaboration withthe National Association of Regulatory UtilityCommissioners, the Edison Electric Institute, the

Electric Power Research Institute, and similarorganizations. The program has funded workevaluating and measuring utility DSM energysavings and the reliability of energy-efficienttechnologies. The program also is supportingdevelopment of analytical tools and methods forcomparing the costs and benefits of variousenergy production and consumption options,including methods for incorporating total fuel-cycle analysis and consideration of environ-mental, social, and other external costs in utilityresource plannin g. In recent years, the programhas underwritten efforts to expand the applicationof IRP and DSM concepts to local gas distributionutilities. Table 7-4 shows selected projects sup-ported in FY 1991. The program continues tosupport similar efforts today. According to IRPprogram representatives, requested budget in-creases will be passed through to support ex-panded activities through national laboratoryprograms and perhaps some additional directresearch contracts.

Among its most successful early efforts ac-cording to program officials were the creation oforganizations that have continued, independentlyof DOE funding, to promote LCP objectives. Oneof these projects, NORDAX, a regional utility-sponsored DSM data exchange is discussed inbox 7-A.

For most of its history, the IRP Program hashad an annual budget of some $1 million, risingto $3 million for FY 1992-93, as shown in figure7-2. With this modest budget, DOE has defined itsrole as the gatherer and disseminator of informa-tion. DOE requested a 50 percent increase for theIRP program for FY 1993 for a total of $6 millionto fund additional research and information activ-ities. 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~ onScience 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 iIICalifornia, and the National Renewable Energy Laboratory in Colorado.

330-075 : QL 30- 93 - 6


Table 7-4-Recipients, Research Topics, and Funding ofDOE Integrated Resource Planning Program Projects, FY 1991

Lawrence Berkeley LaboratoryGas 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 LaboratoryFundamentals 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 LaboratoryRenewable 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 technologiesRenewable resource technologies IRP ($198,000)

Bangor Hydro-ElectricDevelopment of a Market Implementation Strategy for Water and Space Heating Technologies (n/a)

Burlington Electric DepartmentSmall 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)

—


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 & ElectricAssessment of New York State Farmstead DSM (n/a)

Northeast UtilitiesEvaluation of the Effectiveness of a Low-Income Weatherization Program for Rural Customers (n/a)

Washington Electric Cooperative, VTIntegrated 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 $6.8million.17

Although the program is small (two full-timestaff members) and expenditure levels practicallyinvisible within the overall DOE budget, DOE,nevertheless, has projected significant energysavings from its investment. DOE has projectedthat in the next 10 years, the program willcontribute up to 30,000 MW reduction in other-wise necessary supply options. (The estimatesassume that adoption of IRP will spur utilities togreater investments in more efficient generatingtechnologies and expanded electricity savingsfrom utility DSM programs.) In the longer run,according to DOE, this could amount to 80,000MW, with over 4 quads of primary energy savedannually. 18 DOE’S announced program goal1992 was to increase the number of States withcomprehensive IRP from 15 to 40 by the year2000. 19 DOE was silent on the mechanisms foraccomplishing its IRP implementation goals. Asnoted in chapter 6 of this report, State progress inadopting and implementing IRP requirements fortheir jurisdictional utilities has been accelerating,

even in the absence of expansive Federal pro-grams or Federal regulatory requirements. OTAestimates that more than 30 States have estab-lished IRP policies (see ch. 6).

Evaluation of the effectiveness of the IRPProgram has been limited. A 1989 review by OakRidge National Laboratory (funded by the IRPProgram), detailed the activities completed, andconcluded that at the time the program was:

. . playing a small but effective role in ensuringthat the large potential of integrated utilityplanning is realized DOE’s role has been prima-rily catalytic, providing the motivation for other

organizations to join in cost-sharing and information-sharing projects. DOE’s participation in theseprojects helps to publicize and legitimize theideas of integrated planning and aids the technol-ogy transfer processes among utilities, commis-sions, and other interested groups.20

No formal evaluation has been done since. DOEcontinues to view its role primarily as publicizingand legitimizing IRP and DSM concepts.

Given the modest amounts devoted to theprogram 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 onAppropriations, 102d Cong., 2d sess., Apr. 8, 1992, p. 5,

m Linda Berry and Eric Hirst, supra IIOk 14, p. 1.


Box 7-A--NORDAX: Sharing Utility DSM Experiences

NORDAX, the NortheastRegion DSM Data Exchange, is a cooperative projectsponsored by a kgroup of some20 utilities in the northeastern United States and Canada. NORDAX is an example of DOE's institution buildingefforts. The Least-Cost Utility Planning Program (LCUP) provided money for development of a high qualityDSM database and establishment of a regional organization to maintain and update the database. Participantsin developing NORDAX included all of New York State's utilities, a number of othernortheastern utilities, the NewYork Public Service Commission, State and city energy agencies, the Edison Electric lnstitut,the Electric PowerResearch Institute, the Alliance to Save Energy, several national laboratories, and DOE’S LCUP programNORDAX was incorporated as a nonprofit corporation in May 1989 to carry on the project and operatesindependent 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 DSMprograms and resource planning. The NORDAX database, created in 1988, provides comprehensive informationon over 90 DSM programs from participating utilities plus detailed data on other utility systemcharacterostocs, suchas demographics, load and weather. The data is organized to assist utlilties compare and select future programswith 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 DSMtechnologies and programs. TheNORDAX experience will contribute to better methods for developinganddtahgDSM data to improve program effectiveness and to help incorporate real world load impacts and costs of DSMprograms in IRP models. NORDAX also presents an organizational model for development of a regional DSMdatabase 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. Departmentof Energy's Least-Cost Utility Planning Program, ORNL/CON--288 (Oak Ridge, TN: Oak Ridge National Laboratory, A u g u s t 1 9 8 9 ) , p p .l5-18.

support, many of the program’s clients have been Federal funds and technical assistance are notreluctant to criticize it. Nevertheless, anecdotalinformation suggests that its emphasis on promo-tion of IRP and DSM as general concepts israpidly falling behind the needs of client Stateregulators and utilities who are well advanced inimplementing IRP and DSM programs. Withgrowing reliance on IRP and DSM measures tomeet future customer demand reliably and at leastcost, the need increases for more sophisticatedplanning and evaluation methodologies and inde-pendent analyses of the cost and performance ofvarious energy supply and demand-side effi-ciency options. With its current size and scope, itseems unlikely that the IRP Program will be ableto provide institutional leadership or significantfinancial contributions to overcoming these chal-lenges.

the sole sources for financing or directing re-search and education efforts on IRP and DSMmethodologies. As utility involvement in theseprograms has expanded, so too has the institu-tional expertise within the industry and theregulatory community. The Electric Power Re-search Institute maintains active research andinformation programs on utility planning meth-ods, DSM programs and efficient end-use tech-nologies. Professional and trade associations,including such specialized groups as the Associa-tion of Demand-Side Management Professionals,sponsor seminars, conferences, publications, andother educational efforts. A plethora of consultingfirms offer analytical services to utilities andregulators.

Solar and Renewable Energy ConversionResearch Programs

The bulk of the Office of Utility Technologiesannual budget is devoted to DOE-funded R&D toaccelerate the development, demonstration, andcommercialization of advanced renewable tech-nologies for electric power generation. The majorpotential benefits to utilities from these researchefforts are increased diversity in technology andfuel choices, reduced costs and increased confi-dence in the performance of solar, wind, biomass,hydro, and geothermal power technologies.21

DOE also supports activities that target institu-tional factors influencing potential markets forand commercial deployment of renewable energytechnologies.

Renewable energy technologies offer severalsignificant benefits as part of utility resourceplans including opportunities to reduce the oper-ating and maintenance costs and planning uncer-tainties. In particular, renewable power genera-tion technologies have the advantages of reducedfuel costs and fewer adverse environmental im-pacts on-site than fossil fuel alternatives.22 An-other attractive feature is that renewable energygenerating technologies are available in small,modular units offering utilities capacity additionsin smaller size increments and with shorterconstruction lead times than more conventionalgenerators. 23

The Office of Solar Energy Conversion mana-ges projects to encourage solar thermal, bio-mass, and photovoltaic technologies. The Officeof Renewable Energy Conversion oversees geo-thermal, wind, hydroelectric and ocean energytechnologies. Both offices support research aimedat lowering the costs of renewable energy tech-nologies in the mid- and long-term to make themmore competitive economically with conven-tional fossil energy resources, As part of market-

.


Figure 7-2—Funding for Integrated ResourcePlanning Program, FY 1990-93

- $milllons7

6

5

4

3

2

1

0

m 1 9 9 0m 1 9 9 1C l 1 9 9 2~ 1993 request

r1

DSM Regulatoryanalysis

Planning Totalprocesses

Program activity

SOURCE: Office of Technology Assessment, 1993, based on datafrom, U.S. Department of Energy, FY 1993, Congressional BudgetRequest, 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 andparticipates in cooperative efforts to boost U.S.renewable energy technology exports. Many re-newable energy research projects are carried outon a cost-shared basis with private industry. Box7-B shows some of the recent research efforts

supported by these programs.

Office of Energy Management ProgramsThe Office of Energy Management supports

development of technologies to increase the

efficiency and reliability of energy transmission,

d is t r ibut ion , and s torage and to increase the

f lexibi l i ty , and safe ty of u t i l i ty sys tems. The

Office administers research programs on trans-

miss ion and d is t r ibut ion technologies , power

systems and materials, high-temperature super-

conductivity, 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.


Box 7-B-Renewable Energy Technologies R&D Projects of DOE

DOE participates in a variety of cooperative, cost-shared research, development demonstration, andteohnology transfer activitiesbencourage the expanded use of renewable energy technogies. These efforts bythe solar and renewable energy programs of the Office of UtilityTechnologies are directed at overcoming both thetechnical 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. renewableenergy industry and establish technological leadership in the marketplaoe.

Renewable Energy Conversion ProgramsThe 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 developmentof wind pow systems that can compete economicaiiy with conventionai power systems by producing electricityat a cost of $0.04/kWh (in 1990 dollars) in moderate wind speeds. The program is emphasizing cost-shareddevelopment of utility-scale advanced wind turbines and working to resolve critical reliability and performanceissues by examining wind/airfoil interactions and turbine structural response. DOE also continues to supportassessments of U. S. wind resources to assist State and utility energy planners and power producers in identifyingnew 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 ofexploration development, and conversion to make more of the domestic geothermal resource available andeconomic, The program is examining the peak load following capabilities of existing geothermal plants, andexploring technologies for tapping the energy potential of hot dry rooks, and geopressurized brines. GeothermalEnergy Program activities were budgeted at $26 million in FY 1992.

The Hydropower Program sponsors research on the costs, benefits, and effectiveness of environmentalmitigation practices with the goal of reducing the uncertainties in the regulatory review of proposed hydropowerdevelopment. FY 1992 funding was about $1 million.

the health effects of electric and magnetic fields. increase power sys tems f lexibi l i ty , ef f ic iency,

The major recipients of R&D funds under these

programs are the various national laboratories.

Long-term goals for DOE research on trans-mission and distribution (T&D) technologies areto 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 per-

c e n t .24 DOE is engaged in cooperative R&D on

higher capacity transmission and automated con-

trol systems incorporating advanced electronics,

communications, and computer technologies to

and reliability .25 To improve the cost-effectiveness of higher efficiency transmissiontechnologies, for example, the DOE program islooking at the technologies necessary for convert-ing alternating-current (AC) transmission lines tohigh-voltage direct current (DC) effectively dou-bling the capacity over the same right-of-way.Development of new technologies for improvedreal-time control of utility T&D will result in

more efficient transmission and increased trans-

mission capacity utilization.

U lbi~ pp. 27-28.

~ DOE, FY 1993 Congressional Budget Request, vol. 2, pp. ll!J-123.


The Ocean Energy Technology program with a budget of $2 million is cooperating with the State of Hawaiiin the design and construction of an experimental ocean thermal energy conversion (OTEC) facility using seawateras its working fluid.

Solar Energy Conversion Programs

The Photovoitaic (PV) Program is pursuing efforts to aid development of more cost-effective PV energysystems and to expand the market potential for PVS in utility applications. The program has set a goal of cuttingthe 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-termgoal is PV power generation at $0.06/kWh (in 1990 dollars). The PV Program is targeting improvements in PVmaterials, components, and system design to boost the solar conversion efficiency of thin-film and concentratormaterials, and to advance the development of mass-production manufacturing capability. DOE also is participatingin a PV demonstration project called Photovoltaics for Utility-Scale Applications (PVUSA), a joint-venture withEPRI, the California Energy Commission, and several utilities to test PV arraysfromseven manufacturers in a utilitysetting. The FY 1992 budget for the PV program was $60 million.

The SolarThermai Program is sponsoring research on improving basic thermal conversion technology andis supporting cost-shared development of central receiver systems for grid-connected electric generation and dishconcentrators for remote-site power generation. The program is participating in joint ventures with industry indevelopment and commercialization of solar thermal systems for remote applications at $0.1 to $0.2/kWh as astepping 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 biomassgasification and high-efficiency turbine conversion to expand the range of applications and performance ofbiomass 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 CongressionalBudget Request, voI. 2, January 1992, pp. 15-23; and US. Department of Energy, Assistant Secretary for Conservation and RenewableEnergy, Conservation and Renewable Energy Technologies for Utilities,” DOE/CH10093-86 (prepared by National Renewable EnergyLaboratory, Golden Colorado), April 1992, pp. 11-26.

DOE’s support of R&D on high-temperature improving the performance of high-temperature

superconduct iv i ty (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 utilityapplications and is budgeted around $21 milliona year.

Research on thermal energy storage systemsincludes the District Heating and Cooling (DHC)Program supporting joint ventures to developtechnical strategies to cut the capital costs andincrease the energy efficiency of major DHCcomponents. 27 DHC technologies offer utilities

26 [email protected]_e superconductivity ref~ to materials that can conduct electricity with m IWSiStiCX ~ eXWl magnetic fields(dimagnctism) at temperatures substantially higher than liquid helium (4 degrees Kelvin(K) or 4 degrees C above absolute mm which is minus273 degrees C). Sustaining superconductivity of high electric currm ts in high magnetic fields at temperatures of liquid nitrogen (about 77degrees C above absolute zero) now commonly used in industrial applications could make HTS motors generators, magnets, and similar devicespotentially 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.


opportunities to lower electricity peaks and im-prove energy efficiency and fuel flexibility. TheDHC program was budgeted at $4.2 million in FY1990-92 with more than $1 million expected fromnonfederal sources for demonstration projects inFY 1992.28 Because DOE views the technologyas sufficiently mature to permit commercialgrowth of DHC systems, it proposed terminationof the program and documentation of researchresults during FY 1993.29 DOE also supportsresearch on improved battery storage systems forutility applications and technologies for futurehydrogen energy systems.

The Electric Energy Systems program alsooversees DOE’s research efforts on potentialhealth effects of exposure to electric and magneticfields. DOE is supporting research on characteriz-ing EMF exposures, potential biological mecha-nisms of EMF interaction with living systems,and epidemiological studies. DOE is also expand-ing efforts on public information and engineeringresearch on EMF mitigation options.

Office of Utility Technologies programs aregeared specifically towards utilities. However,several other programs in DOE perform work thatis potentially beneficial to utilities. This includesother programs under the 0ffice of EnergyEfficiency and Renewable Energy and in the0ffices of Fossil Fuels and Nuclear Energy, to bediscussed later in this chapter.

Demand-Side Energy Efficiency ProgramsThe Office of Energy Efficiency and Renew-

able Energy also adminis“ ters programs that pro-mote energy-efficient demand-side technologiesthrough R&D, technical and financial assistance,and energy codes and standards. With buildingsand industry contributing 30 percent each to U.S.energy use, the potential contributions fromefficiency improvements in these sectors is sub-

stantial. DOE support for the development andcommercialization of energy-efficient buildingsand industrial technologies yields products that inturn create energy-saving opportunities for utili-ties and consumers.

Office of Building Technologies30—The com-mercial and residential sectors are frequentlyreferred to as the buildings sector because most oftheir energy use is for building systems (i.e.,heating, cooling, lighting, and appliances). Build-ing energy use accounts for more than a third ofall U.S. energy use and is continuing to grow evenas the efficiency of buildings and appliances isimproving. DOE-supported buildings R&D haveprovided several energy-efficient technologiessuccessfully in use today, including solid-statefluorescent lamp ballasts, advanced refrigeratorand freezer technologies, and low-emissivitywindow coatings. These technologies, resultingfrom R&D efforts initiated in the late-1970s,produced results that will save energy into thenext century. Advances in fluorescent lamp bal-lasts aided by $3 million of DOE research funds,are expected to save billions of dollars in lightingenergy costs in the coming decades. DOE-fundedresearch efforts in improved insulation and walland ceiling structures have also yielded success-ful energy-saving applications.

The Office of Building Technologies is cur-rently supporting research to develop cost-effective technologies to reduce building energyloads by 30 percent in the near-term and by asmuch as 80 percent in the long-term. Majoremphasis is given to development of high-efficiency lighting systems, energy efficiencyHVAC conversion and distribution systems, ad-vanced building materials, more energy-efficientappliances and replacements for chlorofluorocar-bons in building systems. Advances in these areaswill 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*tertietito 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 alsosupporting R&D on cost-effective solar technolo-gies to meet some or all of the energy needs ofnew buildings.

Office of Industrial Technologies31-DOE ef-forts to improve industrial efficiency have zeroedin on reducing the waste streams generated inindustrial processes to improve energy efficiencyand eliminate harmful environmental pollutants.DOE is also supporting development and adop-tion of more energy-efficient technologies andprocesses in energy-intensive industries and moreextensive use of industrial cogeneration andmunicipal solid waste energy systems. Theseefforts could offer benefits to utilities in morediverse opportunities for new energy supplies aswell as a stream of efficient industrial electrictechnologies for DSM programs.

Among the successes from DOE-funded indus-trial research are a control mechanism for ahigh-efficiency transformer used in the weldingprocess, biomass grain driers, and slow-speeddiesel motors for cogeneration systems. PresentDOE industrial research is focused on improvingthe efficiency of electric motors, which nowaccount for some 70 percent of industrial electric-ity use. DOE’s cooperative efforts to spur adop-tion of adjustable-speed drives and high perform-ance electric motors for new and retrofit applica-tions include efforts to develop and provideinformation to justify including industrial motorprograms in utility integrated resource plans.32

Technical and Financial Assistance ProgramsFederal efforts to save energy and promote

energy efficiency and renewable energy technolo-gies have led to a variety of programs that offertechnical assistance and Federal funds to gover-

nment and private entities. Many of these programswere originally established during the energyscares of the 1970s and they have had varyingdegrees of success. Among the most notable arethe various programs administered by the Officeof Technica1 and Financial Assistance, the nowexpired Residential Energy Conservation andInstitutional Energy Conservation Programs, andthe Federal Energy Management Program.

The Office of Technical and Financial As-sistance (OFTA) administers a variety of pro-grams that provide technical advice and grants toStates, local governments, nonprofit institutions,and low-income individuals. OFTA also overseesState programs funded from the petroleum over-charge violations settlements. OFTA’S portfolioconsists of various State and local partnerships,information and technical assistance programs,and energy management programs .33 The Stateand local partnerships encompass the State En-ergy Conservation Program, the Energy Exten-sion Service, the Weatherization Assistance Pro-gram, and the Institutional Conservation Pro-gram.

The State Energy Conservation Program,established in 1975 under the Energy Policy andConservation Act, provides financial and techni-cal assistance to States and localities to developand implement comprehensive energy conserva-tion plans to encourage energy efficiency andreduce energy demand growth. All States haveimplemented the act’s mandatory energy conser-vation programs (including lighting efficiency,insulation, and thermal efficiency standards fornonfederal public buildings) and most now in-clude supplementary programs in energy educa-tion, technology demonstration, and technical

31 ~~c~ om~ties for energy-saving technologies for industrial application ti relevant @ve rnment programa are examined indetail in U.S. Congress, Office of Technology Asscsmen~ lndustn”al Energy Eficiency, released in April 1993 and to be published in summer1993.

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 ~dinnovators, technology transfer and information programs, and international market development and energy technology information exchangeprograms. These programs am not particularly relevant to utility energy efilciency efforts and are not discussed here.


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 80,000 187,000State Energy Conservation Program . . . . . 16,620 16,194 45,000 15,600Institutional Conservation Program. . . . . . . . 31,022 30,246 30,000 29,200Total.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 246,594 240,365 155,000 231,800

SOURCE: Office of Technology Assessment 1993, based on data from U.S. Department of Energy, FY 1993Congressiona Budget Request, vol. 4, January 1992, pp. 28&281, and other sources.

assistance reflecting local priorities. A major goalof the program is to build State and localinstitutional capabilities for energy conservationplanning and implementation.

Funds are provided in the form of formulagrants (requiring a 20 percent State match) andincentive awards for innovative State/industrycooperative programs. While appropriations forthe program have decreased since 1979, overallfunding of State program activities has balloonedbecause of the availability of oil overchargefunds.34 See table 7-5 for a summary of funding.DOE technical assistance to State energy agen-cies focuses on education and information ex-change and has included publications, trainingmanuals, an information clearinghouse, seminars,workshops, and conferences. States have used thefunds to support a variety of energy conservationactivities, including demonstration projects in-stalling energy-efficient lighting, HVAC, andenergy management systems and solar technolo-gies in public buildings.35 Beginning in FY 1992,DOE has supported an initiative aimed at encour-aging States to attract nonfederal resources tosupplement the grants provided by offering addi-

tional incentives to support State-led joint ven-tures with industry to encourage the near-termadoption of emerging renewable energy andenergy-efficient technologies.36

A companion program, the Energy ExtensionService (EES) was created in 1977 to provideinformation, technical assistance, and trainingtailored to the needs of small energy users such ashomeowners, municipalities, and small busi-nesses. Under the program, State energy agenciesor other designated entities design projects serv-ing specific local information needs. Cost-sharefunds are disbursed from DOE through Stateagencies to local programs.

Among the successful projects have beenenergy on-site audits, self-help workshops, andauditor-training programs. The program is in-tended to be flexible and responsive to local needsand leveraging of private funds is encouraged.

In Rhode Island, grant funds were used in acooperative effort with local electric utilities anda nonprofit group to conduct energy audits ofState buildings and recommend lighting effi-ciency retrofits. The utilities provided rebates ofup 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 1989is provided in ConsumerEncrgy Council of America Research Foundation A State-&y-State Compendium ofEnergyEflciency Progrurns Um”ngOil Overcharge Funds, EPIU CU-7541 (Mo Alto, CA: Eleetric Power Research Institute, h4.meh 1991). By 1989 ovex $7 billion in variousoil overcharge settlemeds had been collected and additional eases (with anticipated recoveries of $0.5 to $1.0 billion) were still undernegotiation. Expenditures of funds from the eserow amounts from the Exxon settlement wem limited to various Federal and State progmmsincluding the State Energy Conservation Pro- the Energy Extension Serviee, Institutional Consemition Pro- WeatherizationAssistance 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 estimatesthat the project will result in a 20-percentreduction in total annual State electric costs.37

EES funds have also supported providingtraining for school districts in Washington onhow to reduce energy use through lightingchanges on school grounds and installation of acogeneration demonstration at a community andbusiness center, in Taos, New Mexico expected tosave $10,000 annually in energy costs.

The Energy Policy Act of 1992 repealed theNational Energy Extension Service Act thatestablished EES.38 The repeal is unlikely to resultin lost energy savings given the overlap withother programs.

OTA’s Building Energy Efficiency report notedthat both the Energy Extension Program and theState Energy Conservation Programs lack evalua-tions of cost-effectiveness or reliable energy-savings estimates. However, OTA observed:

. . .IB]oth programs are important networks forconveying Federal monies and expertise to theState and local level, and both programs areconnected to small-scale energy users that couldhelp DOE demonstrate technologies emergingfrom its energy conservation research and devel-opment projects. In addition, the auditor and othertraining offered by these programs help establishand sustain local expertise and markets forweatherization and other conservation services.39

The experience in Rhode Island also demon-strates that the programs provide opportunities forState/utility/private partnerships that can lever-age Federal grant funds and expand the reach ofutility-sponsored efficiency programs. With thelarge pool of oil overcharge funds still remaining,these opportunities should prove attractive toStates and utilities.

The Weatherization Assistance Program (WAP)was originally established in 1976 under theEnergy Conservation and Production Act to helpweatherize the homes of low-income families.The program aims to reduce the energy costs oflow-income families.

WAP allocations to States are made under aformula reflecting the number of low-incomehouseholds, residential heating and cooling en-ergy use, and local climate conditions. Familiesqualify for weatherization assistance if they meetcertain eligibility conditions, including a house-hold income at or below 125 percent of thepoverty level. The weatherization assistance pro-grams are usually carried out by local communityorganizations that provide energy audits andinstallation of cost-effective weatherization meas-ures. In addition to the grants for weatherizationactivities, DOE also provides funds for training,technical assistance and client education.

According to DOE, energy savings of 25percent or more are possible at residences eligiblefor WAP funds. Families earning less than $5,000a year consume an average of 68 percent moreenergy to heat a square foot of living space thanhigher-income families. This difference is attrib-utable in part to the fact that lower-incomeresidences are old and in disrepair, and hence lessenergy efficient than the homes of higher-incomehouseholds.

An early national evaluation of WAP foundthat the average energy savings is 10 percent perhousehold from WAP retrofits.40 However, sincethere have been many program changes since1981, 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 repofiSR-EE~-84-1, Washin@o~ ~, August 1984, pp. 1, 18.


has initiated a new evaluation and anticipates afinal report at the end of 1993.41

In recent years, the WAP program has alsoshifted more of its emphasis to encourage lever-aging of Federal funds to increase the number ofclients it can serve. Agreements were made withtwo utilities to augment WAP funds with addi-tional financial and in-kind services.42

The Institutional Conservation Program (ICP)was established by the National Energy Conser-vation Policy Act in 1978 as a matching grantprogram that provided funds for both detailedenergy audits and the suggested energy-savingcapital improvement in nonprofit institutions,such as schools and hospitals. Projects are fundedon a 50 percent cost-share basis and are administ-ered through State agencies. Since 1978, theprogram has awarded over $800 million in grantswhile saving over $2 billion in energy bills atparticipating institutions.43

New rules adopted as a result of Public Law101-440 will streamline the program and encour-age leveraging, and third-party financing options(such as utility demand-side management pro-grams and energy savings contracts). The newrules will allow a State to use up to 100 percent ofits funds for program and technical assistanceactivities and up to 50 percent of its Federal fundsfor marketing and other costs associated withleveraging nonfederal funds.44

The DOE Weatherization Assistance Programand the Institutional Conservation Program (ICP)are financed in large part from the petroleumovercharge fund. An additional beneficiary ofthese funds is the Low-Income Home EnergyAssistance Program (LIHEAP) at the U.S. De-partment of Health and Human Services (HHS)

that helps poor households in meeting theirenergy bills. LIHEAP is described in box 7-C.

Past Technical Assistance Efforts-Building Energy Audits

During the 1980s Congress discontinued twolegislatively-mandated building energy audit pro-grams that included utility participation. TheResidential Conservation Service (RCS), whichexpired in 1989, and the Commercial andApartment Conservation Service, repealed in1986, were designed to provide building ownersand occupants with building-specific informationon energy use and savings.45 The centerpiece ofthe program was the requirement that utilitiesperform an on-site energy audit that includedactual measurements by an auditor and an indi-vidualized written report for its customers.

The enabling legislation for RCS estimatedthat the program would contribute to the insula-tion of 90 percent of the Nation’s homes. How-ever, at the conclusion of the program 7.3 millionaudits had been performed, achieving only 11percent participation.%

As designed, the programs did not addresseither the availability and costs of financingconservation retrofits nor the regional availabilityof conservation supply and installation services.Additionally, under most State ratemaking for-mulas then in use, participating utilities lackedsufficient incentives to conduct the program asthe costs of the program were merely passedthrough to customers without any added profitand resulting energy-savings potentially reducedutility revenues.

Despite these drawbacks, the programs, likeother federally-mandated technical assistance and

41 ()’E.q, Buil&’ng Energy Eficiency, Supra note g, pp. %’-99.

42 D O E , 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.


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 ablock-grant program administered by the Department of Health and Human Services. The program provides fundsto States to help eligible low-income households meet heating and cooling bills, such as utility bills. Up to 15percent 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; weatherizationservices were provided to only 146,000 homes. On average, States spend from 7 to 10 percent of their LIHEAPfunds on weatherization. The bulk of the funds are spent on energy assistance, averaging about $200 perhousehold. 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 reachmore households with available funds than weatherization efforts, even though weatherization could cuthousehold energy bills.

OTA’s report, Building Energy Efficiency found that there was little assessment of the cost-effectiveness ofLIHEAP 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 beenlost or delayed. (Utility arrearages from delays in paying residential bills amount to hundreds of millions of dollarsannually; LIHEAP funds help offset these liabilities.) The report noted that new Federal policies or requirementsto leverage LIHEAP weatherization funds with State and utility resources could boost the number of low-incomehouseholds 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. GovernmentPrinting Office, May 1992), pp. 99-100.

reformation programs, helped to create the insti- budget ($4 million in FY 1992). FEMP has fourtu t ional inf ras t ructure and exper t i se in Sta te

government, utilities, and energy conservation

service providers that now help sustain active

energy efficiency and technical assistance efforts.

The Federal Energy Management ProgramThe Federal Energy Management Program

(FEMP), located in The Office of BuildingTechnologies, is an outreach program designed toassist Federal agencies in adopting energy effi-ciency measures in buildings, transportation andoperations (see box 7-D). The program wasestablished in the mid- 1970s in response tolegislation and Executive Orders directing Fed-eral agencies to reduce energy use. The programhas a small staff (six people in 1991) and a modest

areas of operations: 1) reporting on the energymanagement efforts of Federal agencies; 2) pro-viding information training, and technical SUpport

to Federal agency personnel; 3) hosting intera-gency meetings to develop new Federal initia-tives; and 4) awarding annual certificates ofachievements to Federal facilities and personnelfor demonstrating exemplary performance .47

As part of its efforts to assist Federal agenciesin implementing energy-saving measures, FEMPhas been evaluating agency participation in utility-sponsored DSM programs and is assisting inadministrative reforms that would encouragegreater use of shared energy savings contracts byFederal agencies as an alternative means offunding 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


Box 7-D--Federal Energy Management Program

Federal Spending on Energy, FY 1989

Other

/Assistedhousing

4

SOURCE: Office of Technology Assessment, 1993, adapted from U.S.Department of Energy, Federal Energy Management Program, “Reporton Federal Government Energy Management and Conservation Pro-grams,” October 1990.

The Federal Government is the Nation’sIargest single energy consumer. In FY 1989, theFederal Government spent over $8*7 billion ondirect energy purchasesfor its own facilities andoperations and another $4 billion subsidizing theenergy expenses of low-income households(see figure). Not reflected in this direct energyexpenditure are some $12.7 billion for energycosts for leased space for which the FederalGovernment does not directly pay utility bills.Payments to electric Utilities accounted for anestimated $2.4 billion of the FY 1989 energy billfor Federal buildings. Electricity accounts foraround 70 percent of total energy costs.

OTA’S report Energy Efficiency in theF e d e r a l G o v e r n m e n t b y G o o dExample? concludes that much Federal energyis inefficiently used OTA estimated that theFederal Government could profitably conserveat least 25 percent of the energy used in Itsbuildings by adopting commercially cost-effeotive measures such as high-efficiency

lighting and carefully operated heating, ventilation, and air conditioning equipment-with no sacrifice of comfortor productivity.

The constraints to Improved Federal energy efficiency are real and significant (see table.) Implementingefficiency improvements will require overcoming several hurdles, including finding sufficient funds to pay forretrofits in an era of tight budgets.

OTA’s ease studies found a large potential for savings. However constraints, notably the Iack of funding andstaff, limited action at the facilities. For example, the General Services Administration’s (GSA) Suitland Complexhas 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 airconditioningsystem, improved lighting efficiency, and improved the building envelope. Most Improvements consisted of lowfirst-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, suchas greater use of computers and increased occupancy, offset the gains. Further measures have not beenimplemented for several reasons. The complexity of the procurement process creates significant lag time, andinhibits selection of innovative equipment and participation in local rebate programs. Current policy restrictsreplacement 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 sophisticatedto run without it.

OTA found that there are mechanisms in place to promote greater energy efficiency in Federal buildingsincluding 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 energysavings (SES) contracts. Under the Compre-hensive Omnibus Budget Reconciliation Act of1985 (Public Law 99-272), all Federal agenciescan seek private financing from energy servicecompanies. These companies perform conductenergy audits and install efficiency measuresusing their own capital and personnel. Theircosts and profits are paid for out of the moniesthat previously went to higher energy bills.However, this procurement practice is rarelyused by Federal agendas. The complexity ofthe procurement process and uncertainty overwho keeps the savings discourage interestedagencies from initiating such contracts. Legisla-tion was passed to assist the Department ofDefense (DOD) overcome constraints in SEScontracting. DOD is permitted to retain two-thirds of energy savings at the installation withthe SES contract. One-half is to be used forfurther energy conservation measures, whilethe other half is available for other projects.Additionally, provisions in the act simplify thecontracting procedures for DOD.

Utility rebates are another importantsource of funding. Large Federal installationsoffer significant energy savings for interestedutilities.Therebates offered by utilities are likelyto bring borderline efficiency measures withinfinancial reach. For example, the GSA and

Constraints on Improved FederalEnergy Efficiency

Resource constraintsPriorities favor other agency needs

Energy efficiency is not central to most Agencies’ missionsEnergy is a small component of most agendas’ expendituresLittle senior management interest

Many measures require initial capital spending

Many measures require personnelMany facilities have no energy coordinator

Information constraints

Opportunities have not been systematical!y assessed

Agencies are uncertain of technical and economic performanceDoes 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 ofindividuals

Implementation requires coordinated effort from diverse partiesToo little training and education for diverse parties

Lack of incentives

Dollar savings often do not acrue to energy saversEnergy costs are readily passed through budgets

Federal procurement policies often favor status quoProcurement practices am complex often restrictive

SOURCE: U.S. Congress, Office of Technology Assessment, EnergyEfficiency in theFederal Government: GovernmentbyGood Example?OTA-E-492 (Washington, DC: U.S. Government Printing Office, May1991), p. 10.

Potomac Electric Power Company in the Washington, DC, metropolitan area have been working on a FederatLighting Initiative. In 1991, GSA committed $10 million towardthis effort with PEPCO offering an additional $10million in rebates. As of early 1991, only DOD and DOE had an explicit policy on receiving utility rebates. DODis 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 NorthwestLaboratory, 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 PolicyAct of 1992. The act toughens energy efficiency standards for Federal buildings and sets anew deadline of 2005for Federal agencies to install cost-effective technologies to save energy and water. Also enacted were a numberof other measures to raise energy awareness among Federal managers and financial commitments to energyefficiency.



that aggressive implementation of energy effi-ciency measures in Federal buildings, such aslighting retrofits, could cut Federal energy use by10 percent from 1985 levels and yield savings of$400 million per year by 1995.48

ENERGY EFFICIENCY INFORMATIONAND STANDARDS

The Federal Government has had almost 20years of involvement in various programs involv-ing building energy codes and standards, andappliance labeling and efficiency standards. Inaddition to DOE, the Federal Trade Commission(FTC) and the U.S. Department of Housing andUrban Development (HUD) have been involvedin these efforts. The programs have requiredFederal agencies to work in cooperation withtrade and professional organizations and manu-facturers.

OTA’S report Building Energy Efficiency ex-amined the history and efficacy of these programsfor commercial and residential energy technolo-gies.49

OTA found that although there has beenlimited evaluation of the effectiveness and energy-savings attributable to these efforts, there is someconsensus that they help reduce information-related constraints to energy efficiency improve-ments, and they provide accepted benchmarksused by electric utilities in determining andadvertising energy-efficient products in theirDSM programs.

Federal Building Energy Codes and StandardsWhile building energy codes generally are

adopted and enforced locally, most localities relyon model codes published by national buildingorganizations .50 The DOE and HUD have been

active in developing model and mandatory build-ing energy codes and standards. In cooperationwith States and various national organizations,Federal agencies have issued voluntary guide-lines for nonfederal buildings. DOE and HUDhave promulgated energy efficiency standards forFederal buildings and manufactured homes (e.g.,mobile homes). Although the number of newFederal buildings constructed annually is small,the Federal Government potentially has the abil-ity to influence about 27 percent of new homeconstruction through eligibility requirements forFederal mortgage insurance programs of theFederal Housing Administration, the VeteransAdministration, and the Farmers Home Adminis-tration. 51 Table 7-6 shows the status of Federalefforts.

Appliance Efficiency StandardsThe National Appliance Energy Conservation

Act52, as amended, establishes Federal minimumefficiency or maximum energy use standards forcertain appliances, including refrigerators, airconditioners, and furnaces. DOE is required toupdate the standards to reflect technologicalchanges every 3 to 10 years depending on theappliance. Federal efforts to promulgate effi-ciency standards for consumer appliances wereinitiated in the 1970s under the National EnergyConservation Policy Act. Implementation of thatact’s mandatory efficiency standards was slowbecause of opposition within the ExecutiveBranch and from manufacturers, and litigation.Pressure for uniform national standards helpedbreak the logjam after California and severalother States adopted appliance efficiency stand-

48 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 forbuilding 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.

—


Table 7-6-Federal Energy Standards for New Buildings 1992

Code

HUD Minimum Property Standards(1950s)

National Manufactured Housing Con-struction and Safety Standards (1974)

DOE Building Energy PerformanceStandards (1979)

DOE Mandatory Performance Stand-ards for New Federal ResidentialBuildings (1989)

DOE Energy Performance Stand-ards for New Commercial Buildings(1990)

DOE Voluntary Guidelines for Non-federal Residential Buildings

Applicability

Residential buildings receivingFederal mortgages

All manufactured housing

All new construction

Federal residential construction(95 percent is military housing)

Mandatory for Federal commer-cial buildings. Voluntary for private-sector commercial buildings.

Voluntary standards for nonfed-eral residential buildings

Status

To be replaced with Council ofAmerican Building Officials ‘ModelEnergy Code’

Active

Never implemented; supplantedby performance standards listedbelow

Active

Active

Underdevelopment; issuance pend-ing

NOTE: New Federal Building Energy standards adopted in Energy Policy Act of 1992 (Public Law 102-488) are not includedabove.

SOURCE: Office of Technology Assessment, 1993, adapted from U.S. Congress, Office of Technology Assessment, BuildingEnergy 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 standardsestablished before 1992, The Energy Policy Actof 1992 added additional energy and water-usingdevices to the list of products for which minimumFederal energy efficiency standards have beenestablished .53

Appliance LabelsThe Federal Government has also mandated

labels showing energy use for the appliancescovered by the standards under the Energy Policy

and Conservation Act.54 The requirement is basedon the belief that consumers will purchase moreefficient appliances if given information aboutoperating costs and comparative product efficien-cies. Labels now exist for refrigerators, freezers,dishwashers, water heaters, clothes washers, roomair conditioners, and furnaces.55 The labels in-clude estimated operating costs for the product, aswell as the range of operating costs for otheravailable products in the same class. Appliancelabeling requirements are the responsibility of theFTC.

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 promulgationof 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~eappliance 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 anddehumidifiers, 13) furnaces, and 14) any other type of con.sumerproduct defined as covered by the Secretary of Energy. Swimmin g pool heatersand 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 qipmentother than fi.maces, television sets, kitchen ranges and ovens, and humidifiers and dehumidifiers). was economically unfeasible and would notassist consumer purchasing decisions. 44 Fed. Reg. 6W66 (Nov. 19, 1979).


~~ 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 244on a national average electrlc cubfc feet are compared

UI rate of 4 97c per kilowatt hourn

in the scale

wu.

Model with $91 Model withlowest highestenergy cost

$68energy cost

$132v THIS ~ MODEL v

Your cost will vary depending on your local energy rate and howyou 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¢ $36kilowatthour

4¢ $73

6¢ $1098¢ $146

10¢ $18212¢ S218

Ask your salesperson. or local utility for the energy rate (cost per kilowatt hour) in your area

Impotant Removal 01 this label before consumer purchase IS a violation Offederal law (42 U S C 6302)

(Pa, ! No 371026I

The Federal Trade Commission requires many newappliances to display labels that indicate the units’expected energy use of efficiency.

B Other DOE Supply-side Research

The Office of Energy Efficiency and Renew-able Energy administers a variety of programswith potential benefits for electric utility energyefficiency efforts. Three other DOE programsalso sponsor R&D and demonstration projectsdealing with energy efficiency in utility powergeneration and operations and cleaner generatingtechnologies for new utility plants or repoweringof existing plants. Energy efficiency is at presenta minor consideration among the many objectivesof these programs, which appear to be primarily

directed at advancing particular fuels or technolo-gies. DOE-funded activities could also providecost and performance information on advancedpower technologies that could aid considerationof these options in utility IRP programs. It is notclear, however, whether such information iseffectively made available to the utility sector orto DOE’s own 0ffice of Utility Technologies.

FOSSIL ENERGY R&D PROGRAMSFossil fuels contribute 60 percent of the fuel for

the production of the Nation’s electricity. TheOffice of Fossil Energy (FE) supports a widerange of basic R&D and demonstration projectsinvolving coal, oil, and natural gas. One of thestrategic goals identified for the fossil energyresearch program is to “provide environmentally,economically superior technology for the genera-tion of electrical and thermal energy, and for theproduction of fossil-fuel-based chemicals andproducts for the electric utility market. . .“56Other goals include encouraging utilization ofdomestic resources, improving international com-petitiveness of U.S. technologies and technology-based products, and environmental protection. Inrecent years, consistent with these goals, greateremphasis has been given to cost-shared researchand technologies for near- and mid-term commer-cialization by the private sector.

DOE-sponsored efforts with potential applica-tions for electric utilities include R&D on coalcombustion and control technologies, waste re-duction, and fuel cells.

The coal program activities are focused onreducing emissions and boosting the energyefficiency of coal-fried powerplants. Low-costcoal cleaning methods will reduce costs forutilities’ compliance with clean air regulations.

The fuel cell program, involving both coal andgas resources, is working to realize the potentialof highly efficient, clean, and competitive genera-tion of electricity and heat in the major sectors ofthe 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 programexpects to demonstrate high-efficiency, naturalgas fuel cell powerplants for on-site applicationsand low-megawatt electric utility powerplantsthat are economically competitive with conven-tional technologies.

The Clean Coal Technology program pro-vides Federal funds to spur demonstration ofadvanced coal power generation technologiesoffering higher efllciencies, reduced emissions,and cost savings that can help coal compete withother resources (see box 7-E).

Cost and performance data from the Clean CoalTechnology Program and other Fossil EnergyR&D projects could aid utilities in resourceplanning for future power needs. Figure 7-3shows the Fossil Energy R&D Budget.

NUCLEAR ENERGY R&D PROGRAMSNuclear power currently provides about 20

percent of the Nation’s electricity. The Office ofNuclear Energy supports research projects infission energy, including commercial nuclearreactor development. Preserving the viability andeconomic competitiveness of commercial nuclearpower generation is a major priority of theseefforts.

Much of the DOE nuclear R&D is targeted atthe development of standardized designs for newnuclear plants. The $200-million program isshared equally between industry and the FederalGovernment. The goal of this partnership is todevelop advanced light-water reactor designs forcommercial application. Another focus is contin-ued R&D in advanced nuclear power systems.DOE requested $50 million in FY 1993 forsystems that show ‘‘promise of potentially signif-icant breakthroughs in economics, safety, licens-ing, and waste management. ’ ’57 The early sitepermit program, a joint program started in 1992between DOE and three electric utilities, will


Table 7-7-Selected National Appliance EnergyConservation 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 seasonalperformance factor; EF = eff iciency factor; AFUE = annual fuel use (orutilization) efficiency.a Automatic defrost units with top-mounted freezers, no through-the-

door 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 Effi-ciency, OTA-E-51 8 (Washington, DC: U.S. Government Printing Office,May 1992), p. 112.

demonstrate the effectiveness of the early sitepermits procedure established by the NuclearRegulatory Commission. The procedures aredesigned to approve sites for nuclear powerplantsbefore both construction and substantial financialinvestment in an effort to improve industrystanding. 58 Nuclear R&D funding requests wereat $307 million in FY 1993, down from $332million in FY 1992.

The energy efficiency related goals for nuclearpower 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~, February1992, p. 35.

‘g Ibid., pp. 33-36.


Box 7-E—The Clean Coal Technology Program

The Clean Coal Technology Program was established as an outgrowth of U.S.-Canadian agreements on addrain control (Public Law 99-190, Dec. 19, 1965). The program provides Federal funds for up to 50 percent of thecost of building and operating facilities demonstrating the futurecommercial feasibility of dean coat technologiesthat burn coal more efficiently, with Iower emissions, and at a lowercostthan existlng technologies. The programwas 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-sectorparticipation has exceeded expectations, and the overall investment in projects funded under the program is nowanticipated to top $6 billion.

Clean Coal Program appropriations rose from $99.4 million in FY 1966 to $415 million in FY 1992. Theprogram has encountered a number of difficulties and delays. Obligations have lagged behind the amountsappropriated. Awarding, negotiating, and obligating Federal funds for joint-venture arrangements proved to takelonger 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 asa means to spur practical technologies that would allow expanded coal use by reducing the adverse environmentalimpacts 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 reducingglobal warming through lowered carbon dioxide emmisions. The fifth round targeted super-dean, high-efficiencypower generation systems needed for coal to compete as an energy source under the more stringent post-2000standards for sulfer dioxides and nitrogen oxides under the Clean Air Amendments acid rain controls. lnformationfrom 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 announcedin May 1993. As of late 1992 there were 41 projects from the first four rounds of competition that were eitherunderway (pre-construction or construction, or operational phases) or completed. Total value of these productsiS 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, achievingconversion efficiencies of 45 percent of the energy content in the fuel, compared with the 33 to 35 percentefficiencies of conventional coal powerplants.

Among the technologies that have been funded under the demonstration program in early rounds areadvanced coal cleaning, co-firing ofcoal with other fuels, advanced scrubbing technologies, underground coalgasification, atmospheric and fluidized bed combustion, slagging combustion, sorbent injection, integratedgasification 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-cydepowerplantcoupled with a 2.5 MW-molten carbonate fuel cell, a combined-cycle plant created by repowering an existing plantwith an external gas turbine, a second-generation pressurized circulating fluidized bed powerplant, a small dieselpower system fired by a coal-water slurry and equipped with a heat recovery boiler-steam turbine, and anadvanced integrated steelmaking-power generation process.

The Energy Policy Act of 1992 calls for DOE to consider additional solicitations under the Clean CoalTechnology 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 CoalToday, No. 9, winter 1992.


fossil-thermal plants. The industry is interested inreducing the downtime that nuclear plants haveexperienced, improving load-factor and capacityavailability, and refining predictive maintenancemethodologies, as well as improving the energyefficiency of individual plant components. Imp-rovements in the energy efficiency of nuclearpowerplants is not a driving force in DOEcommercial nuclear programs. Efforts supportingstandardized nuclear reactor designs and permit-ting procedures could enhance the viability ofnuclear options in utility resource plans.

FEDERAL POWER SYSTEMSThere are 10 Federal “electric utilities”—

Government-owned and, operated power systemsthat generate and sell electricity. They include theTennessee Valley Authority (TVA), the fivePower Marketing Administrations (PMAs), theU.S. Army Corps of Engineers, the Bureau ofIndian Affairs and the Bureau of Reclamation inthe Department of the Interior, and the Interna-tional Water and Boundary Con-mission in theDepartment of State. Together, they operate over150 powerplants and generate 8 percent of theNation’s electricity supply .59 Much of the poweris generated at Federal darn projects initiallydesigned to control flooding and improve irriga-tion.

These Federal utilities are primarily generatorsand wholesalers of electricity, although some alsoserve as retail power distributors to ultimatecustomers. Most of the power is sold for resale tomunicipalities, electric cooperatives, and othernonprofit customers under preferences requiredby authorizing statutes. In 1990, Federal powersystems sold 197.9 million MWh to wholesalecustomers, while sales to ultimate or retail cus-tomers totaled 52.1 million MWh. Federal system

Figure 7-3-Fossil Energy Research andDevelopment Budget, FY 1991-93

Budget ($millions)- - -500

400

300

200

100

0

- —: —— — . .—g 1991n 1992~ 1993 request~ 1993 actual

Coal

RZA I 1mEli— - 1

Gas 0il Other Total

Activity

SOURCE: Office of Technology Assessment, 1993, based on datafrom U.S. Department of Energy, FY 1993 Congressional BudgetRequest, vol. 4, January 1992, pp. 1$17.

operating revenues totaled $8.2 billion and oper-ating expenses were $5.4 billion for 1990 (seetable 7-8). Pricing of Federal power is notintended to make a profit, but rather to recoveroperating costs and ultimately the capital costs ofthe facilities plus interest. Long-term debt andliabilities totaled some $31.9 billion in 1990.60

The major Federal power producers are TVA,the Army Corps of Engineers, and the Bureau ofReclamation. TVA markets its own power. Mostof the electricity produced at Corps of Engineersand Bureau of Reclamation projects is marketedand transmitted by five power marketing adminis-trations: the Bonneville Power Administration(BPA), the Western Area Power Administration(WAPA), the Southeastern Power Administration(SEPA), the Southwestern Power AdministrationSWPA), and the Alaska Power Administration(APA).61 The PMAs also purchase power fromother 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 NofiCentral Division in Sault Ste, Marie, Michigan.


Table 7-8-Statement of Income of Federal Power Marketing Administrations and the Tennessee ValleyAuthority, 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 8,167,742Operating expenses. . . . . . . . . . . 3,867 1,554,260 26,500 84,845 514,954 3,216,460 5,400,886Total income. . . . . . . . . . . . . . . . . . 5,735 516,256 110,069 10,482 2,305 2,117,557 2,762,404Income deductions. . . . . . . . . . . . . 2,983 201,950 110,081 830 44,918 2,845,175 3,205,937Net 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 ofSelected 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, especiallyduring periods of drought. ARA is an exception;it operates its own powerplants and distributespower to ultimate customers. Figure 7-4 shows amap of the areas served by the PMAs. With theirbroad customer base, PMAs are in a position toinfluence almost 30 percent of retail electricitysold. 62 Although all of the PMAs have authorityto encourage their utility customers to invest inconservation, only Bonneville and Western haveexpress legislative authority to link power sales totheir customers with energy efficiency. Withoutthis “conditioning authority,” the other smallerPMAs have been limited in their ability to requiretheir customers to participate in DSM activities.63

Individually, TVA and the PMAs have sup-ported a number of energy conservation initia-tives. Energy efficiency improvements offer sev-eral opportunities, including reduced agency costsand increased ability to satisfy varied uses of riversystems.

I Tennessee Valley AuthorityTVA was created by Congress in 193364 as a

government-owned corporation with the broad

mission of resource and economic developmentfor the Tennessee Valley region, an 80,000 squaremile area extending to parts of seven States(figure 7-5).65 TVA conducts a wide range ofresource development programs including im-provement of flood control, navigation, andrecreation for the Tennessee River system, for-estry and wildlife development, and electricpower production. TVA also provides technicalassistance in such areas as industrial develop-ment, regional waste management, and tourismpromotion and has set up high-tech skill trainingcenters to meet the needs of regional businessesand industries. TVA supports a fertilizer researchfacility and a bioenergy research program at OakRidge, Tennessee. TVA is governed by a three-member board of directors who are appointed bythe President and approved by the Senate to serve9-year terms.66

TVA is the largest Federal power producer. Itserves some 110 municipal and 50 cooperativeutilities that distribute power to some 3.3 millioncustomers. TVA also provides power to about 50retail customers. In 1990, TVA generated 116million MWh, accounting for one-half of total net

62 ~H~ AccOUII@ ~% ‘‘Utility Demaad-Side Management Programs Can Reduce Electricity Use, ” GAO/RCED-92-13, October1991, 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.

,—


Figure 74-Federal Power Marketing Administrations Service Areas

l+ , L-q&)

/

/

vc+. , .*-

WAPAA PABPASEPASWPA

Western Area Power AdministrationAlaska Power AdministrationBonneville Power AdministrationSoutheastern Power AdministrationSouthwestern Power AdministrationArea 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 electricoperating revenues reported by the Federal elec-tric utilities.67

While TVA’s regional development programsare financed by congressional appropriations, thepower program is required by law to be finan-cially self-supporting through power sale reve-nues. Rates are to be set to cover capital andoperational costs. Power system operations ac-count for over 95 percent of the TVA budget.

In addition to hydroelectric plants, TVA main-tains coal-fired powerplants, nuclear powerplants,combustion turbines and pumped storage systems

68 Table 7-9 provides statisticsin its capacity base.

Figure 7-States in the Service Area of theTennessee Valley Authority

)“7 .

SOURCE: Office of Technology Assessment, 1993, based on datafrom the Office of Federal Register, The United States GovernmentManual 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 wifiregulations required by the 1990 Clean Air Act Amendments, TVA estimates that it will invest more than $1 billion on new pollution controltechnologies by 2000, increasing annual operating costs by $300 million. William Malec, “TVA Re-Examm“ es the Nuclear OptiorU’ Forumfor Applied Research and Public Policy, winter 1991, p. 89.


Table 7-9-Tennessee Valley Authority PowerSystem Statistics, 1990

Power system operators Million kWh

System salesMunicipalities and cooperatives. . . . .Federal agencies. . . . . . . . . . . . . . . . .Industrial customers. . . . . . . . . . . . . . .

Total sales. . . . . . . . . . . . . . . . . . . .

Power delivered under cogenerationagreement. . . . . . . . . . . . . . . . . . . . . . .Losses, etc.. . . . . . . . . . . . . . . . . . . . .

Total system output. . . . . . . . . . . .

System generation by sourceHydro (includes pumped storage)....Coal-fired. . . . . . . . . . . . . . . . . . . . . . . .Nuclear. . . . . . . . . . . . . . . . . . . . . . . . . .Combustion turbine. . . . . . . . . . . . . . .

Total net generation. . . . . . . . . . . .

Purchased power. . . . . . . . . . . . . . . .Net Interchange and wheel ing. . . . .

Total system Input. . . . . . . . . . . . .

96,7482,336

17,134116,483

1,168

3,135120,768

21,65478,50415,275

203115,636

9594,191

120,786

SOURCE: Office of Technology Assessment, 1993, based on datafrom Tennessee Valley Authority 1990 Annual Report, November1990.

on the TVA power system. TVA also coordinatespower output from Corps of Engineers dams inthe Cumberland Valley and from AluminumCompany of America dams.

In the recent past TVA ran extensive energyconservation programs. However, in 1989 mostof these efforts were terminated by TVA’s board,citing the financial stresses facing the system.From 1985 to 1988, TVA rate hikes averaged 4.5percent a year as the result of a combination of aproblematic nuclear program, expensive repairson coal-fired plants, and diminished hydroelectricproduction because of drought.69 TVA’s manage-ment felt its customer base was threatened as

some of TVA’s largest customers, includingMemphis Light Gas & Water, which then ac-counted for 10 percent of kilowatt-hour sales,began to explore alternative power supply options.

To secure its base of distributors, TVA prom-ised to freeze electricity rates for three yearsbeginnin g in 1988. Among the various actionstaken to reduce operating costs was elimination ofmost energy conservation programs. TVA offi-cials gave two reasons for discontinuing conser-vation programs. First was the pledge not to raiserates for the 3-year period. TVA’s managersreasoned that if sales declined because of success-ful conservation efforts, rates would likely haveto increase as fixed costs were spread over fewersales. TVA feared that increased rates wouldinduce large customers to leave the system,leading to further decline in sales. Second, TVAcited an internal analysis that concluded that ithad exhausted cost-effective conservation op-tions. 70 In TVA management’s view, finishingthe partially complete nuclear plants offered morecost-effective options than continuing conserva-tion programs to meet future electrical supply. Inthe summer of 1988, the TVA board of directorsapproved a transition program that began cuttingthe conservation staff. In 1989, then TVA Chair-man Marvin Runyon stated: ‘‘Conservation willadd to our rates. ’ ’71 In spring 1989, the boardvoted to terminate residential conservation pro-grams, cut personnel from 600 to 280, and reducethe budget from $40 to $20 million.72

Prior to termination, TVA conservation pro-grams were among the most extensive in thecountry, saving an estimated 913 MW in an8-year period from home weatherization pro-grams 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.

7 3 ~meS5ce ~le. Au~ori~, “EnerU s~ices Repofl ‘gT,’ ‘ NA/Op/~HS/lT, 1988, p, 43.


Table 7-10-Tennessee Valley Authority Major Energy Conservation Programs,Fiscal Years 1977-87

Estimated EstimatedNumber 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

2,62653,103

1,50416,246

53,287’57,037 d

22,518

26,500n/a

834,103

$375,001,000490,000

166,555,0001,108,0004,484,000

.——

4,947,000n/a

$552,585,000

1,802,300,0002,100,000

188,500,0004,100,000

79,100,000

—99,900,000

838,600,00050,200,000

3,064,800,000

913.01.0

58.4’0.8

55.4

54.079.430.8

17314

1,411

aValues shown are maximum seasonal reductions.blncludes residences weatherized with TVA loans, without TVA loans, and residences weatherized in a joint effortwith 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 higherthan the national average due to the large numberof homes heated by electricity .74 Residentialcustomers received services ranging from freeaudits to interest-free loans to financing forinstallation of conservation measures. In 1987,TVA celebrated the completion of 1 million homeenergy surveys. TVA had an extensive engineer-ing staff assisting individual commercial andindustrial customers with tailormade conserva-tion programs. Additionally, industrial customerswere eligible to receive information on relevantnew technologies from TVA representatives.TVA also participated in a number of energyefficiency R&D efforts. TVA demonstration pro-

grams showcased innovative home designs, new

water heaters, radiant barriers, and photovoltaicsand helped confirm the cost, reliability, andavailability of these emerging technologies.75

Table 7-10 highlights the major conservationprograms pursued by TVA.

After 1989, the programs remaining in TVA’sconservation budget are primarily educationaland information programs and strategic loadmanagement. The information programs includedistributing energy sourcebooks and other teach-ing materials, and operating a TVA energy centerfor teachers and students. The consumer energyefficiency information program provides bro-chures to customers on appliances. The EnergyManagement Program provides technical assist-ance to Tennessee county governments in identi-

T4 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.


fying opportunities for installation of energy-saving measures financed with State and Federalconservation funds.

The load management programs are designedto maintain and expand TVA’s customer baseload. In the industrial sector, TVA is encouragingthe use of electrotechnologies. In the residentialsector, the focus is on promoting construction ofall-electric homes. TVA “energy conservation”programs have effectively shifted in focus fromsaving kilowatt-hours to strategic load marketingand demand growth.

The Industrial Energy Services program is atechnical assistance program that works with thelargest industrial customers to determine theirenergy requirements. TVA personnel then iden-tify how to meet energy requirements cost-effectively and promote use of electrotechnolo-gies. TVA estimates that 20 percent of activity inthis program is concentrated on energy efficiencyimprovements.76

In 1989 TVA established the Residential En-ergy Service Program (RESP), which providestechnical and financial assistance for installationof energy-efficient electric heat pumps, andinformation on electric hot water heating systems.RESP is currently budgeted at $10.5 million.TVA offers bounty payments to distributors whosuccessfully encourage construction of new all-electric homes.77 RESP was designed to “helpTVA maintain a desirable balance between sum-mer and winter peaks by helping maintain winter

water heating and space heating loads. ”78 TVAprovides the loans and support materials to itsdistributors which are responsible for the admin-istrative costs. If a distributor does not participate,customers in its service area are not eligible forthe loans.79

Under the stewardship of Marvin Runyon,TVA was poised to expand its generating capacityand “committed itself to nuclear power as anintegral source for meeting the energy needs of itsservice area.”80 TVA demand is growing 1.5 to 4percent a year according to TVA load forecasts.TVA plans have called for completing fournuclear powerplants currently in the constructionor licensing stage by 2000.81 With the five unitsalready licensed, TVA anticipates that nuclearpower will supply 40 percent of its annualgeneration by 2000. This additional power will beused to meet projected growth in demand.82

With passage of the Energy Policy Act of 1992,TVA’s determination to eschew energy effi-ciency and build new nuclear generating capacitymay be stalled and its future path redirected.Section 113 of the act requires TVA to establisha least-cost planning program to develop aresource plan with the lowest system cost.83 Theplanning process must consider supply and de-mand resources, including renewable resources,energy conservation and efficiency, on a consist-ent and integrated basis. TVA must incorporateopportunities for its distributors to recommendcost-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. 16-25.8 0 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-DrivenTVA,” Energy Daily, May 4,1993, pp. 3-4.

S2 WTiU~ F, ~=, “WA Re-~~es the Nuclear OptiOL” Forum for Applied Research and Public Policy, winter 1991, pp. 87-90.

s3 ~bfic bW 1m4t3tj, &t. 24, 1992, sec. 113, 102 Stat, 2798, 16 U.S.C. 831m-1. !ktion 11303)(3) dcdines syStem cost =”~ ht ~dquantifiable net costs for an energy resource over its available life, including the cost of production transportatio~ utilization wasternanagemenl environmental compliance, and in the case of imported energy resources, maintaining access to foreign sources of supply.”

—-—.———


rate structure incentives, and renewable energyproposals for inclusion in the program.

In planning and selecting new resources, TVAmust evaluate the full range of existing andincremental resources (including new power sup-plies, energy conservation and efficiency, andrenewable energy resources) in order to provideadequate and reliable services to its customers atthe lowest system cost. The act further requiresTVA to provide opportunity for public review andcomment before selection of any major newenergy resource and include a description of theaction in its annual report to the President and theCongress

TVA was also directed to encourage and assistdistributors in the planning and implementationof cost-effective energy efficiency options andauthorized to provide a range of technical andfinancial services to advance these efforts.

The impact of these requirements on TVA’snuclear plans and its conservation programsremains to be seen. The act set no schedule forTVA’s least-cost planning process and did notinclude any explicit mechanisms for enforcementor ‘review. TVA is moving forward to developexpanded energy conservation programs andpreparing comprehensive DSM analyses for theupcoming integrated resource planning process.84

1 Bonneville Power AdministrationBPA, established in 1937, is the Federal

electric power marketing agency in the PacificNorthwest. 85 BPA markets hydroelectric powerfrom 21 multipurpose water resource projects ofthe U.S. Army Corps of Engineers, and 9 projects

of the Bureau of Reclamation, plus power fromnonfederal generating plants. These generatingstations and BPA’s 14,794 miles of transmissionlines and 389 substations make up the FederalColumbia River Power System. In marketing itspower, BPA must give preference to publicly-owned utilities and electric cooperatives.

BPA is the largest power wholesaler in theNorthwest, supplying half of the electricity andoperating almost 80 percent of the region’shigh-voltage power transmission capacity. BPAsells power at wholesale to local utilities and alsoprovides power to a small number of largedirect-service industrial customers86 and to otherFederal agencies. It participates in seasonal powerexchanges and maintains power coordination andtransfer agreements with utilities in other regionsand in Canada.

Under its authorizing legislation, BPA maybuild and operate transmission facilities andmarket power, but it is not authorized to build orown power generation facilities. To meet its firmpower contracts with its customers, BPA supple-ments its Federal hydropower supplies withpurchases from other utilities. Under the PacificNorthwest Power Planning and Conservation Actof 1980, BPA’s selection of nonfederal supplyand demand resources to meet its customersenergy needs is guided by a collaborative plan-ning process.87 The act also gave BPA responsi-bility for technical and financial assistance forenergy conservation and renewable resource de-velopment, and for fish and wildlife protection inthe 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 @p-of 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 ofBPAs 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.


The House Report provides some of the back-ground history that led to the legislation. 88 Forover 40 years, the Columbia River system wasable to provide the power requirements of BPA’spreference customers, Federal agencies, investor-owned systems, and direct-service industrial cus-tomers. The region enjoyed some of the lowestelectric rates in the country. In the 1970s, growingpower demand was outstripping BPA’s ability tomeet customer needs from available hydroelectricresources. Extensive hydroelectric developmentalso was blamed for declines in the region’s fishand wildlife, and corrective measures to protectsalmon and other species would reduce waterflows for power generation. The BPA administra-

tor warned that threatened power shortages couldforce it to curtail firm-power sales to investor-

owned utilities and direct-service customers andto allocate available resources among the prefer-ence 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 wi th i t s preference customers that

obligated BPA to purchase power generated from

the new plants. In return, the selling utilities

would rece ive credi t s on charges for power

purchased f rom BPA.89 However, this financing

mechanism was forec losed for addi t ional re-

sources by an adverse ru l ing by the In terna l

Revenue Service. Subsequent efforts also were

dera i led . The region’s u t i l i t ies and regula tors

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 ther-

mal powerplants would cost 10 times as much.

The alternative of energy conservation, was being

ignored, despite the existence of several success-

ful programs demonstrating cost-effective elec-

tricity 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 electricpower in the region is great. Kilowatts saved costa small fraction of the cost of producing anequivalent amount of kilowatts. All concede thata vast potential for energy conservation is beingwasted in the region.

As the costs of new generation have increased the

potential for cost-effective conservation pro-grams in the region have also increased. Unfortu-nately, the region appears to lack mechanisms toundertake an effective regional conservation ef-fort. BPA has limited authority to carry outconservation programs, and no authority to bor-row or underwrite funds to finance these pro-grams. Individual utilities (particularly publiclyowned systems) face many legal and practicalproblems which limit their conservation efforts.Further, under current conditions it could beseveral years before many customers of BPApreference customers will face the kind of pricesignals that would encourage them to investmoney in cost-effective conservation measures.

. . . In the absence of a coordinated regional powerprogram, it is probable that conservation efforts inthe region will be too slow, too scattered, and toomodest to be effective; and the region would thuslose a good portion of conservation’s potentialeconomic benefit.90

The report concluded:

The certain inability of the region to resolve itsproblems without legislation represents a seriouseconomic, 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.


region, and by implication to other regions of thecountry. The continued failure to use existingresources and conservation effectively and to planefficiently for future needs raises the potential ofsevere regional electrical power shortages in thisdecade.91

The solution was to create a public planningprocess enabling States, localities, consumers,BPA customers, fish and wildlife agencies, Indian

tribes, users of the Columbia River System, andthe public to participate in the region’s electricpower decisionmaking process. The act author-ized BPA to acquire additional resources on along-term basis, consistent with the regional plan,and giving frost priority to conservation andrenewable resources. It also clarified BPA’sauthority to enter firm power sale contracts withinvestor-owned utilities and direct service cus-tomers.

In form and practice, the regional planningprocess used by the Pacific Northwest PlanningCouncil and BPA resembles utility IRP processesin wide use today. In 1980, however, the actmarked a bold innovation in Federal and Statecollaboration. The act also required that conserva-tion be treated as a resource, and that all resourcesbe evaluated to determine the best and lowest-costalternatives to meet the region’s electricity needs.In planning and selecting resources, priority wasto be given first to conservation; second, renew-able resources; third, generating resources utiliz-ing waste heat or generating resources with highfuel-conversion efficiency; and fourth, all otherresources, including conventional thermal power-plants .92

BOX 7-F summarizes the planning proc-

ess created by the act and the results of BPA’smost recent resource plan.

BPA CONSERVATION ACTIVITIES

The Northwest Power Act of 1980 directedBonneville to use conservation to the fullestextent possible in its resource mix and authorizeda wide range of technical and financial assistanceto encourage energy efficiency and renewableenergy development.

BPA has had more than a decade of experiencein developing, administering, and evaluatingenergy conservation programs. Its programs areextensive and serve customer utilities, residential,commercial, and industrial consumers, and Stateand local governments. Customer outreach pro-vides technical and financial assistance for con-servation measures. BPA pays part of the cost ofresidential weatherization. Hotlines inform com-mercial and industrial customers about emergingenergy-efficient technologies. BPA has assistedState and local governments with the develop-ment and implementation of model energy con-servation codes, and offered financial incentivesto jurisdictions that adopt and enforce the codes.BPA also has underwritten extensive demonstra-tion programs to test energy-efficient technolo-gies and provide cost and performance informa-tion to their utility customers and others.

BPA’s resource plans and energy conservationexperience also contribute to the system’s flexi-bility in responding to changing conditions. InApril 1993 BPA outlined a number of emergencymeasures intended to head off or reduce apotential 25 percent rate hike on October 1, 1993.Among the circumstances that have contributedto the financial crisis were a drought that de-creased sales and required BPA to purchasereplacement power to meet its loads and the lossof one-quarter of its direct sales to aluminumcompanies. In an attempt to hold the priceincrease below 20 percent, BPA announced that

91 Ibid, p. 27.92 pJ~fiWeSt poWer p- and conse~ation Act, 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 betreated as greater than that of any non-conservation measure or rwource unless the incremental system cost of such conservation measure orresource 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).


Box 7-F--Regional Power Planning: The Bonneville Power Administration and thePacific Northwest Power Planning Council

‘Ten years ago, the Pacific Northwest embarked on a grand experiment It was a test initiated by theNorthwest 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 CouncilThe 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 BonnevillePower Administration’s resource planning and selection. The act requires that BPA's resource acquisition beconsistent 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 implementationof the resource plan and efforts at depbyment of conservaton and renewable energy resurces in the region. Theact also gave the Council responsibility for developing a program to protect and enhance fish and wildlife andrelated 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 ofthe 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 hearingson the proposed plan and for an ongoing public information and outreach program to involve State and Federalagendas, Indian tribes, customers, and the public In the planning process.

The Planning ProcessThe 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 ofresource options;a 20-year demand forecast covering the amount and types of resources needed to rneet BPA obligationsimpacts 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 probablecost and the met-effective means of providing them;the fish and wildlife protection, mitigation, and enhancement program; andrecommendations, if any, for surcharges to be imposed on customers not implementing energyconservation standards.5

Energy conservation and renewable energy resources are given the highest priority for new resources. The actprovides 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 ofpower needs and recommendations for resource acquisition.6The early plans weredeveloped during a timewhen


the region faced an energy surplus from the overbuilding in the 1970s. The 1991 plan addresses a tightening powersupply. The plan forecasts a potential for a capacity deficit by the turn of the century unless new resources areacquired.

The plan analyzed a number of electricity demand growth scenarios ranging from one where average demanddeclines at a rate of-0.4 percent per year to one with a high growth rate of 2.5 percent per year, however moreemphasis was placed on mid-range growth levels of 0.6 to 1.7 percent per year.7 The council developed severalalternative resource portfolios containing various mixes of supply and demand resources capable of meeting thefull range of energy demand reflected in the scenarios. Potential supply and demand resources were evaluatedby examining total costs including direct costs and enviromnental impacts, and reliability. Other evaluation criteriaincluded lead times, size, and capital cost. Based on its analysis and public comment, the council plan adoptedfour objectives for a regional energy strategy.

1.

2.

3.

Acquiring all low-cost resources-The plan recommends that BPA and regional utilities acquire 1,500average megawatt (aMW)8 of conservation and energy efficiency improvements at a total cost to utilitiesand customers of $7 billion (see figure on next page). This would entail aggressive efforts to installefficiency measures in the residential, commercial, industrial and agricultural sectors at a level many timesgreater than current DSM and conservation programs. Efficiency improvements in powerplants,transmission, and distribution facilities would contribute 360 aMW of conservation savings. In addition, theplan callsfor 150 aMWof new, Iow-cost hydropower and 650 aMWof Iow cost industrial cogeneration bythe year 2000.9

2. Shortening lead times needed to bring new resources into operation to enable quick and flexibleresponses to rapid load growth. The plan would reduce lead times by beginning inexpensivepre-construction preparations such as siting, permitting, licensing, design, contracts, and other approvalsto enable addition of 100 aMWof new hydropower and up to 750 aMW of cogeneration to resource plansif demand growth is higher than anticipated. These pre-construction activities often are among the mosttime-consuming in developing new power resources. The council also recommends that BPA and utilitiesinvestigate cost- effective backup power supplies for 1,500 aMW of the region’s non-firm hydropower toaccommodate potential impacts of fish and wildlife protection programs. Good candidates for“hydrofirming” include interregional energy transactions, increased interruptible loads and gas firedcombustion turbine plants.10”Confirming the cost and availability of additional resourocs that could be incorporated into futureplans--The plan callsforsupport of research, development, and demonstration efforts for resources thatare not yet ready for utility-scale deployment including new energy conservation and renewable energytechnologies (such as geothermal, wind, and solar generating technologies). Additionally, the councilrequests that BPA determine whether the continued preservation of its two uncompleted nuclear powerplants 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 usedto refer to @@ty, the maxinwm output of an electrical generator. Because most generators do not runcontinuouety, securing 1 aMW of resources may require acquisition of more than IMW of capadty.

9 Ibid., pp. 31-3610 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 estimatedthat more than $3 blIlion would benecessarytocompiete the plants. BPAandregional planners have conc!udedthatmore than 5,000 MWfrom other sources at prices of $0.03/kWh making electridty from the two nuclear plants at anestimated $0.04MVh uneconomic.



Box 7-F–Regional Power Planning: The Bonneville Power Administration and the PacificNorthwest Power Planning Council--Continued)

Recommended Resource Acquisitions of the1991 Northwest Conservation and Electric Power Plan

- Transmission upgrades %

235 Mw

,,,, \N Efficient businesses435 MW

,“, W, ,, ,a, , ,,315 M W Efficient homes

495 MW

SOURCE: Office of Technology Assessment, 1993, from Northwest Power Planning Council, 1991 Northwest Conservation andElectric 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 needarise. Rapid-response resources include acquisitions through bidding, and alterations to existingcombustion turbine resources. The council states that “if sufficient rapid-response resources cannot beidentified, it may be necessary to seek interruptible loads and develop curtailment strategies untilresources with longer lead times can be added.”12

Encouraging regulatory and other lnstitutional changes to help implement theplan--The plan detailsrecommendations for a variety of actions by BPA State regulators, utilities and Iocal governments to easethe implemental’bn of the council plan. Among the suggestions are that regulators consider changes todecouple profits from the energy sold and relink profits to energy saved and review policies to ease thesiting and acquisition of generating resources. Regulators were encouraged to consider appropriate ratetreatment for investing in activities that reduce resource lead times, and for participation in researchactivities to confirm/deny potential resources. Lastly, the council urged cooperation between regulatory

12 Ibid., pp. 31-43.


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 bysupport of environmental, consumer groups and the public. The Council notes that it will monitor progress inaddressing 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 identifiesconservation as its preferred resource. BPA assumed a 1 percent annual growth rate and proposed acquiring1,530 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 systemefficiency 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 ifdemand growth is higher than forecast. BPA will reserve the right to cancel selected projects on option in exchangefor reimbursing the sponsor’s pre-development costs.

To accomplish its goal of accelerated acquisition of conservation resources, BPA is making major changesin the operation of its conservation programs and how it pays for energy savings. Program development anddecisionmaking will shift from headquarters to BPA area offices which will collaborate with utilities and localcommunities in designing and implementing local conservation plans. Under the Northwest Power Act BPA canpay utilities and others for conservation resources that reduce BPA’s loads. BPA anticipates securing conservationresources 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 measurablesavings over time. Verification of energy savings will be required in the performance contracts. BPA expects utilitiesto provide a substantial portion of the necessary capital for installing conservation measures rather than relyingon BPA to provide financing. BPA also will continue to require utilities that own generation to pay a percentageof the cost of conservation in their service area, based on the percentage of the utility’s load supplied by BPA. Thiscost-sharing is required so that nongenerating utilities do not pay a disproportionate share of conservation programcosts. For some utilities, current cost-sharing percentages have, however, created a financial impediment tomeeting accelerated conservation targets and BPA is investigating alternative mechanisms for an equitablesharing.

The accelerated conservation path and will face several challenges. There will have to be unprecedentedcooperation among all groups in the region to identify and install all commercially available cost-effectiveconservation measures. Utilities and governments will need greater staff, technical, and financial support from BPAto develop and carry out local conservation programs. Regulators will have to review policies and rate structuresfor 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 resourceprogram released in November 1992.

15 Ibid., p. 48.

16 Ibid.r pp. 26-33. (Continued on next page)


Box 7-F–Regional Power Planning: The Bonneville Power Administration and the PacificNorthwest Power Planning Council--(Continued)

Savings to DateIn 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 programsand incentives. They have already saved more than 350 megawatts at a cost less than half of the powerfrom a new generating plant Aluminum companies also have cut their consumption. And state energyoffice programs brought Us another 200 megawatts.

New energy-efficient building codes and appliance standards already adopted by Federal, State andlocal 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.


it is cutting all programs by 25 percent, including important link in regional power systems. West-conservation and fish and wildlife activities, and em serves some 532 wholesale customers, mostlyadministrative programs by 50 percent. The cuts public power systems and electric cooperativesare 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 utilitiesand slowdowns in prgram growth. and Federal and State agencies. Western supplies

an average of 35 percent of its customers’ powerI Western Area Power Administration needs. 95

WAPA was established in 1977 under section302 of the Department of Energy OrganizationAct to market power in a 15-State area generatedfrom federally-owned powerplants operated bythe Bureau of Reclamation, Corps of Engineers,and the International Boundary and Water Com-mission. 93 It also markets Federal entitlementpower from the coal-fried Navaho GeneratingStation. WAPA operates and maintains 16,500miles of transmission lines, plus associated sub-stations to deliver power to its customers. LikeBPA, Western’s transmission resources are an

In 1981 WAPA established its own conserva-tion and renewable energy program with threeobjectives:

1.

2.

3.

reducing wasteful uses of electricitythrough energy conservation;

enhancing the place of electricity in theenergy market by making uses of electricpower more efficient; and

ensuring that conservation and renewableenergy technologies are fairly compared

95 Bill Clage~ Administrator, Western Area Power Admxu“ “stration, letter to O’IX, Sept. 18, 1992.


with conventional resources when addi-tional power is required.96

Title II of the Hoover Power Plant Act of 1984essentially confined Western’s conservation andrenewable energy program and its pre-existingauthority to condition contracts for Federal hy-dropower on customer adoption of conservationprograms. 97 Indeed, the act explicitly requiresnew firm power contracts with WAPA to containprovisions obligating the purchaser to implementenergy conservation programs. Unlike BPA, West-ern is not required to meet wholesale customerload growth, however, it must purchase power tomake up for short-term power shortages indrought periods in order to meet its firm powercontractual commitments. Western can withholdpower from a customer that has not implementedconservation programs or that do not submit aplan within a year of signing a power contract.

Following the 1984 legislation, WAPA pub-lished amended guidelines and criteria for evalu-ating the adequacy of customer utilities’ conser-vation programs.

98Long-term firm power cus-

tomers must submit a plan describing qualifyingprogram activities, the implementation schedule,targeted goals, and energy savings estimateswhere feasible. Qualifying customer programs,include: energy consumption efficiency improve-ments; production efficiency improvements, loadmanagement, cogeneration, rate design improve-ments, and renewable energy resources (wind,solar, biomass, small-scale hydro, and geothermaltechnologies). Western allows considerable flexi-bility in program design. The acceptability ofcustomer conservation and renewable energyplans is determined based on utility type and totalsystem sales. For example, most customers with

over 100 gigawatt-hours (GWh) per year in saleshave been required to implement five individualprograms. Customers with sales of less than 50GWh per year need only submit three programsfor acceptance.

Western provides additional support to cus-tomer utilities through a variety of informationand technology transfer activities: workshops,information services, publications, direct techni-cal assistance, onsite visits, equipment loans, andIRP computer software. Under a “peer match-ing’ effort, Western has matched small customerutilities to others with first-hand experience andexpertise in conservation and renewable energytechnologies. This has been particularly helpful tosmall rural communities with limited staff andresources.

Estimates of energy or capacity savings result-ing from the Western’s requirements are notavailable at present. Western measures programaccomplishments by the number of approvedongoing annual customer conservation and re-newable energy activities. For FY 1992, Westernreports almost 100 percent participation by thenearly 800 customers, with a total of 3,200separate approved activities.99 In any event,Western believes that because Federal hydro-power is a low-cost resource, customer conserva-tion activities would likely not be used to reducetheir power purchases from WAPA, but rather tooffset their own higher-cost thermal power sup-plies from utilities’ own generation or fromothers. In 1990 electricity savings from operatingconservation programs were insufficient to offsetthe power loss caused by drought conditions.Western spent an additional $267 million forpower 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 theDepartment 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, October1991, p. 33.


of Western’s statutory responsibility to marketavailable Federal hydropower and contractualobligations to supply power to its customers(including replacement power supplies in times ofdrought), customer DSM programs will not re-duce the amount of power that Western markets.They may, however, allow that low-cost resourceto serve a higher portion of customer require-ments and to be shared more equitably.

Proposed revisions to WAPA’S conservationprogram begun in 1990 and now under reviewwould add requirements for adoption of IRPprograms and also would require customers toquantify energy and capacity savings from theirprograms. Changes would also directly linkallocation of hydro resources to long-term plan-ning and efficient use of resources and imposesurcharges on customers that did not comply.l0l

Many elements of WAPA’S proposed EnergyPlannin g and Management Program were adoptedby section 114 of the Energy Policy Act of 1992,which amends the Hoover Power Plant Act of1984 to add a new title on IRP. WAPA mustpromulgate rules within 1 year amending renew-able resource and conservation plan requirementsfor its long-term firm power customers to includeprovisions calling for customer utilities to imple-ment IRP within 3 years. WAPA is to providetechnical assistance to customer utilities in devel-oping IRP programs and review the plans pre-pared. Definitions of IRP, system costs, andleast-cost resource options in the act requireevaluation of supply and demand resources in aconsistent, integrated manner to select optionsthat minimize life-cycle costs including adverseenvironmental effects, and give priority to energyefficiency and renewable energy to the extentpracticable. Failure to submit a plan or to complywith an approved plan will trigger surcharges of

from 10 to 30 percent on purchases from WAPA.Alternatively, the Administrator can curtail powerallocations by 10 percent until a customer com-plies. No penalties will be imposed if the Admin-istrator determines that the utility has made agood faith effort to comply. Several provisionswere added in recognition of the diversity ofWestern’s customer utilities and to avoid duplica-tion of requirements by State regulators or others.For example, two or more utilities can collaborateto submit joint IRP plans, and plans preparedunder State or other IRP programs can also beaccepted by WAPA.

1 Southwestern Power AdministrationSWPA operates as the marketing agent for

Federal hydroelectric power in a six-State area.102

It was created in 1943 by the Secretary of theInterior for the transmission and sale of electricpower from certain Corps of Engineers reservoirprojects and assumed responsibilities under theFlood Control Act in 1944. SWPA has been underthe direction of DOE since 1977.103 Undervarious authorizing legislation, SWPA’S mandateis to market Federal hydropower to encourage themost widespread and economical use at thelowest possible cost, consistent with sound busi-ness principles.

104 SWPA supplements its power

supplies with power purchased from public andprivate utilities to meet its contractual obliga-tions. By law, publicly-owned utilities and coop-eratives receive preference in power allocations.SWPA operates and maintains some 1,380 milesof transmission lines, 24 substations and switch-ing stations, and 39 radio and microwave sta-tions. l05 With these facilities, SWPA sells powerwholesale 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.


dispatching power, negotiating power sales con-tracts and constructing facilities, and participat-ing in comprehensive planning of water resourcedevelopment. Rates to its customers are adjustedto ensure full recovery of Federal investment.

According to a GAO report, SWPA sought toclarify its authority to require its customers toadopt DSM programs. DOE’s Office of Conser-vation and Renewable Energy responded that‘‘SWPA has implicit authority under Section 5 ofthe Flood Control Act of 1944 to encourageconservation programs among customer utilities,and could propose in the absence of more explicitlegislative authority, conservation programsthrough rule-making actions, subject to depart-mental approval. ’ 106 DOE noted, however, thatany attempts to implement programs could besubject to challenge in the courts.

SWPA supports various activities to encourageDSM and IRP. It maintains a program to loanenergy-efficient equipment for its customers andprovides technical assistance through workshops.Together with WAPA and others, it is jointlyfunding a project to prepare detailed IRP manualsto assist utilities in developing and implantingIRP programs.

1 Southeastern Power AdministrationSEPA was created in 1950 by the Secretary of

the Interior to carry out the functions of the FloodControl Act.107 SEPA operates under the generalmandate to encourage widespread use of electric-ity from Federal hydro projects at the lowestpossible rates consistent with sound businessprinciples and to give preference to publicly-owned utilities. Responsibilities include provid-

ing for the transmission and sale of surpluselectric power generated at Corps of Engineersreservoir projects in a 10-State area of theSoutheast. 108 SEPA does not own or operate anytransmission facilities of its own; transmissionlines owned by other utilities deliver the power.SEPA markets power from a total of 22 Federalmultipurpose water projects, giving preference topublic bodies and cooperatives. Using the re-gion’s large private utilities, SEPA negotiateswheeling and pooling arrangements to providefirm power to its customers. Rates charged tocustomers are adjusted to ensure that the FederalGovernment recovers its investment plus interest.Oversight of SEPA programs was transferred tothe newly created DOE in 1977.109

SEPA does not have any explicit statutorymandate to promote DSM, IRP, or regionalcooperation in power planning. However, likeSWPA its authorizing legislation has been inter-preted to support initiatives to promote energyconservation. 110 Southeastern is offering energy-efficient training programs for cooperatives andmunicipalities.

1 Alaska Power AdministrationAPA is responsible for the operation and

maintenance of the Snettisham and Eklutna hy -droelectric generating projects in Alaska andmarkets the power produced. APA also operatesassociated transmission systems serving Anchor-age and Juneau.

For the past several years, DOE has beennegotiating with the State of Alaska to sell theassets. The Alaska Power Administration SaleAuthorization Act submitted to Congress by DOE

1~ Gener~ Accounting Offia, “Utility Demand-side Management Programs Can Reduce Electricity Use,” GAO/RCED-92-13, October1991, 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, October1991, p. 37,


in June 1992 would sell the 78-MW Snettishamproject to the Alaska Energy Authority and the30-MW Eklutna project to three electric powerutilities serving the Anchorage area. Over 90percent of the State’s electricity is now providedby nonfederal generating sources leading DOE toconclude that there is no longer a need forAPA.111

APA has been assisting a customer utility withevaluating and testing demand as well as supply--side energy efficiency measures.

RURAL ELECTRIFICATIONADMINISTRATION

REA is a credit agency within the U.S.Department of Agriculture (USDA) that makesloans and loan guarantees to finance the construc-tion and improvement of electric power systemsto serve the needs of rural areas. The agency wasestablished during the New Deal to extendelectric service to remote areas not served byprivate utilities.

112 REA loans enabled borrowers

to form electric cooperatives to build power linesfor transmission and distribution of wholesalepower purchased from private utilities or fromFederal hydroelectric facilities. REA also guaran-tees loans made by others, and approves securityarrangements that permit borrowers to obtainfinancing from other lenders without a guaran-tee.113 Since the 1960S, REA has made loans for

the construction of generating and transmissionfacilities “to protect the security and effective-ness of REA-financed systems. ’ ’114 REA is also

authorized to provide technical assistance to itsborrowers to aid system development and toprotect loan security. In 1990, there were 897cooperative borrowers; 838 were distributionborrowers and the remaining 56 were generationand transmission cooperatives. (See table 7-12.)

Loans are made through the Rural Electrifica-tion and Telephone Revolving Fund created in1973. By law, REA loans are made at a 5 percentinterest rate and as low as 2 percent for extremehardship, and for years REA rates were below theprevailing market rates for direct borrowing.115

REA requires most borrowers to obtain 30percent of their financial needs from outsidesources to comply with a statutory requirementadded in 1973 directing REA to encourage ruralelectric systems to enhance their ability to obtainfinancing from their own financial organizationsor other sources.

116 Many cooperatives obtain this

financing from the National Rural Utilities Coop-erative Finance Corporation and the Bank forCooperatives.

REA loan guarantees have been made primar-ily to large-scale facilities and are subject to thesame requirements as direct loans. Interest rateson guaranteed loans are established at rates set bythe borrower and the lender with REA concur-rence. Since 1974, the Federal Financing Bank(FFB) has purchased obligations guaranteed bythe REA, although all borrower dealings werewith REA. A 1981 amendment to the RuralElectrification Act required the FFB to makeloans 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. Proposalsfor privatizing the PMAs have been circulating for more than a decade through both the Reagan and Bush Admm“ “strations and have met SWresistance 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 directborrowing 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 ratesand terms consistent with the loan’s applicant’s ability to pay. ’ Ibid.

do so by a utility who held a guarantee. Now, mostREA-guaranteed loans are made by the FFB.117

In January 1992, REA issued a final rulerevising the requirements for general and preloanprocedures for insured and guaranteed electricloans. 118 These regulations were in large part arecodification of many of REA’s existing policiesand rules. REA loan requirements contain severalprovisions that encourage IRP and utility energyefficiency programs. All borrowers are encour-aged to promote energy efficiency and loadmanagement to improve system load factors,reduce losses, and reduce the need for newgenerating capacity. 119 Most REA borrowers

must prepare and maintain power requirementsstudies (PRS) and construction work plans (CWP)for review and approval by REA. Together thePRS and CWP require a borrower to establish acomprehensive and integrated planning system toguide operations and resource acquisition, effec-

120 To qualify for new loans,tively an IRP process.a borrower must demonstrate to REA that it hasexplored all practical and feasible alternatives toadding new capacity, including improved loadmanagement, energy conservation, and powerpurchases from other suppliers, including inde-pendent power producers. REA believes that therule changes are expected to lead to a moreeffective power planning process.


FEDERAL ENERGY REGULATORYCOMMISSION

FERC regulates prices, terms, and conditionsof wholesale power sales and rates involvingprivately-owned power companies and of trans-mission of electricity at wholesale.121 With thegrowth of wholesale transactions in the utilitysector, FERC now regulates about one-third of

Table 7-1 l—Rural Electrification AdministrationCooperative Distributor Borrowers: Consumers,

Sales, and Operating Revenue 1990

Number of consumers on December 31Residential. . . . . . . . . . . . . . . . . . . . . . . . . . . . 9,732,694Commercial and industrial. . . . . . . . . . . . . . . 915,363Other sales to ultimate consumers. . . . . . . . . 153,324

Total ultimate consumers.. . . . . . . . . . . . 10,801,381Sales for resale, . . . . . . . . . . . . . . . . . . . . . 203Total consumers . . . . . . . . . . . . . . . . . . . . 10,801,584

Sales for the year (mWh)Residential. . . . . . . . . . . . . . . . . . . . . . ......111,776,522Commercial and industrial. . . . . . . . . . . . . . . 65,794,723Other sales to ultimate consumers. . . . . . . . . 5,814,007

Total sales to ultimate consumers . . . . . 183,385,252Sales for resale. . . . . . . . . . . . . . . . . . . . . . 3,095,647Total Sales. . . . . . . . . . . . . . . . . . . . . . . . . 186,480,899

Operating revenues for the year ($000)Residential. . . . . . . . . . . . . . . . . . . . . . . . . . . . 8,403,275Commercial and industrial. . . . . . . . . . . . . . . 3,806,505Other sales to ultimate consumers . . . . . . . . . 374,504

Total sales to ultimate consumers . . . . . 12,684,284Sales for resale. . . . . . . . . . . . . . . . . . . . . . 121,008Total revenue from sales of electricity. 12,805,290Other operating revenues. . . . . . . . . . . . . . 196,248Total operating revenues. . . . . . . . . . . . . 13,001,538

NOTES: Totals may not equal sum of components because ofindependent rounding. This table does not included in 1990 the 56 PowerSupply Borrowers. Data for 1990 represents 838 Distribution Borrow-ers.

SOURCE: Office of Technology Assessment, 1993, based on datafrom 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 PrintingOffice, February 1992), table A4, p. 349.

electricity sold. FERC also approves rates forpower sold and transported by the five powermarketing administrations.

There have been suggestions that FERC couldas a matter of policy under its existing broadauthority over wholesale transactions requireutilities selling power at wholesale to engage inIRP and offer DSM programs and require sellersto 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.


with the buyer’s approved IRP program. Forexample, President Bush’s National Energy Strat-egy suggests FERC promote utilities’ use of IRPthrough its rulemaking authority and its regula-tory powers.

122 To open discussions, from 1991 to

1992 FERC held several workshops with Stateregulators to explore IRP, transmission, andmarket-based pricing issues. However, FERC hasnot yet defined any potential role in promotingIRP or DSM, nor has it been actively pursuingissues related to energy efficiency or least-costplanning for utilities engaged in wholesale powersales and transmission.

ENCOURAGING VOLUNTARY EFFORTSIn recent years, there has been growing interest

in mechanisms that the Federal Government canuse to provide various incentives to utilities andothers to implement energy efficiency programsvoluntarily. These efforts are in addition to, andnot a replacement for, the variety of programs thatestablish more or less mandatory requirements forutilities or that offer technical and financialassistance to aid utility energy efficiency andplanning. Examples of this approach include the“green programs” in EPA’s office of climatechange, the conservation and renewable energyemissions allowances reserve under the Clean AirAct Amendments, and energy efficiency awardsprograms for Federal facility managers.

EPA’s Green ProgramsThe EPA Office of Atmospheric Programs has

embarked on several initiatives designed to en-courage the voluntary adoption of energy-efficient and pollution-reducing technologies aspart of EPA’s global climate change activities.EPA’s green programs marshall the agency’sstores of good will, credibility, and visibility in

combination with market forces to attract com-mercial, industrial, utility, and government par-ticipants to cooperative efforts to overcome someof the barriers that have hampered investment inenergy-efficient and environmentally-friendly tech-nologies. Among the goals most of these pro-grams share are:

Changing corporate and consumer purchas-ing patterns to favor efficient productsthrough information availability and exhor-tation; 123

Creating a market pull and lower prices forefficient products through aggregated pur-chases (group buys) and changes in long-term procurement patterns;Encouraging utility rate reforms to rewardinvestments in energy efficiency;Expanding international markets for high-productivity and energy-efficient products;andChanging industrial practices and processesto reduce emissions of greenhouse gases.l24

The Green Lights Program is the largest andmost prominent of EPA’s green programs. It wasestablished in 1991 as a voluntary programdesigned to encourage U.S. corporations to retro-fit their buildings with cost-effective lightingmeasures. According to EPA estimates, commerc-ial and industrial lighting amounts to some 20percent of total electricity consumption. Byreducing energy use from lighting, EPA antici-pates a lower amount of pollutants associatedwith fuels from electricity generation. In particu-lar, EPA estimates that more efficient lightingcould lower greenhouse gas emissions by 22 to 55million metric tonnes of carbon. EPA is relyingon the lure of cost-savings, and higher profits, andthe promise of technical assistance to attractparticipants.

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.


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) withEPA committing to survey their U.S. facilitiesand install all profitable lighting retrofits in 90percent of total square footage within 5 years. Inreturn, EPA offers encouragement, information,product testing, technical assistance, and publicrecognition to organizations. Green Lights helpspartners overcome barriers to energy efficiencyby providing technical assistance as well asinformation on products and financing. EPA-provided software and training help businessesidentify the retrofit options that maximize sav-ings. The National Lighting Product InformationProgram provides reliable information aboutlighting technologies and options to corporationsconcerned about product claims or potentialemployee response to lighting changes. EPA alsosupports participants through a registry of utilityrebates, energy service companies, banks andleasing companies providing financing.

The over 350 Green Lights “allies” includelighting manufacturers and energy managementcompanies, and electric utilities that agree toeducate customers about energy efficient light-ing. EPA’s utility ally program promotes cooper-ation in publicizing the many benefits of energyefficient lighting, EPA invites utilities to sign aMOU under which the utility agrees to:

■ complete profitable lighting retrofits in 90percent of the square footage of its ownfacilities;

■ assist EPA in marketing Green Lights andenergy-efficient technologies to its industrialand commercial customers;

■ participate in the ongoing lighting productand employee information programs; and

= assist EPA in documenting savings fromlighting upgrades in their service area.

In return EPA agrees to:

reen-Lights

provide tools and methodologies for pollu-tion prevention calculations, energy savings,dollar savings, and lighting upgrade designs;provide materials to help the utility’s effortsto promote high quality energy-efficientlighting; andenhance the energy-efficient lighting marketby working with the lighting industry toimprove consumer confidence in productavailability, quality, and value.

EPA also promises utilities that participation inGreen Lights will enhance their corporate imageby showing their concern and involvement inenvironmental protection. Green Lights also of-fers utilities support for their own DSM objec-tives and access to a national network providinga timely exchange of information on programeffectiveness, experience, and decision-supporttools.125

EPA has also enrolled the assistance of varioustrade, conservation, and professional associationsas Green Lights endorsers.

Green Lights builds on the realization thatprotecting the environment has become an attrac-tive product marketing angle. As an additionalincentive, EPA authorizes participating compa-

1~ “U.S. EPA Green Lights, Utility Ally Program, ” flyer, April 1992.


nies and allies to use the EPA Green Lights logoin advertising and promotional materials. EPAalso displays corporate logos of participants in itsown publicity and recruitment materials andadvertising.

As of May 1993, some 2300 Green Lightsprojects encompassing over 220,000 square feetwere in the process of being surveyed andretrofitted. Approximately, 40,000 square feet ofretrofits were complete. EPA estimates that if allparticipants enrolled as of May 1993 complete theupgrading of their facilities, more than 3.3 billionsquare feet will have been retrofitted.126 Annualsavings on participants’ electric bills will totalover $1 billion annually, according to EPA, andmore than $6 billion in new powerplant invest-ments will be avoided. Lighting upgrades willprevent emission of some 21,378 million poundsof carbon dioxide annually-the equivalent ofremoving over 2.1 million cars from the roads.Additionally, EPA estimates that program invest-ments in lighting upgrades will create some66,000 job years.

Because the agreements are voluntary, thereare no enforcement mechanisms under whichEPA can compel participants to fulfill theirpromises. EPA, however, is monitoring the paceof installations and has indicated that if partici-pants fail to follow through, EPA will bring addedpressure on them to do so.

Green Lights advances several objectives. First,it helps overcome informational barriers to in-stalling more efficient lighting through advertis-ing and technical assistance provided by EPA.Second, by expanding the pool of customers forenergy-efficient lighting services, EPA is helpingto create a market pull for efficient products andservices. Third, this market expansion couldeventually help lower prices of these productsthrough improved economies of scale in manu-facturing and distribution. Lastly, the programcan help lower first-cost barriers to participation

by collaborating with various utility and govern-ment programs that provide loans and rebates forinstalling efficient lighting.

EPA is also creating a partner lighting programfor the Federal Government, entitled FederalGreen Lights. A similar program dubbed GreenBuildings, which will launch a cooperative effortto incorporate energy-saving construction andbuilding, ventilation, and air conditioning tech-nologies in commercial buildings, is under devel-opment.

Building on the success of Green Lights, EPAhas launched an energy efficiency labeling pro-gram designed to sell consumers and manufactur-ers on the advantages of energy efficient products.The first application, the EPA Energy StarComputers program is a voluntary partnershipwith EPA and the computer equipment manufac-turers to manufacture and market computer equip-ment incorporating energy-saving technologies.In return the participants gain the right to use theEPA pollution preventer logo in marketing andadvertising. For more on this program see chapter4. Other cooperative efforts under considerationare showerheads, residential room air condition-ers, and cooking equipment.

Another innovative initiative is the “GoldenCarrot” program-a consortium of 25 utilitiesthat is sponsoring a contest for the developmentand production of a super-efficient regrigeratorthat is free of ozone-depleting CFCS. The winningmanufacturer will receive a bonus of $28 millionand orders to deliver up to 300,000 units toparticipating utilities for use in their DSM pro-grams. The award will be announced in summer1993. For more on the Super Efficienttor Program (SERP), see chapter 4.

9 Conservation and RenewableEnergy Reserve

Refrigera-

The Clean Air Act Amendments of 1990 acidrain 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.


sulfur dioxide (S02) emissions allowances to aconservation and renewable energy reserve.127

The EPA Administrator can make allowancesfrom the reserve available to eligible utilities thathave reduced S02 emissions by installing quali-fied cost-effective conservation measures or re-newable energy generation after January 1, 1992.These allowances will be made available begin-ning January 1, 1995, and can be used forcomplying with the acid rain emissions limita-tions. The amendments set a number of require-ments for eligibility. The utility must adopt aleast-cost planning process that evaluates a fullrange of resources including conservation andrenewable energy sources to meet future demandat the lowest system cost. The plan must beapproved by the utility’s State regulatory author-ity and the qualifying measures must be consist-ent with the plan. For conservation measures,State-regulated utilities must obtain DOE certifi-cation that State regulators have adopted rateprovisions that assure that the utility’s net incomeafter installing the qualified conservation meas-ures is at least as high as it would have beenwithout the energy efficiency measures.in

DOE certification of this “net income neutrali-ty status’ for DSM investments involves reviewof the regulatory treatment of conservation pro-gram expenditures, such as decoupling adjust-ments, lost revenues, and performance incen-tives. 129

DOE certification must be obtainedbefore the utility implements the qualified conser-vation measure. DOE is processing certificationson a “first-come, first-served” basis, and mustalso certify that the utility is actually implementi-ng the conservation measures it developed inqualifying for the emission allowances.130

1 Federal Energy Efficiency Awards

Two awards programs administered by theFederal Government recognize Federal employ-ees and/or facilities for energy efficiency achieve-

ments. The first is the Federal Energy EfficiencyAwards at FEMP, and the other is the awardsprogram at the U.S. Department of Army.

Each year the FEMP awards 15 certificates ofachievement to individuals and facilities forexemplary performance in promoting conserva-tion in Federal facilities.131 The award does notinclude any financial compensation, but it doesprovide recognition and favorable publicity forthe winning individuals and organizations.

The U.S. Army in Europe (USAREUR) has anaward component in its energy program. Theawards recognize both small and large facilitiesfor saving energy in a variety of ways. The

strenuous review of the nominees includes scor-ing on elements like efficiency measures, short-term measures, long term plans, numeric perform-ance, mobility fuel savings, special considera-tions, and a day-long inspection of finalists. Thevalue of the program is multifold. In addition to

showing the interest and commitment of USA-REUR, it creates publicity for energy programs,recognizes deserving communities, and reducesenergy use. Prior to FY 1991, the award includeda monetary component: $500,000 for first place,and a total $1.2 million in cash awards to be usedon a ‘‘welfare, morale, and recreation’ item forthe 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.7G51b-

121742 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~entof 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

Documents

Energy Efficiency: Challenges and Opportunities for Electric ...2 I Energy Efficiency: Challenges and Opportunities for Electric Utilities Box l-A-Key Terms I Energy efficiency refers