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34083Federal Register / Vol. 71, No. 113/ Tuesday, June 13, 2006 / Notices

906TH—MEETING—Continued

Item No. Docket No. Company

Gas

G–1 ........ PL04–3–000 .................................................................... Natural Gas Interchangeability.G–2 ........ RM06–17–000 ................................................................. Natural Gas Supply Association.G–3 ........ RP05–618–002 ................................................................ Colorado Interstate Gas Company.G–4 ........ OMITTED.

G–5 ........ TS04–280–002 ................................................................ Jupiter Energy Corporation.TS05–10–000 .................................................................. Cotton Valley Compression, L.L.C.TS05–3–000 .................................................................... Texas Eastern Transmission, LP.TS05–19–000 .................................................................. Chandeleur Pipe Line Company.TS05–21–000 .................................................................. Sabine Pipe Line Company.TS05–17–000, OA05–1–000 ........................................... Thumb Electric Cooperative.TS05–15–000 .................................................................. Discovery Gas Transmission Inc.

Hydro

H–1 ........ P–12641–000 .................................................................. Mt. Hope Waterpower Project LLP.H–2 ........ P–4244–021 .................................................................... Northumberland Hydro Partners, L.P.

P–10648–009 .................................................................. Adirondack Hydro Development Corporation.H–3 ........ P–12451–003 .................................................................. SAF Hydroelectric, LLC.H–4 ........ P–12462–003 .................................................................. Indian River Power Supply, LLC.

P–12430–002 .................................................................. Alternative Light and Hydro Associates.H–5 ........ P–2118–011 .................................................................... Pacific Gas and Electric Company.

H–6 ........ P–1962–136 .................................................................... Pacific Gas and Electric Company.

Certificates

C–1 ........ RM06–12–000 ................................................................. Regulations for Filing Applications for Permits to Site Transmission Facili-ties.

C–2 ........ RM05–23–000, AD04–11–000 ........................................ Rate Regulation of Certain Natural Gas Storage Facilities.C–3 ........ RM06–7–000 ................................................................... Revisions to the Blanket Certificate Regulations and Clarification Regard-

ing Rates.C–4 ........ CP05–130–000, CP05–130–001, CP05–130–002 ......... Dominion Cove Point LNG, LP.

CP05–132–000, CP05–132–001 ..................................... Dominion Cove Point LNG, LP.CP05–131–000, CP05–131–001 ..................................... Dominion Transmission, Inc.

C–5 ........ CP05–360–000 ................................................................ Creole Trail LNG, L.P.CP05–357–000, CP05–357–001, CP05–357–002,

CP05–358–000, CP05–359–000.Cheniere Creole Trail Pipeline, L.P.

C–6 ........ CP05–396–000 ................................................................ Sabine Pass LNG, L.P.C–7 ........ CP04–411–000 ................................................................ Crown Landing LLC.

CP04–416–000 ................................................................ Texas Eastern Transmission, LP.C–8 ........ CP05–83–000 .................................................................. Port Arthur LNG, L.P.

CP05–84–000, CP05–84–001, CP05–85–000, CP05– 86–000.

Port Arthur Pipeline, L.P.

C–9 ........ CP05–395–000 ................................................................ Dominion Cove Point LNG, LP.C–10 ...... CP06–26–000 .................................................................. Dominion Cove Point LNG, LP.C–11 .... .. OMITTED.

Magalie R. Salas,

Secretary.

A free webcast of this event isavailable through www.ferc.gov. Anyonewith Internet access who desires to viewthis event can do so by navigating to

www.ferc.gov’s Calendar of Events andlocating this event in the Calendar. Theevent will contain a link to its webcast.The Capitol Connection providestechnical support for the free webcasts.It also offers access to this event viatelevision in the DC area and via phone

bridge for a fee. If you have anyquestions, visitwww.CapitolConnection.org or contactDanelle Perkowski or David Reininger at703–993–3100.

Immediately following the conclusionof the Commission Meeting, a press

briefing will be held in Hearing Room2. Members of the public may view this

briefing in the Commission Meetingoverflow room. This statement isintended to notify the public that thepress briefings that follow Commission

meetings may now be viewed remotelyat Commission headquarters, but willnot be telecast through the CapitolConnection service.[FR Doc. 06–5415 Filed 6–9–06; 3:54 pm]

BILLING CODE 6717–01–U

DEPARTMENT OF ENERGY

Federal Energy RegulatoryCommission

[Docket No. AD05–17–000]

Electric Energy Market CompetitionTask Force; Notice RequestingComments on Draft Report toCongress on Competition in theWholesale and Retail Markets forElectric Energy

AGENCY: Federal Energy RegulatoryCommission, DOE.

ACTION: Notice.

SUMMARY: Section 1815 of the EnergyPolicy Act of 2005 requires the ElectricEnergy Market Competition Task Force

VerDate Aug<31>2005 16:40 Jun 12, 2006 Jkt 208001 PO 00000 Frm 00032 Fmt 4703 Sfmt 4703 E:\FR\FM\13JNN1.SGM 13JNN1



34084 Federal Register / Vol. 71, No. 113/ Tuesday, June 13, 2006 / Notices

to conduct a study and analysis of competition within the wholesale andretail market for electric energy in theUnited States and to submit a report toCongress within one year. Section 1815further requires that the Task Forcepublish its draft report in the FederalRegister for public comment 60 daysprior to submitting its final report to the

Congress. The Federal EnergyRegulatory Commission, as an agencywith a representative on the Task Force,is publishing this notice providing thedraft report and seeking publiccomment on behalf of the Task Force.

DATES: Comments are due on or before5 p.m. Eastern Time June 26, 2006.

ADDRESSES: Comments may beelectronically filed by any interestedperson via the e-Filing link on theFederal Energy RegulatoryCommission’s Web site at http:// www.ferc.gov for Docket No. AD05–17– 000. Persons filing electronically do notneed to make a paper filing. Persons thatare not able to file electronically mustsend an original of their comments to:Federal Energy Regulatory Commission,Office of the Secretary, 888 First StreetNE., Washington, DC 20426.

FOR FURTHER INFORMATION CONTACT:Moon Paul, Office of the GeneralCounsel, Federal Energy RegulatoryCommission, 888 First Street, NE.,Washington, DC 20426. 202–502–6136.

SUPPLEMENTARY INFORMATION: Section1815 of the Energy Policy Act of 2005established an interagency task force to

conduct a study and analysis of competition within the wholesalemarkets and retail markets for electricenergy in the United States. The taskforce has 5 members: (1) An employeeof the Department of Justice, appointed

by the Attorney General of the UnitedStates; (2) an employee of the FederalEnergy Regulatory Commission,appointed by the Chairperson of thatCommission; (3) an employee of theFederal Trade Commission, appointed

by the Chairperson of that Commission;(4) an employee of the Department of Energy, appointed by the Secretary of Energy; and (5) an employee of theRural Utilities Service, appointed by theSecretary of Agriculture.

The Electric Energy MarketCompetition Task Force consulted withand solicited comments from the States,representatives of the electric powerindustry and the public, in accordancewith a notice requesting publiccomment published in the FederalRegister on October 19, 2005 at 70 FR60819. A full listing of the persons orentities that have met with the task forceor submitted comments in response to

the notice will be listed as anattachment to the final report.

The draft report of the Electric EnergyMarket Competition Task Force isattached to this notice as Appendix A.The appendices to the draft report willnot be published in the FederalRegister, but will be available online, asfollows. The draft report is also

available at each of the following Websites of the Task Force members’ agencies:

Department of Justice: http:// www.usdoj.gov/atr

Federal Energy Regulatory Commission:http://www.ferc.gov/legal/staff-reports/epact-competition.pdf

Federal Trade Commission: http:// www.ftc.gov

Department of Energy: http:// www.oe.energy.gov

Department of Agriculture: http:// www.usda.gov/rus/electric/ competition/index.htm

Members of the public are invited tocomment on the draft report andencouraged to file comments as soon asis practicable in order to maximize thetime available to the task force toconsider these comments. Commentswill be received by the Federal EnergyRegulatory Commission and availablefor public review. A final report will bedelivered to Congress on or beforeAugust 8, 2006 in accordance with thestatutory deadline.

How To File Comments

Any interested person may submit a

written comment and it will be madepart of the public record of the TaskForce maintained with the FederalEnergy Regulatory Commission.Comments may be filed electronicallyvia the e-Filing link on the FederalEnergy Regulatory Commission’s Website at http://www.ferc.gov for DocketNo. AD05–17–000.

Most standard word processingformats are accepted, and the e-Filinglink provides instructions for how toLogin and complete an electronic filing.First-time users will have to establish auser name and password. User

assistance for electronic filing isavailable at 202–208–0258 or by e-mailto efiling at ferc.gov. Comments shouldnot be submitted to the e-mail address.Persons filing comments electronicallydo not need to make a paper filing.Persons that are not able to filecomments electronically must send anoriginal of their comments to: FederalEnergy Regulatory Commission, Officeof the Secretary, 888 First Street NE.,Washington, DC 20426.

This filing is accessible on-line athttp://www.ferc.gov , using the

‘‘eLibrary’’ link and is available forreview in the Commission’s PublicReference Room in Washington, DC. Forassistance with any FERC Onlineservice, please [email protected] , or call(866) 208–3676 (toll free). For TTY, call(202) 502–8659.

Dated: June 5, 2006.

Magalie R. Salas,

Secretary, Federal Energy Regulatory Commission.

Appendix A—Draft Report of theElectric Energy Market CompetitionTask Force

Report to Congress on Competition inthe Wholesale and Retail Markets forELectric Energy

Draft

June 5, 2006.

By The Electric Energy MarketCompetition Task Force.

Table of Contents

Executive SummaryChapter 1. Industry Structure, Legal and

Regulatory Background, Industry Trendsand Developments

Chapter 2. Context For The Task Force’sStudy of Competition in Wholesale andRetail Electric Power Markets

Chapter 3. Competition in Wholesale ElectricPower Markets

Chapter 4. Competition in Retail ElectricPower Markets

Appendix A: Index of Comments ReceivedAppendix B: Task Force Meetings With

Outside PartiesAppendix C: Annotated Bibliography of Cost

Benefit StudiesAppendix D: State Retail Competition

ProfilesAppendix E: Analysis of Contract Length and

Price TermsAppendix F: Bibliography of Primary

Information on Electric CompetitionAppendix G: Credit Ratings of Major

American Electric Generation CompaniesTable 1–1. U.S. Retail Electric Providers 2004Table 1–2. U.S. Retail Electric Sales 2004Table 1–3. U.S. Retail Electric Providers

2004, Revenues from Sales to UltimateConsumers

Table 1–4. U.S. Electricity Generation 2004Table 1–5. U.S. U.S. Electric Generation

Capacity 2004

Table 1–6. Power Generation AssetDivestitures by Investor-Owned ElectricUtil. as of April 2000

Table 4–1 Distribution Utility Ownership of Generation Assets in the State in WhichIt Operates

Figure 1–1. U.S. Electric Power Industry,Average Retail Price by State 2004

Figure 1–2. Status of State Electric IndustryRestructuring Activity, 2003

Figure 1–3. RTO Configurations in 2004Figure 1–4. Transmission Expenditures of

EEI MembersFigure 1–5. U.S. Electric Generating Capacity

Additions: Non-Utility Growth Overtakes





1The Task Force consists of 5 members: (1) Oneemployee of the Department of Justice, appointed by the Attorney General of the United States; (2)one employee of the Federal Energy RegulatoryCommission, appointed by the Chairperson of thatCommission; (3) one employee of the Federal TradeCommission, appointed by the Chairperson of thatCommission; (4) one employee of the Departmentof Energy, appointed by the Secretary of Energy; (5)one employee of the Rural Utilities Service (RUS),appointed by the Secretary of Agriculture.

Utility 2000–2004Figure 1–6. National Average Retail Prices of

Electricity for Residential CustomersFigure 1–7. Gas Has Recently Been Dominant

FuelFigure 1–8. Net Generation Shares by Energy

SourceFigure 1–9. Electric Power Industry Fuel

Costs, Jan. 2005–December 2005Figure 3–1. U.S. Electric Generating Capacity

Additions (19602005)Figure 3–2. Estimate of Annul NY CapacityValues—All Auctions

Figure 4–1. U.S. Electric Power Industry,Average Retail Price of Electricity byState, 1995

Figure 4–2. U.S. Map Depicting States withRetail Competition, 2003

Figure 4–3. Average Revenues per kWh forRetail Customers 1990–2005 ProfiledStates vs. National Avg.

Appendix D Tables 1–34

Executive Summary

Congressional Request

Section 1815 of the Energy Policy Act

of 2005 (the Act) requires the ElectricEnergy Market Competition Task Force(Task Force) to conduct a study of competition in wholesale and retailmarkets for electric energy in the UnitedStates.1 Section 1815(b)(2)(B) of the Actrequires the Task Force to publish adraft final report for public comment 60days prior to submitting the finalversion to Congress. This FederalRegister notice fulfills this statutoryobligation. The Task Force seekscomment on the preliminaryobservations contained in this draftreport.

Task Force ActivitiesIn preparing this report, the Task

Force undertook several activities, asfollows:

• Section 1815(c) of the Energy PolicyAct of 2005 required the Task Force to‘‘consult with and solicit commentsfrom any advisory entity of the taskforce, the States, representatives of theelectric power industry, and thepublic.’’ Accordingly, the Task Forcepublished a Federal Register noticeseeking comment on a variety of issuesrelated to competition in wholesale andretail electric power markets to comply

with this statutory obligation. The TaskForce received over 80 comments thatexpressed a variety of opinions andanalyses. The list of parties who

submitted comments is attached asAppendix A.

• The Task Force met and discussedcompetition-related issues with avariety of representatives of the electricpower industry in October/November2005. These groups are listed inAppendix B.

• The Task Force prepared an

annotated bibliography of the publiccost/benefit studies that have attemptedto analyze the status of wholesale andretail competition. Appendix C containsthis bibliography.

• The Task Force researched andanalyzed the relevant features of sevenstates that have implemented retailcompetition. The states include: Illinois,Maryland, Massachusetts, New Jersey,New York, Pennsylvania, and Texas.These seven states represent the variousapproaches that states have used tointroduce retail competition whereretail competition programs are active.

Appendix D contains these individualstate profiles.• The Task Force reviewed the

information gleaned from comments,interviews, and further research. Theythen produced draft documentation of the resulting observations and findings.These drafts were circulated among taskforce members for comments andrevised. No outside contractors werehired to conduct this work.

Federal and several statepolicymakers generally introducedcompetition in the electric powerindustry to overcome the perceivedshortcomings of traditional cost-based

regulation. In competitive markets,prices are expected to guideconsumption and investment decisionsto bring about an efficient allocation of resources.

Observations on Competition inWholesale Electric Power Markets

For almost 30 years, Congress hastaken steps to encourage competition inwholesale electric power markets. ThePublic Utility Regulatory Policies Act of 1978, the Energy Policy Act of 1992, andthe Energy Policy Act of 2005 all soughtto promote competition by lowering

entry barriers, increasing transmissionaccess, or both. Federal electricitypolicies seek to strengthen competition

but continue to rely on a combination of competition and regulation.

In responding to its statutory charge,the Task Force has sought to answer thefollowing question:

Has competition in wholesale markets forelectricity resulted in sufficient generationsupply and transmission to providewholesale customers with the kind of choicethat is generally associated with competitivemarkets?

To answer this question, the TaskForce examined whether competitionhas elicited consumption andinvestment decisions that were expectedto occur with wholesale marketcompetition.

The Task Force found this questionchallenging to address. Regionalwholesale electric power markets have

developed differently since the beginning of widespread wholesalecompetition. Each region was at adifferent regulatory and structuralstarting point upon Congress’ enactmentof the Energy Policy Act of 1992. Someregions already had tight power pools,others were more disparate in theiroperation of generation andtransmission. Some regions had higherpopulation densities and thus moretightly configured transmissionnetworks than did others. Some regionshad access to fuel sources that wereunavailable or less available in other

regions (e.g., natural gas supply in theSoutheast, hydro-power in theNorthwest). Some regions operate undera transmission open-access regime thathas not changed since the early days of open access in 1996, while other regionshave independent provision of transmission services and organizedday-ahead exchange markets for electricpower and ancillary services. Thesedifferences make it difficult to single outthe determinants of consumption andinvestment decisions and thus make itdifficult to evaluate the degree to whichmore competitive markets haveinfluenced such decisions. Even the

organized exchange markets havedifferent features and characteristics.

Despite the difficulty of directlyanswering the question at hand, theTask Force’s examination of wholesalecompetition has yielded some usefulobservations, as presented below. TheTask Force seeks comment on theseobservations.

Observations on Competitive Market Structures

1. One approach to competition inwholesale markets is to base tradesexclusively on bilateral sales directly

negotiated between suppliers, ratherthan on a centralized trading and marketclearing mechanisms. This approachpredominates in the Northwest andSoutheast. This bilateral format allowsfor somewhat independent operation of transmission control areas and, in theview of some market participants, betteraccommodates traditional bilateralcontracts. However, the fact that pricesand terms can be unique to eachtransaction and are not always publiclyavailable can lead to less than efficient(not least cost) generation dispatch





scenarios. Also, it can be difficult toefficiently coordinate transmissionwhen using this trading mechanism.The lack of centralized informationabout trades leaves the transmissionowner with system security risks thatnecessitate constrained transmissioncapacity. In some of these markets,wholesale customers have difficulty

gaining unqualified access to thetransmission they would need to accesscompetitively priced generation—thuslimiting their ability to shop for leastcost supply options.

2. Another approach to wholesalecompetition relies on entities which areindependent of market participants tooperate centralized regionaltransmission facilities and tradingmarkets (Regional TransmissionOrganizations or Independent SystemOperators). Various forms of thisapproach have come to predominate inthe Northeast, Midwest, Texas, and

California. The market designs in theseregions provide participants withguaranteed physical access to thetransmission system (subject totransmission security constraints).These customers are responsible for thecost of that access (if they choose toparticipate), and thus are exposed tocongestion price risks. This more openaccess to transmission can increasecompetitive options for wholesalecustomers and suppliers as compared tomost bilateral markets. Thetransparency of prices in these marketscan increase the efficiency of the tradingprocess for sellers and buyers and can

give clear price signals indicating the best place and time to build newgeneration. However, concerns have

been raised about the inability to obtainlong-term transmission access atpredictable prices in these markets andthe impact that this lack of long-termtransmission can have on incentives toconstruct new generation. Somecustomers have raised concerns abouthigh commodity price levels in thesemarkets.

Observations on Generation Supply inMarkets for Electricity

Several options may be used to elicitadequate supply in wholesale markets:1. One possible, but controversial,

way to spur entry is to allow wholesaleprice spikes to occur when supply isshort. The profits realized during theseprice spikes can provide incentives forgenerators to invest in new capacity.However, if wholesale customers havenot hedged (or cannot hedge) againstprice spikes, then these spikes can leadto adverse customer reactions.Unfortunately, it can be difficult todistinguish high prices due to the

exercise of market power from those dueto genuine scarcity. Customers exposedto a price spike often assume that thespike is evidence of market abuse. Pastprice spikes have caused regulators andvarious wholesale market operators toadopt price caps in certain markets.Although price caps may limit pricespikes and some forms of market

manipulation, they can also limitlegitimate scarcity pricing and impedeincentives to build generation in theface of scarcity. Not all the caps in placemay be necessary or set at appropriatelevels.

2. ‘‘Capacity payments’’ also can helpelicit new supply. Wholesale customersmake these payments to suppliers toassure the availability of generationwhen needed. However, where there arecapacity payments in organizedwholesale markets, it is difficult forregulators to determine the appropriatelevel of capacity payments to spur entry

without over-taxing market participantsand customers. Also, capacity paymentsmay elicit new generation whentransmission or other responses to pricechanges might be more affordable andequally effective. Depending on theirformat, capacity payments also maydiscourage entry by payinguneconomical generation to continuerunning when market conditionsotherwise would have led to the closureof that generation.

3. Building appropriate transmissionfacilities may encourage entry of newgeneration or more efficient use of existing generation. But, transmission

owners may resist building transmissionfacilities if they also own generation andif the proposed upgrades would increasecompetition in their sheltered markets.Another challenge with transmissionconstruction is that it is often difficultto assess the beneficiaries of transmission upgrades and, thus, it isdifficult to identify who should pay forthe upgrades. This challenge may causeuncertainty both for new generators andfor transmission owners. There can also

be difficulties associated with uncertainrevenue recovery due to unpredictableregulatory allowances for rate recovery.

4. Another option for ensuringadequate generation supply is throughtraditional regulatory mechanisms— regulatory control over electricitygenerators/suppliers. In this situation,Monopoly utility providers operateunder an obligation to plan and secureadequate generation to meet the needsof their customers. Regulators allow theutilities to earn a fair rate of return ontheir investment, thereby encouragingutility investment. However, thisapproach is not without risk to theutility as regulators have authority to

disallow excessive costs. Furthermore,these traditional methods are imperfectand can in some cases lead tooverinvestment, underinvestment,excessive spending and unnecessarilyhigh costs. These methods can distort

both investment and consumptiondecisions. Furthermore, undertraditional regulation, ratepayers (rather

than investors) may bear the risk of potential investment mistakes.

Observations on Competition in Retail Electric Power Markets

The Task Force examined theimplementation of retail competition inseven states in detail: Illinois, Maryland,Massachusetts, New Jersey, New York,Pennsylvania, and Texas. Theimplementation of retail competitionraises the question whether retail pricesare higher or lower than they otherwisewould be absent the introduction of thiscompetition.

In most profiled states, retailcompetition began in the late 1990s.States implemented retail rate caps anddistribution utility obligations to serve,which are now just ending, that make itdifficult to judge the success or failureof retail competition. Few alternativesuppliers currently serve residentialcustomers, although industrialcustomers have additional choices. Tothe extent that multiple suppliers serveretail customers, prices have notdecreased as expected, and the range of new options and services is limited.Since retail competition began, mostdistribution utilities in the profiled

states have either sold most of theirgeneration assets or transferred them tounregulated affiliates.

One of the main impediments to retailcompetition has been the lack of entry

by alternative suppliers and marketersto serve retail customers. Most statesrequired the distribution utility to offercustomers electricity at a regulated priceas a backstop or default if the customerdid not choose an alternative electricitysupplier or the chosen supplier wentout of business—this is called ‘‘providerof last resort (POLR) service.’’ Many of these states capped the POLR service

price for‘‘transitional

’’multi-yearperiods that are now just ending. These

caps have had the unintended effect of discouraging entry by competitivesuppliers. Thus, it has been difficult forthe Task Force to determine whetherretail prices in the profiled states arehigher or lower than they otherwisewould be absent the introduction of retail competition. At the same time,there is some evidence that alternativesuppliers have offered new retailproducts including ‘‘green’’ productsthat are more environmentally friendly





2Theoretically, competitive prices provideefficient incentives for all resource allocation(supply and consumption) decisions, and thusencourage efficient allocation of resources,including use of existing capacity, new investment by incumbent suppliers, entry by new suppliers,consumption, new investments by consumers.

for residential and non-residentialcustomers and customized energymanagement products for largecommercial and industrial customers.

When the rate caps expire, states mustdecide whether to continue POLR for allcustomer classes and how to price POLRservice for each class. Several stateshave rate caps that will expire in 2006

and 2007. The Task Force seekscomment on the observations about howPOLR prices affect competition in retailelectric power markets.

1. If regulators intend for the POLRservice to be a proxy for efficient pricesignals, it must closely approximate acompetitive price. The competitiveprice is based on supply and demand atany given time. If the POLR serviceprice does not closely match thecompetitive price, it is likely to distortconsumption and investmentdecisions.2

2. If POLR prices remain fixed whileprices for fuel and wholesale power arerising, customers may experience rateshock when the transition period ends.This rate shock can create publicpressure to continue the fixed POLRrates at below-market levels. Oneregulatory response may be to phase inthe price increase gradually, bydeferring recovery of part of thesupplier’s costs. Although this approachreduces rate shock for customers, it islikely to distort retail electricity markets

both in the short-term (when costs aredeferred) and in the long-term (whenthe deferred costs are recovered).

3. Some states have different POLR

service designs for different customerclasses. POLR prices for largecommercial and industrial customershave reflected wholesale spot marketprices more than have POLR prices forresidential customers. This approachgenerally has led the large customers toswitch suppliers more than the smallcustomers have. Also, more suppliershave made efforts to solicit these largecustomers. Retail pricing that closelytracks wholesale prices providesefficient price signals to consumers. Itcreates incentives for customers to cutconsumption during peak demand

periods which, in turn, can reduce therisk that suppliers will exercise marketpower and can improve systemreliability.

4. Some states have used auctions toprocure POLR supply. Auctions mayallow retail customers to get the benefit

of competition in wholesale markets assuppliers compete to supply thenecessary load.

5. One reason why retail competitionfor small customers may be slow todevelop is that it is difficult for theconsumer to find competitive supplieroffers in the first place and tounderstand the terms and conditions of

those offers. It also is unclear whetherthe effort to find this information isjustified by the potential cost savingsthat can be realized. As and when thereare more alternative suppliers, it mayresult in greater potential savings. Butthe need for clear and readily availableinformation relating to competitiveoffers will remain.

Chapter 1—Industry Structure, Legaland Regulatory Background, IndustryTrends and Developments

For the majority of the twentiethcentury, the electric power industry wasdominated by regulated monopolyutilities. Beginning in the late 1960s,however, a number of factorscontributed to a change in structure of the industry. In the 1970s, vertically-integrated utility companies (investor-owned, municipal, or cooperative)controlled over 95 percent of the electricgeneration. Typically, a single localutility sold and delivered electricity toretail customers under an exclusivefranchise. Now, the electric powerindustry includes both utility andnonutility entities, including many newcompanies that produce and marketelectric energy in the wholesale and

retail markets. This section will brieflydescribe the structural changes in thewholesale and retail electric powerindustry from the late 1960s until today.It provides a historical overview of theimportant legislative and regulatorychanges that have occurred in the pastseveral decades, as well as the trendsseen over this time period that have ledto increased competition in the electricpower industry.

A. Industry Structure and Regulation

Participants in the electric powersector in the United States include

investor-owned, cooperative utilities;Federal, State, and municipal utilities,public utility districts, and irrigationdistricts; cogenerators; nonutilityindependent power producers, affiliatedpower producers, and power marketersthat generate, distribute, transmit, or sellelectricity at wholesale or retail.

In 2004, there were 3276 regulatedretail electric providers supplyingelectricity to over 136 millioncustomers. Retail electricity salestotaled almost $270 billion in 2004.Retail customers purchased more than

3.5 billion megawatt hours of electricity.Active retail electric providers includeelectric utilities, Federal agencies, andpower marketers selling directly to retailcustomers. These entities differ greatlyin size, ownership, regulation, customerload characteristics, and regionalconditions. These differences arereflected in policy and regulation.

Tables 1–1 to 1–5 provide selectedstatistics for the electric power sector bytype of ownership in 2004 based oninformation reported to the UnitedStates Department of Energy (DOE),Energy Information Administration(EIA).

1. Investor-Owned Utilities

Investor-owned utility operatingcompanies (IOU) are private,shareholder-owned companies rangingin size from small local operationsserving a customer base of a fewthousand to giant multi-state holdingcompanies serving millions of customers. Most IOUs are or are part of a vertically-integrated system that ownsor controls generation, transmission,and distribution facilities/resourcesrequired to meet the needs of the retailcustomers in their assigned serviceareas. Over the past decade, under Stateretail competition plans many IOUshave undergone significant restructuringand reorganization. As a result, manyIOUs in these states no longer owngeneration, but must procure theelectricity they need for their retailcustomers from the wholesale markets.

IOUs continue to be a major presence

in the electric power industry. In 2004there were 220 IOUs servingapproximately 94 million retaildistribution customers, accounting for68.9 percent of all retail customers and60.8 percent of retail electricity sales.IOUs directly own about 39.6 percent of total electric generating capacity andgenerated 44.8 percent of totalgeneration in 2004 to meet their retailand wholesale sales.

IOUs provide service to retailcustomers under state regulation of territories, finances, operations,services, and rates. States generally

regulate bundled retail electric rates of IOUs under traditional cost of servicerate methods. In states that haverestructured their IOUs and IOUregulation, distribution servicescontinue to be provided undermonopoly cost-of-service rates, butretail customers are free to shop for theirelectricity supplier. IOUs operate retailelectric systems in every state butNebraska.

Under the Federal Power Act, theFederal Energy Regulatory Commission(FERC) regulates the wholesale





3American Public Power Association. 4National Rural Electric Cooperative Association.

electricity transactions (sales for resale)and unbundled transmission activitiesof IOUs (except in Alaska, Hawaii, andthe ERCOT region of Texas).

2. Public Power Systems

The more than 2,000 public powersystems include local, municipal, State,

and regional public power systems,ranging in size from tiny municipaldistribution companies to large systemslike the Power Authority of the State of New York. Publicly owned systemsoperate in every State but Hawaii. About1,840 of these public power systems arecities and municipal governments thatown and control the day to dayoperation of their electric utilities.3 Public power systems served over 19.6million retail customers in 2004, orabout 14.4 percent of all customers.Together, public power systemsgenerated 10.3 percent of the Nation’s

power in 2004, but accounted for 16.7percent of total electricity sales,reflecting the fact that many publicsystems are distribution-only utilitiesand must purchase their power suppliesfrom others. Public power systems ownabout 9.6 percent of total generatingcapacity. Public power systems areoverwhelmingly transmission- andwholesale-market-dependent entities.According to the American PublicPower Association, about 70 percent of public power retail sales were met fromwholesale power purchases, includingpurchases from municipal joint action

agencies by the agencies’membersystems. Only about 30 percent of the

electricity for public power retail salescame from power generated by a utilityto serve its own native load.

Regulation of public power systemsvaries among States. In some States, thepublic utility commission exercisesjurisdiction in whole or part overoperations and rates of publicly ownedsystems. In most States, public powersystems are regulated by localgovernments or are self-regulated.Municipal systems are usually governed

by the local city council or an

independent board elected by voters orappointed by city officials. Other publicpower systems are operated by publicutility districts, irrigation districts, orspecial State authorities.

On the whole, state retailderegulation/restructuring initiativesleft untouched retail services in publicpower systems. However, some statesallow public systems to adopt retailchoice alternatives voluntarily.

3. Electric Cooperatives

Electric cooperatives are privately-owned non-profit electric systemsowned and controlled by the membersthey serve. Members vote directly forthe board of directors. In 2004, about884 electric distribution cooperativesprovided retail electric service to almost

16.6 million customers. In addition tothese 884 distribution cooperatives,about 65 generation and transmissioncooperatives (G&Ts) own and operategeneration and transmission and securewholesale power and transmissionservices from others to meet the needsof their distribution cooperativemembers and other rural native loadcustomers. G&T systems and theirmembers engage in joint planning andpower supply operations to achievesome of the savings available under avertically integrated utility structure forthe benefit of their customers. Electriccooperatives operate in 47 States. Most

electric cooperatives were originallyorganized and financed under theFederal rural electrification programand generally operate in primarily ruralareas. Electric cooperatives provideelectric service in all or parts of 83percent of the counties in the UnitedStates.4

In 2004, electric cooperatives soldmore than 345 million megawatt hoursof electricity, served 12.2 percent of retail customers and accounted for 9.7percent of electricity sold at retail.Nationwide electric cooperativesgenerated about 4.7 percent of total

electric generation. Electric cooperativesown approximately 4.2 percent of generating capacity.

While some cooperative systemsgenerate their own power and makesales of power in excess of their ownmembers needs, most electriccooperatives are net buyers of power.Cooperatives nationwide generate onlyabout half of the power needed to meetthe needs of retail customers.Cooperatives secured approximatelyhalf of their power needs from otherwholesale suppliers in 2004. Althoughcooperatives own and operate

transmission facilities, almost allcooperatives are dependent ontransmission service by others to deliverpower to their wholesale and/or retailcustomers.

Regulatory jurisdiction overcooperatives varies among the States,with some States exercisingconsiderable authority over rates andoperations, while other States exemptcooperatives from State regulation. Inaddition to State regulation,

cooperatives with outstanding loansunder the Rural Electrification Act of 1936 also are subject to financial andoperating requirements of the U.S.Department of Agriculture, which mustapprove borrower long-term wholesalepower contracts, operating agreements,and transfer of assets.

Cooperatives that have repaid their

RUS loans and that engage in wholesalesales or provide transmission services toothers have been regulated by FERC aspublic utilities. EPACT 05 providedFERC additional discretionaryjurisdiction over the transmissionservices provided by larger electriccooperatives.

4. Federal Power Systems

Federally owned or chartered powersystems include the Federal powermarketing administrations, theTennessee Valley Authority (TVA), andfacilities operated by the U.S. ArmyCorps of Engineers, the Bureau of Reclamation, the Bureau of IndianAffairs, and the International Water andBoundary Commission. Wholesalepower from federal facilities (primarilyhydroelectric dams) is marketed throughfour Federal power marketing agencies:Bonneville Power Administration,Western Area Power Administration,Southeastern Power Administration,and Southwestern PowerAdministration. The PMAs own andcontrol transmission to deliver power towholesale and direct service customers.PMAs may also purchase power fromothers to meet contractual needs and

sell surplus power as available towholesale markets. Existing legislationrequires that the PMAs and TVA givepreference in the sale of their generationoutput to public power systems and torural electric cooperatives.

Together, Federal systems have aninstalled generating capacity of approximately 71.4 gigawatts (GW) orabout 6.9 percent of total capacity.Federal systems provided 7.2 percent of the Nation’s power generation in 2004.Although most Federal power sales areat the wholesale level, they do engage insome end-use sales of generation.

Federal systems nationwide directlyserved 39,845 retail customers in 2004,mostly industrial customers and about1.2 percent of retail load.

5. Nonutilities

Nonutilities are entities that generateor sell electric power, but that do notoperate retail distribution franchises.They include wholesale non-utilityaffiliates of regulated utilities, merchantgenerators, and PURPA qualifyingfacilities (industrial and commercialcombined heat and power producers).





5Edison Electic Institute.

Power marketers that buy and sellpower at wholesale or retail, but that donot own generation, transmission, ordistribution facilities are also includedin this category.

Non-QF (qualifying facilities)wholesale generators engaged inwholesale power sales in interstate

commerce are subject to FERCregulation under the FPA. Powermarketers that sell at wholesale are alsosubject to FERC oversight. Power

marketers that sell only at retail aresubject to State jurisdiction andoversight in the States in which theyoperate.

As retail electric providers, 152 powermarketers reporting to EIA served about6 million retail customers or about 4.4percent of all retail customers andreported revenues of over $28 billion,

on about 11.6 percent of retail electricitysold.

Nonutilities are a growing presence inthe industry. In 2004 nonutilities owned

or controlled approximately 408,699megawatts or 39.6 percent of all electricgeneration capacity. In 1993 they ownedonly about 8 percent of generation. It isestimated that about half of nonutilitygeneration capacity is owned by non-utility affiliates or subsidiaries of holding companies that also own aregulated electric utility.5 Nonutilitiesaccounted for about 33 percent of generation in 2004. Tables 1–1 through1–5 summarize this information.

TABLE 1–1.—U.S. RETAIL ELECTRIC PROVIDERS 2004

OwnershipNumber of

electricity pro-viders

Percent of totalNumber of customers

Percent of totalFull service Delivery only Total

Publicly-owned ut ilities .. .. ... .. ... ... .. ... .. ... 2,011 61.4 19,628,710 6,125 19,634,835 14.4Investor-owned utilities ........................ 220 6.7 90,970,557 2,879,114 93,849,671 68.9Cooperatives ........................................ 884 27 16,564,780 12,170 16,576,950 12.2Federal Power Agencies ...................... 9 0.3 39,843 2 39,845 0.03Power Marketers .................................. 152 4.6 6,017,611 0 6,017,611 4.4

Total .............................................. 3,276 100 133,221,501 2,897,411 136,118,912 100.0

Source: American Public Power Association, 2006–07 Annual Directory & Statistical Report, from Energy Information Administration Form EIA– 861, 2004 data.

Notes: Delivery-only customers represent the number of customers in a utility’s service territory that purchase energy from an alternative sup-plier.

Ninety-eight percent of all power marketers ’ full-service customers are in Texas. Investor-owned utilities in the ERCOT region of Texas nolonger report ultimate customers. Their customers are counted as full-service customers of retail electric providers (REPs), which are classifiedby the Energy Information Administration as power marketers. The REPs bill customers for full service and then pay the IOU for the delivery por-tion. REPs include the regulated distribution utility ’s successor affiliated retail electric provider that assumed service for all retail customers thatdid not select an alternative provider. Does not include U.S. territories.

TABLE 1–2.—U.S. RETAIL ELECTRIC SALES 2004[Sales to ultimate consumers in thousands of MWhs]

Full service Energy only Total Percent

Publicly-owned utilities ..................................................................................... 525,596 65,466 591,062 16.7

Investor-owned utilities .................................................................................... 2,148,351 3,359 2,151,720 60.8Cooperatives .................................................................................................... 344,267 890 345,157 9.7Federal Power Agencies ................................................................................. 41,169 352 41,521 1.2Power Marketers .............................................................................................. 207,696 203,202 410,898 11.6

Total .......................................................................................................... 3,267,089 273,269 3,540,358 100.0


Notes: Energy-only revenue represents revenue from a utility ’s sales of energy outside of its own service territory. Total revenue shows theamount of revenue each sector receives from both bundled (full service) and unbundled (retail choice) sales to ultimate customers. Eighty-fivepercent of the energy-only revenue attributed to publicly owned utilities represents revenue from energy procured for California ’s investor-ownedutilities by the California Department of Water Resources Electric Fund. Ninety-eight percent of power marketers ’ full-service sales and revenuesoccur in Texas. Investor-owned utilities in the ERCOT region of Texas no longer report sales or revenue to ultimate consumers on EIA 861.

TABLE 1–3.—U.S. RETAIL ELECTRIC PROVIDERS 2004, REVENUES FROM SALES TO ULTIMATE CONSUMERS

Sales in $ millionsTotal

Full service Energy only Delivery

Publicly-owned utilities ..................................................................................... $37,734 $5,787 $27 $43,548Investor-owned utilities .................................................................................... 162,691 128 8,746 171,565Cooperatives .................................................................................................... 25,448 37 7 25,492Federal Power Agencies ................................................................................. 1,211 13 1 1,224Power Marketers .............................................................................................. 17,163 11,000 0 28,162

Total .......................................................................................................... 244,247 16,965 8,761 269,992






6Vernon Smith, Regulatory Reform in the ElectricPower Industry (1995) (working paper, on file withthe Department of Economics, University of Arizona).

7See Richard F. Hirsch, Power Loss: The Originsof Deregulation and Restructuring in the AmericanElectric Utility System, MIT PRESS (1999);SHARON BEDER, POWER PLAY: THE FIGHT TOCONTROL THE WORLD’S ELECTRICITY, W.W.Norton (2003).

8Promoting Wholesale Competition ThroughOpen Access Non-Discriminatory TransmissionServices by Public Utilities; Recovery of Stranded Costs by Public Utilities and Transmitting Utilities,Order No. 888, 61 FR 21,540, FERC Stats. & Regs.¶31,036, 31,639 (1996), order on reh’ g , Order No.888–A, FERC Stats. & Regs. ¶31,048 (1997); order on reh’ g , Order No. 888–B, 81 FERC ¶61,248(1997), order on reh’ g , Order No. 888–C, 82 FERC¶61,046 (1998), aff ’ d in relevant part sub nom.Transmission Access Policy Study Group v. FERC ,225 F..3d 667 (D.C. Cir. 2000), aff ’ d sub nom. New York v. FERC , 535 U.S. 1 (2002)[hereinafter OrderNo. 888].

9See U.S. Dep’t of Energy, Energy Info. Admin.,The Changing Structure of the Electric Power Industry: 1970– 1991, at 57 (March 1993), availableat http://tonto.eia.doe.gov/FTPROOT/electricity/ 0562.pdf [hereinafter EIA 1970–1991].

TABLE 1–4.—U.S. ELECTRICITY GENERATION 2004

Electricity Generation 2004Generation

(thousands ofMWhs)

% of Total

Publicly-owned utilities ............................................................................................................................................. 397,110 10.3Investor-owned utilities ............................................................................................................................................ 1,734,733 44.8Cooperatives ............................................................................................................................................................ 181,899 4.7Federal Power Agencies ......................................................................................................................................... 278,130 7.2

Power Marketers ...................................................................................................................................................... 42,599 1.1Non-utilities .............................................................................................................................................................. 1,235,298 31.9

Total .................................................................................................................................................................. 3,869,769 100.0

Source: American Public Power Association, 2006–07 Annual Directory & Statistical Report, from Energy Information Administration Form EIA– 861 and EIA–906/920 for generation. Data are for 2004, adjusted for joint ownership.

TABLE 1–5.—U.S. ELECTRIC GENERATION CAPACITY 2004

OwnershipNameplate ca-

pacity(in MWs)

% of Total

Publicly-owned utilities ............................................................................................................................................. 98,686 9.6Investor-owned utilities ............................................................................................................................................ 408,699 39.6Cooperatives ............................................................................................................................................................ 43,225 4.2

Federal Power Agencies ......................................................................................................................................... 71,394 6.9Non-utilities .............................................................................................................................................................. 409,689 39.7

Total .................................................................................................................................................................. 1,031,692 100.0

Source: American Public Power Association, 2006–07 Annual Directory & Statistical Report, from Energy Information Administration Form EIA– 860 for capacity, including adjustments for joint ownership. Data are for 2004.

B. Growth of the Electric Power Industry

1. Electric Power Characterized as aNatural Monopoly

The early electric power industry has been characterized as a naturalmonopoly.6 This idea was, in partengendered by the work of Thomas

Edison’s prote ge , Samuel Insull whoacquired monopoly ownership over allcentral station electricity production inChicago. Insull went on to publiclycharacterize electricity production as a‘‘natural monopoly’’ and promote theidea of the public granting monopolyfranchises to integrated generation/transmission utilities whose profitswould be monitored and regulated.7

Over the years, experts have debatedwhether or not Samuel Insull was right.But he made a compelling argument,and the industry structure developed asif electricity was a natural monopoly.States granted monopoly franchises tovertically-integrated utilities. Thesefranchises controlled the generation,transmission, and distribution of electricity. Public utility commissions

were established to regulate the retailprices the electric utilities could charge.

Electric rates were set to cover thecompanies’ reasonable costs plus a fairreturn on their shareholders’ investment. Retail customers werecharged a price based on the averagesystem cost of production (including the

investors’ fair return on investment). Insome circumstances, the public chose toestablish publicly owned municipalutilities and cooperatives.

Most utilities began by building theirown generation plants and transmissionsystems, primarily due to the cost andtechnological limitations on thedistance over which electricity could betransmitted.8 In the beginning, thefederal role in the electric powerindustry was limited. Under the FederalPower Act of 1935 (FPA), the FederalGovernment regulated the price of IOUs’ interstate sales of wholesale power (e.g.,sales of power between utility systems)and the price and terms of use of the

interstate transmission system, whichwas used in these interstate sales of wholesale power. When this act waspassed, interstate sales of electricitywere limited. Over time utilities becamemore interconnected via high-voltagetransmission networks that wereconstructed primarily for purposes of

reliability but facilitated more robustinterstate trade. However, this trade wasslow to develop. Entry into thesemarkets by nonutility generators waslimited.

Until the late 1960s, this systemappeared to work reasonably well.Utilities were able to meet increasingdemand for electricity at decreasingprices, due to advances in generationtechnology that increased economies of scale and decreased costs.9

2. The Energy Crisis, Shift from Utility-Dominated Generation: Effects of PURPA on the Expansion of Nonutility

Generation and Wholesale PowerMarkets

Several changes during the 1970screated a shift to a more competitivemarketplace for wholesale power.Mainly, the large vertically integratedutility model became less profitable.Additional economies of scale were no





10See Order No. 888, FERC Stats. & Regs.¶31,036 at 31,640–41.

11 Id. at 31,639.12Consumers reacted to electricity price

increases, and growth in demand fell sharply belowprojections. See U.S. Congress, Office of Technology Assessment, Electric Power Wheeling and Dealing: Technological Considerations for Increasing Competition 39, OTA–E–409(Washington, DC: U.S. Government Printing Office,May 1989) [hereinafter U.S. Congress, Office of Technology Assessment].

13Order No. 888, FERC Stats. & Regs. ¶31,036 at31,641.

14 Id .15Severin Borenstein & James Bushnell,

Electricity Restructuring: Deregulation or Reregulation? , 23 REGULATION 46, 47 (2000).

16Paul L. Joskow, The Difficult Transition toCompetitive Electricity Markets in the U.S. 6–7(AEI-Brookings Joint Ctr. for Regulatory Studies,Working Paper No. 03–13, 2003), available at http:// www.aei-brookings.org/admin/authorpdfs/ page.php?id=271 [hereinafter Joskow, DifficultTransition].

17The response to the blackout included theformation of regional reliability councils and theNorth American Electric Reliability Council (NERC)to promote the reliability and adequacy of bulkpower supply. U.S. Dept. of Energy, Energy Info.Admin., The Changing Structure of the ElectricPower Industry 2000: An Update, at 109 (October

2000), available at http://www.eia.doe.gov/cneaf/ electricity/chg _stru _update/update2000.pdf [hereinafter EIA 2000 Update].

18Order No. 888, FERC Stats. & Regs. ¶31,036 at31,639, n.9.

19Pub. L. No. 95–617, 92 Stat. 3117 (codified inU.S.C. sections 15, 16, 26, 30, 42, and 43).

20See EIA 1979–1991 at 22.21PURPA specifically set forth criteria on who

and what could qualify as QFs (mainlytechnological and size criteria). Two types of QFswere recognized: cogenerators, which sequentiallyproduce electric energy and another form of energy(such as heat or steam) using the same fuel source,and small power producers, which use waste,renewable energy, or geothermal energy as aprimary energy source. These nonutility generatorsare ‘‘qualified’’ under PURPA, in that they meetcertain ownership, operating, and efficiencycriteria. See EIA 1970–1991 at 5.

22 Id . at 24.23Order No. 888, FERC Stats. & Regs. ¶31,036 at

31,642.24 Joskow, Deregulation at 19.

25 Id . at 17.26CONG. RESEARCH SERV., COMM. ON

ENERGY AND COMMERCE, 102D CONG.,ELECTRICITY A NEW REGULATORY ORDER? 92(Comm. Print 1991).


28 Joskow, Deregulation at 19.

longer being achieved; large generatingunits needed greater maintenance andexperienced longer downtimes. Thus a

bigger generation facility was no longerconsidered the most cost-efficientformat.10 Periods of rapid inflation andhigher interest rates increased the costsof operating large, baseload generationplants,11 and a more elastic-than-

expected demand or load led todecreasing profits for large utilities.12 Significant improvements in technologyallowed smaller generation units to beconstructed at lower costs.13 As a result,lower cost generation sources couldreach systems where customers werecaptive to high cost generators.14 Inaddition, these technological advancesmade it more feasible for generationplants hundreds of miles apart tocompete with each other 15 and fornonutility generators to enter themarket; physically isolated systems

became a thing of the past. Criticism of

the cost-based regime also increasedduring this period with suggestions foralternate approaches to regulation andchanges in industry structure. Critics of cost-based regulation argued that theindustry structure provided limitedopportunities for more efficientsuppliers to expand and placedinsufficient pressure on less efficientsuppliers to improve theirperformance.16

Other events also influenced thesechanges. First, a major power blackoutin the Northeastern U.S. in 1965 raisedconcerns about the reliability of weaklycoordinated transmission arrangementsamong utilities.17 Second, from October

of 1973 to March of 1974, the Arab oil-producing nations imposed a ban on oilexports to the United States. The Araboil embargo resulted in significantlyhigher oil prices through the 1970s,adding to inflation.18

Congress enacted the Public UtilityRegulatory Policy Act of 1978(PURPA)19 as a response to the energy

crises of the 1970s. A major goal of PURPA was to promote energyconservation and alternative energytechnologies and to reduce oil and gasconsumption through use of technologyimprovements and regulatory reforms.PURPA further created an opportunityfor nonutilities to emerge as importantelectric power producers.20 PURPArequired electric utilities to interconnectwith and purchase power from certaincogeneration facilities and small powerproducers meeting the criteria for aqualifying facility (QF). PURPAprovided that the QF be paid at the

utility’s incremental cost of production,which FERC, in a departure from cost- based regulation, defined as the utility’savoided cost of power.21 Box 1–1discusses how the implementation of PURPA encouraged nonutilitiesgeneration suppliers by guaranteeing amarket for the electricity theyproduced.22 PURPA changed prevailingviews that vertically integrated publicutilities were the only sources of reliable power 23 and showed thatnonutilities could build and operategeneration facilities effectively andwithout disrupting the reliability of transmission systems.24

Box 1–1: State Implementation of PURPA

PURPA required states to define theutility’s own avoided cost of production.This cost was used to set the price forpurchasing a QF’s output. Several states,including California, New York,Massachusetts, Maine, and New Jersey,

enacted regulations that required utilities inthese states to sign long-term contracts withQFs at prices that ended up being muchhigher than the utilities’ actual marginalsavings of not producing the power itself (avoided costs). The result of theseregulations was that many utilities enteredinto long-term purchase contracts thatultimately proved uneconomic, and thusdistorted the development of competitive

wholesale markets. The costs of suchcontracts were subsequently reflected inretail rates as cost pass-throughs. Theexperience added to the dissatisfaction withretail utility service and regulation. See

Joskow, Deregulation at 18.

PURPA was largely responsible forcreating an independent competitivegeneration sector.25 The response toPURPA was dramatic.

Before passage of PURPA, nonutilitygeneration was primarily confined tocommercial and industrial facilitieswhere the owners generated heat andpower for their own use where it was

advantageous to do so. Althoughnonutility generation facilities werelocated across the country, developmentwas heavily concentrated geographicallywith about two thirds located inCalifornia and Texas. Nonutilitygeneration development advanced inStates where avoided costs were highenough to attract interest and wherenatural gas supplies were available.Federal law largely precluded electricutilities from constructing new naturalgas plants during the decade followingenactment of PURPA, but nonutilitygenerators faced no such restriction.

Annual QF filings at FERC rose from29 applications covering 704 megawattsin 1980 to 979 in 1986 totaling over18,000 megawatts. From 1980 to 1990FERC received a total of 4610 QFapplications for a total of 86,612megawatts of generating capacity.26

Following PURPA, there wereeconomic and technological changes inthe transmission and generation sectorsthat further contributed to an influx of new entrants in wholesale generationmarkets who could sell electric powerprofitably with smaller scale technologythan many utilities.27 In addition to

QFs, other non-utility power producersthat could not meet QF criteria also began to build new capacity to competein bulk power markets to meet the needsof load serving entities.28 These entitieswere known as merchant generators or





29Order No. No. 888, FERC Stats. & Regs.¶31,036 at 31,642.

30EIA 1970–1991 at vii.31 Id . at 27.32See Order No. No. 888, FERC Stats. & Regs.

¶31,036 at 31,643.33See Regulations Governing Bidding Programs,

Notice of Proposed Rulemaking, 53 FR 9,324(March 22, 1988), FERC Stats. & Regs. ¶32,455(1988) (modified by 53 FR 16,882 (May 12, 1988)).This proposal would have adopted competitive bidding into the process of acquiring and pricingpower from QFs and would have largely abandonedthe prior avoided cost purchase rates.

See Regulations Governing Independent Power

Producers, Notice of Proposed Rulemaking, 53 FR9,327 (March 22, 1988), FERC Stats. & Regs.¶32,456 (1988) (modified by 53 FR 16882 (May 12,1988)). This proposal would have relaxed ratereview and regulation of wholesale sales byindependent power producers, and other publicutilities that did not operate retail distributionsystems.

See Administrative Determination of Full Avoided Costs, Sales of Power to Qualifying Facilities, and Interconnection Facilities, Notice of Proposed Rulemaking, 53 FR 9,331 (March 221988), FERC Stats. & Regs. ¶32,457 (1988)(modified by 53 FR 16882 (May 12, 1988)). Thisproposal would have revised the elements used inmaking administrative determinations of avoidedcosts for rates for utilities’ PURPA QF purchases.

34Hearing on National Energy Security Act of 1991 (Title XV) Before the S. Comm. on Energy and Natural Resources, 102d Cong. 97 (1991) (Statementof Cynthia A. Marlette, Associate General Counselfor Hydroelectric and Electric, Federal EnergyRegulatory Commission).

35 Id . at 100.36 Id .37 Id . at 102.38Order No. 888, FERC Stats. & Regs. ¶31,036 at

31,642–43.

39 Joskow, Deregulation at 21. See Order No. 888,

FERC Stats. & Regs. ¶31,036 at 31,644.40 Joskow, Deregulation at 23. Under PUHCA,

those public utility holding companies that did notqualify for an exemption were subject to extensiveregulation of their financial activities andoperations. These regulations limited theavailability of exemptions and the growth andexpansion of electric utility companies. PUHCArestricted utility operations to a single integratedpublic-utility system and prevented utility holdingcompanies from owning other businesses that werenot reasonably incidental or functionally related tothe utility business. Further, registered holdingcompanies had to obtain Securities and ExchangeCommission (SEC) approval for the sale andissuance of securities, for transactions among theiraffiliates and subsidiaries and for services, sales,and construction contracts, and they were requiredto file extensive financial reports with the SEC.

Although PUHCA provided for limitedexemptions, it was long criticized as discouragingnew investment in the electric utility industry bynon-utility entities. Mergers and acquisitions of utilities subject to PUHCA have largely been byother domestic and foreign utilities. Investment byentities outside the industry has been limited, asthese entities avoid the extensive regulationsimposed by PUHCA.

41Pub. L. No. 102–486, 106 Stat. 2776 (1992),codified at, among other places, 15 U.S.C. 79z–5aand 16 U.S.C. 796(22–25), 824j–l.


43 Joskow, Deregulation at 24.44See EIA 1970– 1991 at 30; Joskow, Deregulation

at 23.

Independent Power Producers (IPPs).29 By 1991, nonutilities (QFs and IPPs)owned about six percent of the electricpower generating capacity andproduced about nine percent of the totalelectricity generated in the UnitedStates,30 and nonutility generatingfacilities accounted for one-fifth of alladditions to generating capacity in the

1980s.31 FERC allowed many new utility and

non-utility generators to sell electricpower supply at wholesale market,rather than regulated rates.32

In 1988 FERC solicited publiccomments on three notices of proposedrulemaking (NOPRs) concerning thepricing of electricity in wholesaletransactions: (1) Competitive bidding fornew power requirements; (2) treatmentof independent power producers; and(3) determination of avoided costs underPURPA.33 These proposals would havemoved towards greater use of a ‘‘non-

traditional’’ market-based pricingapproach in ratemaking as opposed tothe agency’s ‘‘traditional’’ cost-basedapproach. These FERC NOPRs provedcontroversial, and efforts to establishformal rules or policies adopting themwere abandoned as commissionmembership changed. However, withthe support of several Commissionmembers and key FERC staff, the overallpolicy goals were still pursued on acase-by-case basis.

FERC laid the foundation for greaterreliance on market-based mechanismsfor Federal oversight of wholesaleelectricity prices on a case-by-case basis.Between 1983 and 1991, FERC

considered more than 31 casesconcerning approval of non-traditionalrates involving independent powerproducers, power brokers/marketers,utility-affiliated power producers, andtraditional franchised utilities. FERCapproved all but four of theseapplications.34 FERC staff wrote: ‘‘TheCommission has accepted non-

traditional rates where the seller or itsaffiliate lacked or had mitigated marketpower over the buyer, and there was nopotential abuse of affiliate relationshipswhich might directly or indirectlyinfluence the market price and nopotential abuse of reciprocal dealing

between the buyer and seller.’’ 35 In its process of determining whether

the seller could exercise market powerover the buyer, the FERC consideredwhether the seller or its affiliates ownedor controlled transmission that mightprevent the buyer from accessing othersources of power. A seller with

transmission control might be able toforce the buyer to purchase from theseller, thus limiting competition andsignificantly influencing the price the

buyer would have to pay. The FPA doesnot allow rates to reflect an exercise of such market power.36

The potential for control of transmission to create market power,and the challenge that such controlcreated in moving to greater reliance onmarket-based rates, was recognized.‘‘Because the Commission’s verypremise of finding market-based ratesjust and reasonable under the FPA is theabsence or mitigation of market power,or the existence of a workablycompetitive market, and because theFPA mandates that the Commissionprevent undue preference and unduediscrimination, we believe theCommission is legally required toprevent abuse of transmission controland affiliate or any other relationshipswhich may influence the price chargeda ratepayer.’’ 37

Despite these developments, twolimitations at that time were perceivedto discourage development of competitive wholesale generationmarkets. First, IPPs and other generators

of cheaper electric power could noteasily gain access to the transmissiongrid to reach potential customers.38

Under the FPA as then written, FERCauthority to order transmission accesswas limited. FERC would subsequentlyfind that ‘‘intervening’’ transmittingutilities would deny or limittransmission service to competingsuppliers of generation service in orderto protect demand for wholesale powersupplied by their own generation

facilities.39 Second, unlike QFs thatenjoyed a statutory exemption underPURPA, IPPs were subject to the PublicUtility Holding Company Act of 1935(PUHCA), which discouraged non-utilities from entering the generation

business.40

3. Energy Policy Act of 1992 and FERCOrder Nos. 888 and 889

Congress enacted the Energy PolicyAct of 1992 (EPACT 92) 41 and amendedthe FPA and PUHCA to address twomajor limitations on the development of a competitive generation sector. First,EPACT 92 created a new category of power producers, called exemptwholesale generators (EWGs).42 A EWGwas an entity that directly, or indirectlythrough one or more affiliates, owned oroperated facilities dedicated exclusivelyto producing electric power for sale inwholesale markets.43 EWGs wereexempted from PUHCA regulations,thus eliminating a major barrier forutility-affiliated and nonaffiliated powerproducers that wanted to compete to

build new non-rate-based powerplants.44 EPACT 92 also expanded






46 Id . at ¶31,654.47 Id . Order No. 888 also clarified FERC’s

interpretation of the Federal/state jurisdictional boundaries over transmission and localdistribution. While it reaffirmed that FERC hasexclusive jurisdiction over the rates, terms, andconditions of unbundled retail transmission ininterstate commerce by public utilities, itnevertheless recognized the legitimate concerns of state regulatory authorities for the development of competition within their states. FERC therefore

declined to extend its unbundling requirement tothe transmission component of bundled retail salesand reserved judgment on whether its jurisdictionextends to such transactions. The United StatesSupreme Court affirmed this element of Order No.888. New York v. FERC , 535 U.S. 1 (2002).

48Open Access Same-Time Information System(Formerly Real-Time Information Networks) and Standards of Conduct , Order No. 889, 61 FR 21,737(May 10, 1996), FERC Stats. & Regs. ¶31,035 at31,583 (1996), order on reh’ g, Order No. 889–A,FERC Stats. & Regs. ¶31,049 (1997), order on reh’ g,Order No. 889–B, 81 FERC ¶61,253 (1997).

49 Joskow, Deregulation at 29.50EIA 2000 Update at 66.51 Id . at 66, 68, 80.52 Id . at 67.53 Joskow, Deregulation at 27–28.54EIA 2000 Update at ix.55See discussion infra, Box 1–1.56 Joskow, Deregulation at 19.57Electricity Consumers Resource Council,

Profiles in Electricity Issues: Cost-of-Service Survey(Mar. 1986).

58EIA 2000 Update at 43.

FERC’s authority to order transmittingutilities to provide transmission servicefor wholesale power transmission to anyelectric utility, Federal power marketingagency, or any person generatingelectric energy in wholesale electricitymarkets.45 The amendment provided fororders to be issued on a case by case

basis following a hearing if certain

protective conditions were met. ThoughFERC implemented this new authority,it ultimately concluded that procedurallimitations limited its reach and a

broader remedy was needed toeffectively eliminate pervasive unduediscrimination in the provision of transmission service.

Thus, in April 1996, FERC adoptedOrder No. 888 in exercise of its statutoryobligation under the FPA to remedyundue transmission discrimination toensure that transmission owners do notuse their transmission facility monopolyto unduly discriminate against IPPs and

other sellers of electric power inwholesale markets. In Order No. 888,the FERC found that unduediscrimination and anticompetitivepractices existed in the provision of electric transmission service by publicutilities in interstate commerce, anddetermined that non-discriminatoryopen access transmission service wasone of the most critical components of a successful transition to competitivewholesale electricity markets.Accordingly, FERC required all publicutilities that own, control or operatefacilities used for transmitting electric

energy in interstate commerce to fileopen access transmission tariffs(OATTs) containing certain non-priceterms and conditions and to‘‘functionally unbundle’’ wholesalepower services from transmissionservices.46 To functionally unbundle, apublic utility was required to: (1) Takewholesale transmission services underthe same tariff of general applicability asit offered its customers; (2) stateseparate rates for wholesale generation,transmission and ancillary services; and(3) rely on the same electronicinformation network that itstransmission customers rely on to obtaininformation about the utility’stransmission system.47

Concurrent with the issuance of OrderNo. 888, FERC issued Order No. 889 48 that imposed standards of conductgoverning communications between theutility’s transmission and wholesalepower functions, to prevent the utilityfrom giving its power marketing armpreferential access to transmissioninformation. Order No. 889 requires

each public utility that owns, controls,or operates facilities used for thetransmission of electric energy ininterstate commerce to create orparticipate in an Open Access SametimeInformation System, to provideinformation regarding availabletransmission capacity, prices, and otherinformation that will enabletransmission service customers to obtainopen access non-discriminatorytransmission service.49

FERC, through Order No. 888, alsoencouraged grid regionalization throughthe formation of Independent Systems

Operator (ISOs). Participating utilitieswould voluntarily transfer operatingcontrol of their transmission facilities tothe ISO to ensure independentoperation of the transmission grid.50 The ISO also could achievecoordination, reliability, and efficiency

benefits by having regional control of the grid.51 Participation in an ISOremained voluntary, however, and itonly occurred in some areas of thecountry. It was not implemented inother areas.52 Together, Order Nos. 888and 889 serve as the primary federalfoundation for providing transmission

service and information about theavailability of transmission service.53

4. Restructuring Initiatives in RetailMarkets: State-Authorized RetailElectricity Competition

Beginning in the early 1990s, severalstates with high electricity prices beganto explore opening retail electric serviceto competition. With retail competition,customers could choose their electricsupplier, but the delivery of electricitywould still be done by the localdistribution utility.

Substantial rate disparity existedamong and between utilities in differentstates. For example, customers in NewYork paid more than two and one-half

times the rates paid by customers inKentucky in 1998. Rates in Californiawere well over twice the rates inWashington.54 Some of this disparity inprice from state to state can beattributed to different natural resourceendowments across regions—mostimportant the hydroelectricopportunities in the Northwest and

some states such as Kentucky andWyoming with abundant coal reserves— and the resulting diverse costs of fuelused for generation by utilities. Anotherreason for the price disparity may bethat some states required utilities toenter into PURPA contracts thatsubsequently resulted in prices higherthan the cost to acquire power in thewholesale market.55 Utilities’ QFcontract costs were included as part of the bundled service provided to retailcustomers; ultimately the cost of thesehigh-cost PURPA contracts wasreflected in the regulated retail prices.56

Additionally, utilities in some statesinvested heavily in large, new nuclearpower plants, and coal plants, whichturned out to be more expensive thananticipated, adding to the retail rateshock.

Not only were there large disparitiesin utility rates among states, but manyindustrial customers contended thatthey subsidized lower rates forresidential customers. For example, asurvey by the Electricity ConsumersResource Council in 1986 contendedthat industrial electricity consumerspaid more than $2.5 billion annually in

subsidies to other electricity customers(e.g., commercial and residentialcustomers). By allowing industrialcustomers to choose a new supplier, itwas presumed that these subsidiescould be avoided and industrialcustomer electricity prices woulddecrease.57

This rate disparity provided animpetus for states to initiate theirrestructuring efforts; thus it is notsurprising that many of the states thatled the restructuring movement werethose with higher prices.58 As of 2004the disparity in retail prices among thestates persisted, as illustrated in Figure1–1, below.





59 Id . at 81–82. 60Paul L. Joskow, Markets for Power in the United States: An Interim Assessment , ENERGY J. 2 (2006)[hereinafter Joskow, Interim Assessment].

Not all state commissions adoptedretail competition plans, although mostof them considered the merits andimplications of competition,deregulation, and industry

restructuring. States such as Californiaand those in New England and the mid-Atlantic region, with high electricityrates, were among the most aggressive inadopting retail competition in the hopeof making lower rates available to their

retail customers. As of July 2000, 24states and the District of Columbia hadenacted legislation or passed regulatoryorders to restructure their electric powerindustries. Two states had legislation or

regulatory orders pending, while 16states had ongoing legislative orregulatory investigations. There wereonly eight states where no restructuringactivities had taken place.59 Since 2000,however, no additional states have

announced plans to implement retailcompetition programs, and severalstates that had introduced suchprograms have delayed, scaled back, orcancelled their programs entirely (see

Figure 1–2 below).60

The Californiaenergy crisis is widely-perceived tohave halted interest by states inrestructuring retail markets. Theseissues are further discussed in ChapterIV, Retail Competition.





61Regional Transmission Organizations, OrderNo. 2000, FERC Stats. & Regs. ¶ 31,089 at 16 (1999),order on reh’ g , Order No. 2000–A, FERC Stats. &Regs. ¶ 30,092, 65 FR 12,088 (2000), aff ’ d, PublicUtility District No. 1 v. FERC , 272 F.3d 607 (DC Cir.2001) [hereinafter Order No. 2000].

62 In Order No. 2000, FERC found that‘‘opportunities for undue discrimination continueto exist that may not be remedied adequately by[the] functional unbundling [remedy of Order No.888].’’ Order No. 2000, FERC Stats. & Regs. ¶ 31,089at 31,105.

63The term ‘‘rate pancaking’’ refers tocircumstances in which a transmission customermust pay separate access charges for each utilityservice territory crossed by the customer’s contractpath.

5. Development of RegionalTransmission Organizations andRegional Wholesale Markets

Even after issuance of Order Nos. 888and 889, FERC continued to receivecomplaints about transmission ownersdiscriminating against independentgenerating companies. Transmissioncustomers remained concerned thatelectric utilities’ implementation of functional unbundling did not producecomplete separation between operatingthe transmission system and marketingand selling electric power in wholesalemarkets. Also, there were concerns thatOrder No. 888 changes made somediscriminatory behavior in transmissionaccess more subtle and difficult to

identify and document.The electric industry continued totransform since FERC issued Order Nos.888 and 889, in response to competitivepressures and state retail restructuringinitiatives. Utilities today purchasemore wholesale power to meet theirload than in the past and are expandingreliance on availability of other utilitytransmission facilities for delivery of power. Retail competition increasedsignificantly in the years followingadoption of Order No. 888. These stateinitiatives brought about the divestiture

of generation plants by traditionalelectric utilities. In addition, this periodsaw a number of mergers among

traditional electric utilities and amongelectric utilities and gas pipelinecompanies, large increases in thenumber of power marketers andindependent generation facilitydevelopers entering the marketplace,and the establishment of ISOs asmanagers of large parts of thetransmission system. Trade in wholesalepower markets has increasedsignificantly and the Nation’stransmission grid is being used moreheavily and in new ways.

In response to continuing complaintsof discrimination and lack of transmission availability and in thewake of an expanding competitivepower industry, in December 1999,FERC issued Order No. 2000.61 Thisorder recognized that Order No. 888 setthe foundation upon which to attaincompetitive electric markets, but did noteliminate the potential to engage in

undue discrimination and preference inthe provision of transmission service.62 Thus, FERC concluded that regional

transmission organizations (RTOs)could eliminate transmission ratepancaking,63 increase region-widereliability, and eliminate any residualdiscrimination in transmission servicesthat can occur when the operation of thetransmission system remains in thecontrol of a vertically integrated utility.Accordingly, FERC encouraged thevoluntary formation of RTOs.

RTOs are entities set up in responseto FERC Order Nos. 888 and 2000encouraging utilities to voluntarily enterinto arrangements to operate and planregional transmission systems on anondiscriminatory open access basis.RTOs are independent entities thatcontrol and operate regional electrictransmission grids for the purpose of





64Fed. Energy Regulatory Comm’n, Office of Mkt.Oversight and Investigations, State of the MarketsReport: An Assessment of Energy Markets in theUnited States in 2004, at 51 (2005) [hereinafterFERC State of the Markets Report 2005], availableat http://www.ferc.gov/legal/staff-reports.asp.

65 Id. at 53.66 Id. at 52.67U.S. Canada Power System Outage Task Force,

Final Report on the August 14, 2003 Blackout in the

United States and Canada: Causes and

Recommendations, April 2004, at 1.68 Id.69 Id. at 107.70Pub. L. No. 109–58, 119 Stat. 594 (2005).

promoting efficiency and reliability inthe operation and planning of thetransmission grid and for ensuring non-discrimination in the provision of electric transmission services.

FERC has approved RTOs or ISOs inseveral regions of the country includingthe Northeast (PJM, New York ISO, ISO-New England), California, the Midwest

(MISO) and the South (SPP), as shownin Figure 1–3 below. By the end of 2004,regions accounting for 68 percent of alleconomic activity in the United Stateshad chosen the RTO option.64

In 2004 and 2005, the PJM gridexpanded substantially to includeseveral additional service territories in

the Midwest. In 2004, the territoriesserviced by Commonwealth Edison(ComEd), American Electric Power(AEP), and Virginia Electric and Power(VEPCO) joined PJM. The expansioncontinued in 2005 with the addition of Duquesne Light. The area now in PJMcovers about 18 percent of totalelectricity consumption in the United

States.65 In most cases, RTOs haveassumed responsibility to calculate theamount of available transfer capability(ATC) for wholesale trades across thefootprint of the RTO. RTOs also areresponsible for regional planning, atleast for facilities necessary forreliability above a certain voltage.

As of 2004, all of the RTOs inoperation coordinate dispatch of thegenerators in their systems and providetransmission services under a singleRTO open access tariff. In addition,RTOs operate regional organized energymarkets, including a short-term marketwhich prices energy, congestion, andlosses. RTOs in the East all offer day-ahead and real-time markets, whileCalifornia and Texas offer real-timemarket alone. Further, all RTOs incurrent operation use or plan to usesome form of locational pricing andhave independent market monitors.66

6. August 2003 Blackout

On August 14, 2003, an electricaloutage in Ohio precipitated a cascading

blackout across seven other states and asfar north as Ontario, leaving more than50 million people without power.67 The

August 2003 blackout was the largest blackout in the history of the UnitedStates, leaving some parts of the nationwithout power for up to four days andcosting between $4 billion and $10

billion.68 The 2003 blackout was theeighth major blackout experienced in

North America since the 1965 NortheastBlackout.

A Joint U.S.-Canada Power SystemOutage Task Force issued a finalBlackout Report in April 2004. TheBlackout Report identified factors thatwere common to some of the eight major

outage occurrences from the 1965Northeast Blackout through the 2003Blackout, as shown below:

(1) Conductor contact with trees; (2)overestimation of dynamic reactiveoutput of system generators; (3) inabilityof system operators or coordinators tovisualize events on the entire system; (4)

failure to ensure that system operationwas within safe limits; (5) lack of coordination on system protection; (6)ineffective communication; (7) lack of ‘‘safety nets;’’ and (8) inadequatetraining of operating personnel.69

7. Recent Developments: Enactment of the Energy Policy Act of 2005

In 2005, Congress passed the EnergyPolicy Act of 2005 (EPACT 2005),70 which amended the core statutes (FPA,PURPA, PUHCA) governing the electric





71EIA 2000 Update at ix. The size of the costimprovements depends on the underlying fuelprices.

72 Id.

power industry. Several key provisionsof EPACT 2005 are:

• Authorizes FERC to certify anElectric Reliability Organization topropose and enforce reliabilitystandards for the bulk power system.EPACT 2005 authorized penalties forviolation of these mandatory standards.

• Authorizes the Secretary of Energy

to conduct a study of electricitycongestion within one year of theenactment of the Energy Policy Act, andevery three years thereafter. Authorizesthe Secretary of Energy to designate‘‘National Interest Electric TransmissionCorridors’’ based on these congestionstudies. EPACT 05 also authorizes FERCin limited circumstances to approve thesiting of transmission facilities in thesecorridors, in states which lack suchauthority or do not exercise it in atimely manner. Proponents of this newfederal authority have argued that it willfacilitate the construction of new

transmission lines and, thus, helpalleviate transmission congestion thatcan impair competition in electricmarkets.

• Requires FERC to establishincentive-based rate treatments forpublic utilities’ transmissioninfrastructure in order to promotecapital investment in facilities for thetransmission of electricity, attract newinvestment with an attractive return onequity, encourage improvement intransmission technology, and allow forthe recovery of prudently incurred costsrelated to reliability and improvedtransmission infrastructure. Proponentsof this authority contend it willencourage the expansion of transmission capacity and, thus, helpfoster greater competition in electricmarkets.

• Permits FERC to terminate,prospectively, the obligation of electricutilities to buy power from QFs, such asindustrial cogenerators. FERC may do sowhen the QFs in the relevant area haveadequate opportunities to make

competitive sales, as defined by EPACT2005. The premise is that growth incompetitive opportunities in electricmarkets is negating the need forPURPA’s ‘‘forced sale’’ requirements.

• Repeals PUHCA 1935 and replacesit with new PUHCA 2005, whichprovides FERC and state access to booksand records of holding companies and

their members and provides that certainholding companies or states may obtainFERC-authorized cost allocations fornon-power goods or services provided

by an associate company to publicutility members in the holdingcompany. PUHCA 2005 also contains amandatory exemption from the Federal

books and records access provisions forentities that are holding companiessolely with respect to EWGs, QFs orforeign utility companies. The goal of these provisions is to reduce legalobstacles to investment in the electricutility industry and, thus, help facilitate

the construction of adequate energyinfrastructure.

C. Recent Trends Related toCompetition in the Electric Energy Industry

Given the previous reviewed of electric industry legal and regulatory

background, this section discussesseveral more recent electric industrypolicy developments andcharacteristics.

1. Technological Improvements inGeneration and Transmission

Electric power industry restructuring

has been largely sustained bytechnological improvements in gasturbines. No longer is it necessary to

build a large generating plant to exploiteconomies of scale. Combined-cycle gasturbines reach maximum efficiency at400 megawatts (MW), while aero-derivative gas turbines can be efficientat sizes as low as 10 MW. These newgas-fired combined cycle plants can bemore energy efficient and less costly

than the older coal-fired power plants.71 Technological advances in transmissionequipment have made transmission of electric power over long distances moreeconomical. As a result, generatingplants hundreds of miles apart cancompete with each other and customerscan be more selective in choosing anelectricity supplier.72

Despite these increases in technology,the Edison Electric Institute reports thatinvestment in transmission declinedfrom 1975 through 1997. See Figure 1– 4. Since 1998, transmission investmenthas increased annually, but remains

below 1975 levels. Over that sameperiod, electricity demand has morethan doubled, resulting in a significantdecrease in transmission capacityrelative to demand. Box 1–2 discussessome suggested explanations for thistrend of declining transmissioninvestment.

Box 1–2: Decline in Transmission InvestmentTransmission is the physical link between

electricity supply and demand. Withoutadequate transmission capacity, wholesalecompetition cannot function effectively.

Some of the reasons suggested for thedecline in transmission investment between1975 and 1997 (see Figure 1–4) are: anoverbuilt system prior to 1975, lack of available capital due to other investmentactivities by vertically-integrated utilities, theprotection of vertically-integrated utilitygeneration from competition and regulatoryuncertainty.

Another explanation for the long decline intransmission investment is the difficulty of siting new transmission lines. Siting can

bring long delays and negative publicity.NIMBY-based local opposition is usuallystrong. Also, many state processes require ashowing of benefits to the state to site atransmission line. This can create barriers fortransmission facilities that primarily benefitinterstate commerce.





73 Id. at 23.74EIA 1970–1991 at vii.

75 Id.76U.S. Dept. of Energy, Energy Information

Administration, Electric Power Annual 2004, at 2

(November 2005), available at http:// www.eia.doe.gov/cneaf/electricity/epa/epa.pdf [hereinafter EIA Electric Power Annual 2004].

2. Increase in Nonutility GenerationSuppliers

The market participation of utilitiesand other suppliers in the generation of electricity has changed over the past fewdecades. The change began with thepassage of PURPA, when nonutilitieswere promoted as energy-efficient,environmentally-friendly, alternativesources of electric power. The change

continued through the issuance of OrderNo. 888, which opened up the

transmission grid to suppliers otherthan utilities.73 Until the early 1980s,the electric utilities’ share of electricpower production increased steadily,reaching 97 percent in 1979.74 By 1991,however, the trend had reversed itself,and the electric utilities’ share declinedto 91 percent.75 By 2004, regulatedelectric utilities’ share of totalgeneration continued to decline (63.1percent in 2004 versus 63.4 percent in

2003) as IPPs’ share increased (28.2percent versus 27.4 percent in 2003).76

This trend is illustrated by comparingthe increases in capacity for utility andnonutility generation suppliers, asshown in Figure 1–5 below. While mostof the existing capacity, and until thelate 1980s, most of the additions tocapacity, have been built by electricutilities, their share of capacityadditions declined in the 1990s.Between 1996 and 2004, roughly 74percent of electricity capacity additions

have been made by independent powerproducers.





77Order No. 888, FERC Stats. & Regs. ¶ 31,036 at31,640.

78 Joskow, Difficult Transition at 7.

3. Retail Prices of Residential Electricity

As seen in Figure 1–6 below, between1970 and 1985, national averageresidential electricity prices more than

tripled in nominal terms, and increased by 25 percent (after adjusting forinflation) in real terms.77 On a nationallevel, real retail electricity prices beganto fall after the mid-1980s until 2000–

2001, as fossil fuel prices and interestrates declined and inflation moderatedsignificantly.78 Real retail prices havesince stayed flat through 2004.





79EIA 1970–1991 at 20.80EIA Electric Power Annual 2004 at 2.

81Fed. Energy Regulatory Comm’n, The WesternEnergy Crisis, The Enron Bankruptcy, & FERC ’ sResponse, at 1, available at http://www.ferc.gov/

industries/electric/indus-act/wec/chron/ chronology.pdf.

4. Changing Patterns of Fuel Use forGeneration—Reaction to Increased OilPrices and Clean-Air EnvironmentalRegulations

For utilities, coal was the fuel mostcommonly used for many years,providing 46 percent of utilities’ generation in 1970 and more than 50percent since 1980. When world oilprices escalated in the 1970s, oil-firedand gasoline-fired generation’s share of electricity supply began decreasing.

Hydroelectric power has also played alarge role in the supply of electricpower, but its use has declined relativeto other major fuels mainly because

there are a limited number of economical sites for hydroelectricprojects. Nuclear power grew to be thesecond largest fuel source in 1991 butwas not expected to continue toincrease.79

For nonutilities, natural gas has beenthe major fuel. Indeed, new capacityadded in recent years shows the

prevalence of natural gas to fuel newplants.80 As shown in Figure 1–7, recentplant additions illustrate this change infuel sources. This increased use of natural gas also is due, in part, to theClean Air Act Amendments of 1990(CAA) and state clean air requirements.The CAA sought to address the most

widespread and persistent pollutionproblems caused by hydrocarbons andnitrogen oxides— both of which areprevalent with traditional coal andpetroleum-based generating plants. TheCAA fundamentally changed thegeneration business because it would nolonger be costless to emit air pollutants.As a result of these requirements, many

generation owners and new generationplant developers turned to cleaner-

burning natural gas as the fuel sourcefor new generation plants. California has

been very dependent on gas-firedgeneration because of its specific airquality standards.81





The result of these plant additionsthrough December 2005 is that 49.9percent of the nation’s electric powerwas generated at coal-fired plants(Figure 1–8). Nuclear plants contributed

19.3 percent, 18.6 percent was generated by natural gas-fired plants, and 2.5percent was generated at petroleumliquid-fired plants. Conventionalhydroelectric power provided 6.6

percent of the total, while otherrenewables (primarily biomass, but alsogeothermal, solar, and wind) and othermiscellaneous energy sources generatedthe remaining electric power.

The trend toward gas-fueled capacityadditions may be changing, however. Inthe coming years, more coal-firedgeneration capacity may be built. Twomajor reasons may explain coal’sresurgence: (1) The relative price of natural gas compared to coal hasincreased substantially in recent yearsand (2) the cost of environmental

equipment for coal plants, such asscrubbers, has decreased. To the extentthat combined-cycle gas-fired units were

built on the assumption that natural gaswould be relatively inexpensive andthat cleaning technology for coal plantswould drive the price of coalsignificantly higher, both theseassumptions have proved questionable

with time. The Department of Energy’sEnergy Information Administration(EIA) estimated only 573 megawatts of new coal generation would be addednationally in 2005, which compareswith an estimate of 15,216 megawatts of gas-fired additions for the same year.For the year 2009, however, predictedtrends shift—the EIA projects that 8,122





82See EIA Electric Power Annual 2004 at 17,table 2.4, available at http://www.eia.doe.gov/cneaf/

electricity/epa/epat2p4.html.83See U.S. Dept. of Energy, Nat’l Energy Tech.

Lab, Tracking New Coal-Fired Power Plants, at 3–

4, available at http://www.netl.doe.gov/coal/

refshelf/ncp.pdf (predicting 85 GW of new coalcapacity created by 2025).

84See U.S. Congress, Office of TechnologyAssessment at 47.

85EIA 2000 Update at 91.86 Id. at 105–06.87 Id. at 105.88 Id. at 91.89 Id. at 106.

MW of new coal generation will beadded that year, whereas only 5,451MW of gas-fired generation additionsare predicted for that year.82 TheDepartment of Energy predicts aresurgence of coal-fired generation willcontinue as far into the future as 2025.83

5. Price Changes in Fuel Sources

Natural gas prices have beenincreasing in recent years, due in part tothe historically high level of petroleum

prices. Natural gas prices experienced a51.5 percent increase between 2002 and2003, a 10.5 percent increase between2003 and 2004, and a 37.6 percentincrease between 2004 and 2005. Strongdemand for natural gas, as well asnatural gas production disruptions inthe Gulf of Mexico, contributed to theseprice increases. As shown in Figure 1– 9, for December 2005 the overall priceof fossil fuels was influenced by the

increases in price of natural gas. InDecember 2005, the average price forfossil fuels was $3.71 per MMBtu, 10.1percent higher than for November 2005,and 44.4 percent higher than inDecember 2004. As natural gas pricesincrease relative to coal prices, thechange may make development of clean-

burning coal plants more economicalthan they were when natural gas fuelprices were lower.

6. Mergers, Acquisitions, and PowerPlant Divestitures of Investor-OwnedElectric Utilities

Many IOUs have fundamentallyreassessed their corporate strategies tofunction more as competitive, market-driven businesses in response to anincreasingly competitive businessenvironment.84 One result is that therewas a wave of mergers and acquisitionsin the late 1980s through the late 1990s

between traditional electric utilities and between electric utilities and gas

pipeline companies.IOUs also have divested a substantial

number of generation assets to IPPs ortransferred them to an unregulatedsubsidiary within the company.85 Eventhough FERC-regulated IOUs havefunctionally unbundled generation fromtransmission, and some have formed

RTOs and ISOs, many utilities havedivested their power plants because of state requirements. Some states thatopened the electric market to retailcompetition view the separation of power generation ownership frompower transmission and distributionownership as a prerequisite for retailcompetition. For example, California,Connecticut, Maine, New Hampshire,and Rhode Island enacted lawsrequiring utilities to divest their powerplants. In other states, the state public

utility commission may encouragedivestiture to arrive at a quantifiablelevel of stranded costs for purposes of recovery during the transition tocompetition.86

Since 1997, IOUs have divestedpower generation assets atunprecedented levels,87 and these

power plant divestitures have alsoreduced the total number of IOUs thatown generation capacity.88 A fewutilities have decided to sell their powerplants, as a business strategy, decidingthat they cannot compete in acompetitive power market. In a fewinstances, an IOU has divested powergeneration capacity to mitigate potentialmarket power resulting from a merger.89 As described in Table 1–6 below,

between 1998 and 2001, over 300plants, representing nearly 20% of U.S.

installed generating capacity, changedownership.

There was no significant electricpower company merger activity from2001 to 2004, but this changed in 2004,when utilities and financial institutionsexhibited growing interest in mergersand acquisitions, prompting many





90FERC State of the Markets Report 2005 at 30– 32.

91Announced in December 2003, Ameren closedits acquisition of Illinois Power Co. in September2004. Id. at 31.

92 In January 2004, Black Hills Corp announcedthe acquisition of Cheyenne Light, Fuel & Powerfrom Xcel Energy. In July 2004, PNM Resources, theparent of Public Service Company of New Mexico,announced the intention to acquire TNPEnterprises, the parent of Texas New Mexico PowerCompany from a group of private equity investors.

Id. at 31–32. In December 2004, Exelon announcedits intent to merge with PSEG, a plan that wouldcreate the nation’s largest utility company bygeneration ownership, market capitalization,revenues, and net income. Id. at 32.

93 Id. at 30.

analysts to herald 2004 as theinauguration of a new round of consolidation in the power sector.90 Oneutility-to-utility acquisition wasclosed 91 and three were announced.92

Most electric acquisitions in 2004 tookplace with the purchase of specificgeneration assets; many companiesstrove to stabilize financial profilesthrough asset sales. In aggregate, almost

36 GW of generation, or nearly 6 percentof installed capacity, changed hands in2004.93

TABLE 1–6.—POWER GENERATION ASSET DIVESTITURES BY INVESTOR-OWNED ELECTRIC UTILITIES, AS OF APRIL 2000

Status category Capacity (GW) Percent oftotal

Percent of

total U.S.GenerationCapacity

Sold .............................................................................................................................................. 58.0 37 8Pending Sale (Buyer Announced) ............................................................................................... 28.2 18 4For Sale (No Buyer Announced) ................................................................................................. 31.9 20 4Transferred to Unregulated Subsidiary ....................................................................................... 4.1 3 1Pending Transfer to Unregulated Subsidiary .............................................................................. 34.2 22 5

Total ...................................................................................................................................... 156.5 100 22

Source: EIA 2000 Update, Table 19.

Chapter 2—Context for the Task Force’sStudy of Competition in Wholesale andRetail Electric Power Markets

This chapter provides the context tothe Task Force’s study of competition inwholesale and retail electric powermarkets. For approximately 70 years,state and federal policymakers regulatedthe generation, transmission, anddistribution of electric power as naturalmonopolies—it was consideredinefficient to have multiple sources of generation, transmission, anddistribution facilities serving the samecustomers. The traditional ‘‘regulatorycompact’’ required an electric powerutility to serve all retail customers in adefined area in exchange for theopportunity to earn a reasonable returnon its investment. This approach isoften called ‘‘cost-based’’ or ‘‘cost-plus’’ regulation.

Technological and regulatory changesas discussed in Chapter 1 negated thenatural monopoly assumption for themost capital intensive segment of theindustry—the generation of electricpower. Federal and several statepolicymakers introduced competition toprovide for an economically efficientallocation of resources within theindustry’s generation sector and toovercome the perceived shortcomings of

traditional cost-based regulation. Thischapter describes these shortcomings. Italso discusses the role of price inguiding consumption and investmentdecisions in competitive markets.

This chapter highlights three issuesthat policymakers confronted as they

considered introducing competition intowholesale and retail electric powermarkets. First, customers under

historical cost-based regulationgenerally paid average prices calculatedover an extended period of months oryears that did not vary with theirconsumption or with variation in thecost of generating electric power. Thus,wholesale and retail customers did notreceive economically accurate pricesignals to guide their consumptiondecisions. Similarly, suppliers did notreceive economically accurate pricesignals to guide their short term sales of existing generation and long termgeneration. Second, regulators hadhistorically encouraged local utilities to

build or contract for sufficientgeneration to serve customers withintheir territories and they erected entry

barriers to block entry by independentgenerators. These actions resulted inutilities owning nearly all generationassets within their own serviceterritories. Under cost-based regulation,the regulator would set the price forelectric power, thus addressing possiblemarket power abuses that otherwisecould occur with the monopoly utilitystructure. Third, certain physicalrealities associated with electricitygeneration constrain regulatory and

market options in this industry. Theinability to economically store electricpower means that electricity mustgenerally be consumed as soon as it isgenerated—supply must always exactlyequal demand in real time. The deliveryof electric power depends, however,

upon availability and pricing of theregulated transmission grid. Thus, thephysical realities of the transmission

grid must be considered as competitiondevelops in wholesale electric powermarkets.

The Task Force received manycomments identifying or endorsingvarious studies on aspects of the costsand benefits of competition inwholesale and retail electric powermarkets, particularly the formation of Regional Transmission Organizations(RTOs) or similar entities.

Appendix C contains an annotated bibliography of these studies. Many of these studies, however, provide onlylimited insights into the effect of

restructuring in wholesale and retailelectric power markets. See Box 2–1 thatdescribes a recent Department of Energyreview of such studies. This Reportaddresses competition in variouswholesale and retail markets regardlessof whether they contain an RTO orsimilar entity.

Box 2–1: ‘‘A Review of Recent RTO Benefit-Cost Studies: Toward More ComprehensiveAssessments of FERC ElectricityRestructuring Policies’’

By J. Eto, B. Lesieutre, and D. Hale, Prepared for the U.S. Department of Energy, December 2005

This paper provides a review of the stateof the art in RTO Cost/Benefit studies andsuggests methodological improvements forfuture studies. The study draws the followingconclusions:

In recent years, government and privateorganizations have issued numerous studies





94Electricity Consumers Resource Council,Profiles in Electricity Issues: Cost-of-Service Survey(Mar. 1986).

95See e.g. The Economics and Regulation of Antitrust, at 6–7.

96 In the academic literature, the risk of utility

overinvestment has been explained by the Averch- Johnson Effect. The Averch-Johnson Effect reflectsthat ‘‘a firm that is attempting to maximize profitsis give, by the form of regulation itself, incentivesto be inefficient. Furthermore, the aspects of monopoly control that regulation is intended toaddress, such as high prices, are not necessarilymitigated, and could be made worse, by theregulation.’’ KENNETH E. TRAIN, OPTIMALREGULATION 19 (1991). The Averch-JohnsonEffect also predicts that if a regulator attempts toreduce a firm’s profits by reducing its rate of return,the firm will have an incentive to further increaseits relative use of capital. Id. at 56. Thus, the mostobvious regulatory control within cost-base rateregulation creates further distortions. The Averch- Johnson Effect is sometimes thought to explain whya regulated firm is led to ‘‘gold plate’’ its facilities,i.e. incur excessive costs so long as those expensescan be capitalized.

97U.S. Dept. of Energy, The Future of ElectricPower in America: Economic Supply for EconomicGrowth, June, 1983 (DOE/PE–0045).

98Under price cap regulation, a firm cantheoretically ‘‘produce with the cost-minimizinginput mix [and] invest in cost-effective innovation.’’ Train at 318. However, this dynamic only occurswhere the price cap is fixed over time and theutility receives the benefit of cost reductions andcost-effective innovations. Further, the benefit of this increased efficiency ‘‘accrues entirely to thefirm: consumers do not benefit from the productionefficiency.’’ Id. Where the price cap is adjusted overtime, firms are induced to engage in strategic behavior. Additionally, ‘‘if, as * * * expected, thereview of price caps is conducted like the price

of the benefits and costs of RegionalTransmission Organizations (RTOs) andother electric market restructuring efforts.Most of these studies have focused on

benefits that can be readily estimated usingtraditional production-cost simulationtechniques, which compare the cost of centralized dispatch under an RTO todispatch in the absence of an RTO, and onthe costs associated with RTO start-up andoperation. Taken as a whole, it is difficult todraw definitive conclusions from thesestudies because they have not examinedpotentially much larger benefits (and costs)resulting from the impacts of RTOs onreliability management, generation andtransmission investment and operation, andwholesale electricity market operation.

Existing studies should not be criticized foroften failing to consider these additionalareas of impact, because for the most partneither data nor methods yet exist on whichto base definitive analyses. The primaryobjective of future studies should not be tosimply improve current methods, but toestablish a more robust empirical basis for

ongoing assessment of the electric industry’sevolution. These efforts should be devoted tostudying impacts that have not beenadequately examined to date, includingreliability management, generation andtransmission investment and operationalefficiencies, and wholesale electricitymarkets. Systematic consideration of theseimpacts is neither straightforward norpossible without improved data collectionand analysis.

A. Overview of Cost-Based RateRegulation—Effect on Customer Pricesand Investment Decisions

State policymakers imposed rateregulation on retail sales of electricpower because allowing prices to be set

by the monopolist was expected to leadto uneconomic results, namely higherprices with lower output. Regulatorsused cost-based regulation to meet statelegal requirements to ensure sufficientoutput at reasonable prices forconsumers.

1. Effect on Customer Prices

Retail prices for most customers,although different for each customerclass, often were average pricescalculated over an extended period of months or years that did not vary withtheir consumption or with the costs of generating electric power. These rateswere stable and often only varied byseason (e.g., summer rates may behigher than winter rates). Althoughtime-based rates and certain regulatedproducts such as interruptible orcurtailable services have been usedwithin the electric power industry fordecades, they have not been applied tothe vast majority of retail customers. Inaddition, many argued that retail rate

structures contain cross-subsidiesamong customer classes.94

2. Effect on Investment Decisions

The usual market-based signal forefficient investment into a market— prices that align consumer demand withgenerators’ supply under given marketconditions—is unavailable under cost-

based rate regulation of retail electricpower prices. Under cost-based rateregulation, utilities could decide whento add generation, but their recovery of their costs for these investments wasdependent on state regulators agreeingthat the generation was necessary andprudent. (Most state also imposed sitingregulation on construction of majorelectric power facilities). Thus, it waslong term planners and regulators thatdetermined when generation would be

built, and it was consumers who borethe cost of investment risks once theyhad been approved by the stateregulators. Utilities were reluctant totake investment risks that might end up

being unrecoverable if the regulatorsdeemed their cost unreasonable. By far,the most important of these decisionswas for generation investment whichconstitutes the substantial majority of the capital investment in the electricpower industry. While the intent of cost-based rate regulation, was notsimply to keep price down, the effectwas sometimes to dampen investmentin new capacity and innovation.95 Inmaking decisions, regulators struggledto strike the balance between reasonable

rates and providing utilities withincentives to make necessary andsufficient investments.

Regulatory mistakes in setting ratestoo high or too low may lead toexcessive or inadequate additions of new electric power generation and otherforms of investment. If rates are set toohigh, utilities could earn a higher returnon new generation investments thanwould be warranted by the cost of capital. The result could beoverinvestment and overbuilding.Utilities also had little incentive todesign new generation plants in a cost-

effective manner, to the extentregulators were unlikely to identify anddisallow excessive costs to be includedin customer rates. At the same time,regulatory disallowances of some costsimposed risk on utility decisions toelicit capital and build new generation,and investors sought compensation for

this risk when they supplied capital toutilities.96

Indeed, a 1983 Department of Energyanalysis of electric power generationplant construction showed that electricutilities (which were regulated under acost-based regulatory regime) had littleability to control the construction costsof coal and nuclear generation plants.

During the 1970s and early 1980s, thecost range per megawatt to build anuclear plant varied by nearly 400percent and by 300 percent for coalplants. The DOE study showed thatsome companies were not competent tomanage such large-scale, capital-intensive projects. In addition, therewas a tendency to custom design theseplants, as opposed to use of a basicdesign and then refining it.97

Box 2–2: Market Prices

Market prices reflect myriad individualdecisions about prices at which to sell or

buy. Market prices are a mechanism that

equalizes the quantity demanded and thequantity supplied. Rising prices signalconsumers to purchase less and producers tosupply more. Falling prices signal consumersto purchase more and producers to supplyless. Prices will stop rising or falling whenthey reach the new equilibrium price: theprice at which the quantity that consumersdemand matches the quantity that producerssupply.

One alternative to traditional rate-of-return regulation is price cap regulation.Under this approach, the regulator capsthe price a firm is allowed to charge.98





reviews under cost-base rate regulation, then thedistinction blurs between price-cap regulation andcost-base rate regulation.’’ Id at 319.

99U.S. Department of Energy, Benefits of Demand Response in Electricity Markets and Recommendations for Achieving Them: A Report tothe United States Congress Pursuant to Section1252 of the Energy Policy Act of 2005, February2006 (DOE EPAct Report). The DOE EPAct Reportdiscusses the benefits of demand response inelectric power markets and makesrecommendations to achieve these benefits.

100There is a substantial literature on setting rates based on marginal costs in the electric sector. Seefor example, M. Crew and P. Kleindorfer, PublicUtility Economics. St. Martin’s Press: New York,1979 and B. Mitchell, W. Manning, and J. Paul

Acton, Peak-Load Pricing. Ballinger: Cambridge,1978. Other papers suggest that setting rates basedon marginal costs will result in a misallocation of resources (see Borenstein, S., The Long-RunEfficiency of Real-Time Pricing, ENERGY JOURNAL, Vol. 26, No. 3, 2005). Nevertheless, theliterature also indicates that marginal cost pricingmay result in a revenue shortfall or excess, andstandard rate-making practice is to require anadjustment (presumably to an inelastic component)to reconcile with embedded cost-of-service. Variousrate structures to accomplish marginal-cost pricinginclude two-part tariffs (see Viscusi, Vernon, andHarrington, Economics of Regulation and Antitrust,MIT Press, 2000) and allocation of shortfalls to rateclasses.

101DOE EPAct Report, p. 7.

102Estimates of the total costs in the United Statesdue to August 14, 2003 blackout range between $4 billion and $10 billion. ELCON, The EconomicImpacts of the August 2003 Blackout, February 2,2004.

This alternative may remedy some of the incentive problems of cost-baseregulation. Another alternative isIntegrated Resource Planning, whichprovided that choices about the buildingof new generation would be controlled

by the regulator. Even with thisoversight mechanism, regulators hadfew reference points to determine

prudence in the choices that the buildermade about design, efficiency, andmaterials.

In part, the struggles of regulators toensure adequate supplies of power atreasonable rates led policy makers toexamine whether competition couldprovide more timely and efficientincentives for what to consume and

build. Advances in technology negatedthe assumption that generation is anatural monopoly, and thus set the stagefor price and competition to provide amarket entry signal, althoughtransmission and distribution would

continue to be regulated.B. Competition in Wholesale and Retail Electric Power Markets—The Role of Price

With competition, the price of acommodity such as electric powergenerally reflects suppliers’ costs andconsumers’ willingness to pay. Theprice signals the relative value of thatcommodity compared to other goodsand services. How much a supplier willproduce at a given price is determined

by many things, including (in the longrun) how much it must pay for the laborit hires, the land and resources it uses,the capital it employs, the fuel inputs itmust purchase to generate the electricpower, the transmission it must use todeliver the electric power to end users,and the risks associated with itsinvestment. Consumers’ overallwillingness to pay for a product also isdetermined by a large variety of factors,such as the existence and prices of substitutes, income, and individualpreferences.

1. Price Affects Customer Consumption

Price changes signal to customers inwholesale and retail markets that they

should change their decisions abouthow much and when to consumeelectric power. Price increases generallyprovide a signal to customers to reducethe amount they consume. Thedampening effect on price of a reductionin consumption helps consumerssafeguard themselves against a supplierthat may seek to exercise market power

by increasing prices. By contrast, lower

prices may encourage some customersto consume more than they would haveat higher prices. Price changes thus playan important economic function byencouraging customers and suppliers torespond to changing market conditions.In the electric power industry,consumer’s price responsiveness isoften referred to as ‘‘demand

response.’’ 99 The primary objective to incorporate

price-based signals into wholesale andretail electric power markets is toprovide consumers with price signalsthat accurately reflect the underlyingcosts of production. These signals willimprove resource efficiency of electricpower production due to a closeralignment between the price thatcustomers pay for and the value theyplace on electricity. In particular, byexposing customers (some or all) toprices based on marginal productioncosts, resources can be allocated more

efficiently.100

Flat electricity prices based on average costs can leadcustomers to ‘‘over-consume—relativeto an optimally efficient system in hourswhen electricity prices are higher thanthe average rates, and under-consume inhours when the cost of producingelectricity is lower than averagerates.’’ 101 Exposure of customers toefficient price signals also has the

benefit of increasing price responseduring periods of scarcity and highprices, which can help moderategenerator market power and improvereliability.

When customers have many close

substitutes for a particular good, arelatively small price increase willresult in a relatively large reduction in

how much they consume. For example,if natural gas were a very goodsubstitute for electric power atcomparable prices, then even arelatively small increase in the price of electric power could persuade manyconsumers to switch in part or entirelyto natural gas, rather than electricity. Toinduce those consumers to return to

using electricity, electricity priceswould not need to fall by very much.However, when there are no closesubstitutes for electric power, pricesmay have to rise substantially to reduceconsumption in order to restore the

balance between the quantity suppliedand the quantity demanded.

A substantial body of empiricalliterature has shown that, even if theretail price of electricity increasesrelatively quickly and sharply, theshort-run consumption of electricitydoes not decline much. In other words,short-run demand for electricity is very

inelastic. See Box 2–3. This inability tosubstitute other products for electricity

in the short run means that changes insupply conditions (price of input fuels,etc.) are likely to cause wider pricefluctuations than would be the case if customers could easily reduce theirdemand when prices rise. Furthermore,electric power has few viable andeconomic substitutes for key end-usessuch as refrigeration and lighting andthus the consequences for supplyshortfalls can be significant.102 In thelong run, this effect may be somewhatmuted as, with time, electricitycustomers may have more ability to

adjust their consumption in response toprice changes.

Box 2–3: Demand Elasticity

The desire and ability of consumers tochange the amount of a product they willpurchase when its price increases is knownas the price elasticity of that product. Theprice elasticity of demand is the ratio of thepercent change in the quantity demanded tothe percent change in price. That is, if a 10percent price increase results in a 5 percentdecrease in the quantity demanded, the priceelasticity of demand equals ¥0.5 (¥5%/10%). If the ratio is close to zero demand isconsidered ‘‘inelastic’’, and demand is more‘‘elastic’’ as the ratio increases, especially if the ratio is greater than

¥1. Short-run

elasticities are typically lower than long-runelasticities.

Experience in New York, Georgia,California, and other states and pricingexperiments have demonstrated thatcustomers have adjusted theirconsumption, and are responsive to





103Charles River Associates, Impact Evaluation of the California Statewide Pricing Pilot, Final Report,March 16, 2005, available at http:// www.energy.ca.gov/demandresponse/documents/ group3 _ final _reports/2005– 03– 24 _SPP _FINAL _REP.PDF. Customers on a similar CPPprogram at Gulf Power also have high satisfactionwith the program, which incorporates automatedresponse to CPP events.

104EEI; PEPCO cautions that many customers,particularly residential and commercial customers,are relatively inflexible in responding to pricechanges due to constraints imposed by theiroperations and equipment.

105APPA.106Alcoa.107TAPS.

short-run price changes (i.e., have a non-zero short-run price elasticity of demand). Georgia Power’s Real TimePricing (RTP) tariff option has foundthat industrial customers who receiveRTP based on an hour-ahead market aresomewhat price-responsive (short-runprice elasticities ranging fromapproximately¥0.2 at moderate prices,

to¥

0.28 at prices of $1/kWh or more).Among day-ahead RTP customers,short-run price elasticities range fromapproximately¥0.04 at moderate pricesto¥0.13 at high prices. Similarelasticities were found in the NationalGrid RTP pricing program. A criticalpeak pricing experiment in California in2004 determined that small residentialand commercial customers are priceresponsive and will make significantreductions in consumption (13 percenton average, and as much as 27 percentwhen automated controls such ascontrollable thermostats were installed)

during critical peak periods. In addition,the California pilot found that mostcustomers who were placed on the CPPtariffs had a favorable opinion of therates and would be interested incontinuing in the program.103

The ability of a customer to respondto prices requires the followingconditions: (1) That time-differentiatedprice signals are communicated tocustomers, (2) that customers have theability to respond to price signals (e.g.,

by reducing consumption and/orturning on an on-site generator), and (3)that customers have interval meters (i.e.,

so the utility can determine how muchpower was used at what time and billaccordingly).104 Most conventionalmetering and billing systems are notadequate for charging time-varying ratesand most customers are not used toconsidering price changes in makingelectricity consumption decisions on adaily or hourly basis.

2. Supplier Responses Interact WithCustomer Demand Responses to DriveProduction

Generation supply responses areequally important in determining anappropriate equilibrium market price.

The extent of supply responses will

depend on the cost of increasing ordecreasing output. Generally, the longerindustry has to adjust to a change indemand, the lower will be the cost of expanding that output. With more time,firms have more opportunity to changetheir operations or invest in newcapacity.

If the cost of increasing production is

small, then a relatively small priceincrease may be enough to encourageexisting producers to increase theirproduction levels to provide additionalsupply in response to increaseddemand. If the cost of increasingelectricity capacity is high, however,existing suppliers will not increase theirproduction without a very strong pricesignal. In that case, customers wouldhave to pay significantly higher pricesto obtain additional supply.Additionally, if suppliers are alreadyproducing as much electric power asthey can, increased demand can be met

only from new capacity, and suppliersmust be confident that prices willremain high enough for long enough tojustify building a new generating plant.

These supply decisions arecomplicated because electric powercannot be stored economically, thusthere are generally no inventories inelectricity markets. Therefore, electricitygeneration must always exactly matchelectricity consumption.105 The lack of inventories means that wholesaledemand is completely determined byretail demand. Moreover, any distantgeneration must ‘‘travel’’ over atransmission system with its own

limiting physical characteristics.106 Transmission capability is required toallow customers access to distantgeneration sources. The transmissionsystem is complicated by the fact thatthe dynamics of the AC transmissiongrid create network effects and canproduce positive externalities(depending on the method used inaccounting for transmission costs).107 That is to say, where transmission usersare not charged for the congestionimpacts of their use patterns, that user’sactions can cause costs to other users— costs which the causal party is not

obligated to pay. This dynamic candistort the effect of price signals ondispatch efficiencies.

Moreover, aggregate retail demandfluctuates throughout the day, withhigher demand during the day than atnight. Fluctuating demand means thatthe transmission operator must havesufficient capacity to equal or exceedcustomer demand in real-time. Load

serving entities (those entities thatdeliver power to meet demand or‘‘load’’) must supply or procuresufficient capacity and energy (either inlong-term contracts or short-term ‘‘spot’’ market purchases) to meet these varyingloads. The costs of generating electricityare also highly variable, leading to widedisparity between the costs of

generating electricity from generationplants that operate around-the-clockversus the cost of those that generateonly during peak periods.

In any case, a higher price signals aprofit opportunity, attracting resourceswhere they are needed. If customerdemand decreases in response to risingprices, prices are likely to fall, all elseequal. In that circumstance, fallingdemand signals suppliers to reduce theamount of electric power that theysupply. Suppliers will reduce theirgeneration to meet the new, lower levelof consumer demand, and will not be

inclined to consider any new capacityincreases.

3. Customer and Supplier BehaviorResponding to Price Changes in Markets

In sum, the combined impact of consumers’ and suppliers’ responses tochanged market conditions will producea new market equilibrium price. Currentprices must change when they create animbalance between the quantitydemanded and the quantity supplied.For example, when demand spikes,short-run prices might have to swingsharply higher to provide incentives forshort-run supply increases. However,consumers do not have very many goodsubstitutes for electric power, andsuppliers usually cannot increaseoutput instantly or transport distantavailable generation to increase thequantity supplied to a market. Even if higher prices give consumers andproducers incentives to change their

behavior, they may have little ability todo so in the short term. Over muchlonger time frames, however, bothconsumers and producers have moreoptions to react to higher prices. Theresult is that long-run price increasesusually will be much smaller than the

short-run price increases needed toinduce additional generation.

Chapter 3—Competition in WholesaleElectric Power Markets

A. Introduction and Overview

Congress required the Task Force toconduct a study of competition inwholesale electric power markets.Wholesale markets involve sales of electric power among generators,marketers, and load serving entities(e.g., distribution utilities) that





108U.S. v. Otter Tail Power Company, 410 U.S.366 (1973) (the United States sued a verticallyintegrated utility for refusal to deal with the Townof Elbow Lake, MI, a town that was seekingalternative sources of wholesale power for aplanned municipal distribution system).

109See EPACT 92 House Report. H.R. No. 102– 474(I) at 138.

110See infra Chapter 1.

111See, e.g., U.S. Gen. Accounting Office, GAO– 03–271, LESSONS LEARNED FROM ELECTRICINDUSTRY RESTRUCTURING 21 (2002)(‘‘Increasing the amount of competition requiresstructural changes within the electric industry, suchas allowing a greater number of sellers and buyersof electricity to enter the market’’).

112H.R. No. 102–474(I) at 133.

113The demand charge for long-term point-to-point transmission service is known in advance. Fornetwork service, the transmission customer pays aload ratio share of the transmission provider’sFERC-approved transmission revenue requirement.Thus, even if redispatch to relieve transmissioncongestion occurs and the costs are charged to

Continued

ultimately resell the electric power toend-use customers (e.g., residential,commercial, and industrial customers).Prior to the introduction of competition,vertically integrated utilities with excesselectric power sold it to other utilitiesand to wholesale customers such asmunicipalities and cooperatives thathad little or no generating capacity of

their own. The Federal EnergyRegulatory Commission (FERC) and itspredecessor agency (the Federal PowerCommission) regulated the prices, termsand conditions of interstate wholesalesales by investor-owned utilities. Thedesire of wholesale purchasers foraccess to competitive sources of electricpower was a fundamental impetus tothe opening of the generation sector tocompetition.108

Effective competition ensures aneconomically efficient allocation of resources. Congress in the Energy PolicyAct of 1992 (EPACT 92) determined that

competition in wholesale electric powermarkets would benefit from two changesto the traditional regulatory landscape:(1) Expansion of FERC’s authority toorder utilities to transmit, or ‘‘wheel,’’ electric power on behalf of others overtheir owned transmission lines; and (2)elimination of entry barriers so non-utility entry could occur. The formerchange permitted wholesale customersto purchase supply from distantgenerators and the latter changeprovided customers with competitivealternatives from independententrants.109

As described in Chapter 2, animportant component of effectivemarket operation is customer responseto prices. The demand for wholesalepower, however, is derived entirelyfrom consumption choices at the retaillevel. The lack of electric powerinventories only intensifies the directlink between wholesale and retailelectric power markets. Yet stateregulators set the prices for retailcustomers. State regulators generallyhave treated wholesale rates as an inputinto retail prices. But states often setretail rates that dilute the direct impact

of the price of wholesale power on retailprices.110 Thus, retail consumptiondecisions have been guided by prices,terms, and conditions that often do notdirectly reflect the wholesale price to

purchase the electric power or the costgenerators incurred to produce it.

This price disconnect is heightened by the fact that, if competition is toallocate resources in an economicallyefficient manner, customers must haveaccess to a sufficient number of competing suppliers either viatransmission or from new local

generation.111 But one of theshortcomings of cost-based rateregulation was its inability to provideincentives for investors to makeeconomically efficient decisionsconcerning when, where, and how to

build new generation.Thus, the question is whether

competition in wholesale markets hasresulted in sufficient generation supplyand transmission to provide wholesalecustomers with the kind of choice thatis generally associated with competitivemarkets. In other words, hascompetition in wholesale electric powermarkets resulted in an economicallyefficient allocation of resources? Theanswer to this question is difficult toderive because each region was at adifferent regulatory and structuralstarting point upon Congress’ enactmentof the Energy Policy Act of 1992. Thesedifferences make it difficult to single outthe determinants of consumption andinvestment decisions and thus make itdifficult to evaluate the degree to whichmore competitive markets haveinfluenced such decisions. Even theorganized exchange markets havedifferent features and characteristics.For example, some regions already had

tight power pools, others were moredisparate in their operation of generation and transmission. Someregions had higher population densitiesand thus more tightly configuredtransmission networks than did others.Some regions had access to fuel sourcesthat were unavailable or less availablein other regions (e.g., natural gas supplyin the Southeast, hydro-power in theNorthwest). Some regions operate undera transmission open-access regime thathas not changed since the early days of open access in 1996, while other regionshave independent provision of

transmission services and organizedday-ahead exchange markets for electricpower and ancillary services.

This chapter discusses the impact of competition for generation supply onthe ability of wholesale customers tomake economic choices among

suppliers and for suppliers to makeeconomic investment decisions. Thechapter addresses how entry hasoccurred in several regions withdifferent forms of competition (e.g., theMidwest, Southeast, California, theNorthwest, Texas, and the Northeast).This chapter also discusses how long-term purchase and supply contracts,

capital requirements, regulatoryintervention, and transmissioninvestment affect supplier and customerdecisions. The chapter concludes withobservations on various regionalexperiences with wholesalecompetition. These observationshighlight the trade-offs involved withvarious policy choices used to introducecompetition.

B. Background

Congress enacted the EPACT 92 tojump start competition in the electricpower industry. One of the statedpurposes of the EPACT 92 was ‘‘to usethe market rather than governmentregulation wherever possible both toadvance energy security goals and toprotect consumers.’’ 112 Policy makersrecognized that vertically integratedutilities had market power in bothtransmission and generation—that isthey owned all transmission and nearlyall generation plants within certaingeographic areas. Congress, therefore,enhanced FERC’s authority to orderutilities, case-by-case, to transmit powerfor alternative sources of generationsupply.

Today, vertically integrated utilities

that operate their transmission systemsgenerally offer transmission serviceunder the terms of the standard OpenAccess Transmission Tariff (OATT)adopted by FERC in Order No. 888. TheOATT requires a utility to offer the samelevel of transmission service, under thesame terms and conditions and at thesame rates that it provides to itself.Vertically integrated utilities (alsoreferred to here as the transmissionprovider) offer two types of long-termtransmission service under the OATT:network integration transmissionservice (network service) and point-to-

point transmission service. See Box 3– 1 for a description of both types of transmission service. For both services,the price has been predictable andstable over the long term.113





customers, or expansion is necessary and the costsof the expansion are added to the revenuerequirement, the distribution of the costs over thewhole system has allowed the charges to individualcustomers to remain relatively stable. Customerswho take either kind of service have a right tocontinue taking service when their contract expires,although point-to-point customers may have to paya different rate (up to the maximum rate stated inthe transmission provider’s tariff) for that service if another customer offers a higher rate.

114APPA, TAPS. See also Midwest Stand AloneTransmission Companies.

115Prior to wholesale competition, several of theregions listed had ‘‘power pools’’ of utilities thatundertook some central economic dispatch of plants and divided the cost savings among thevertically integrated utility members.

Box 3–1: How Transmission Services AreProvided Under the OATT

OATT contracts can be for point-to-point(PTP) or ‘‘network’’ transmission service.Network integration transmission serviceallows transmission customers (e.g., loadserving entities) to integrate their generationsupply and load demand with that of thetransmission provider.

A transmission customer taking networkservice designates ‘‘network resources,’’ which includes all generation owned,purchased or leased by the network customerto serve its designated load, and individualnetwork loads to which the transmissionprovider will provide transmission service.The transmission provider then providestransmission service as necessary from thecustomer’s network resources to its networkload. The customer pays a monthly charge forthe basic transmission service, based on a‘‘load ratio share’’ (i.e., the percentage shareof the total load on the system that thecustomer’s load represents) of thetransmission-owning and operating utility’s‘‘revenue requirement’’ (i.e., FERC-approvedcost-of-service plus a reasonable rate of

return).In addition to this basic charge, some

additional charges may be incurred. Forexample, when a transmission customertakes network service, it agrees to‘‘redispatch’’ its generators as requested bythe transmission provider. Redispatch occurswhen a utility, due to congestion, changesthe output of its generators (either byproducing more or less energy) to maintainthe energy balance on the system. If thetransmission provider redispatches its systemdue to congestion to accommodate a networkcustomer’s needs, the costs of that redispatchare passed through to all of the transmissionprovider’s network customers, as well as toits own customers, on the same load-ratio

share basis as the basic monthly charge.Also, the transmission provider must plan,

construct, operate and maintain itstransmission system to ensure that itsnetwork customers can continue to receiveservice over the system. To the extent thatupgrades or expansions to the system areneeded to maintain service to a networkcustomer, the costs of the upgrades orexpansions are included in the transmission-owning utility’s revenue requirement, thusimpacting the load-ratio share paid bynetwork customers.

Point-to-point transmission service, whichis available on a firm or non-firm basis andon a long-term (one year or longer) or short-term basis, provides for the transmission of

energy between designated points of receiptand designated points of delivery.Transmission customers that take this kind of service specify a contract path. A customer

taking firm point-to-point transmissionservice pays a monthly demand charge basedon the amount of capacity it reserves.Generally, the demand charge may be thehigher of either the transmission provider’sembedded costs to provide the service, or theincremental costs of any system expansionneeded to provide the service. Also, if thetransmission system is constrained, thedemand charge may reflect the higher of the

embedded costs or the transmissionprovider’s ‘‘opportunity’’ costs, with thelatter capped at incremental expansion costs.

The comments submitted in responseto the Task Force’s request raisedseveral concerns as to transmission-dependent customers’ access toalternative generator suppliers viaOATTs. In particular, some commentersnoted that there is a continuedpossibility of transmissiondiscrimination in their region, and thatability for transmission suppliers todiscriminate can deny transmission-dependent customers access to

alternative suppliers.114

Thecommenters conclude that transmissiondiscrimination can increase deliveryrisk because purchasers feared that theirtransmission transactions might beterminated for anticompetitive reasons

by their vertically integrated rival, werethey to purchase generation from agenerator who is not affiliated with thetransmission provider. The fact thatelectricity cannot be storedeconomically and electricity demand isvery inelastic in the short termheightens the ill-effects of this deliveryrisk.

One response to this risk is to turnover operation of the transmission gridin a region to an independent operator,like the ones that now operate in NewEngland, New York, the Mid-Atlantic,Texas, and California (‘‘organizedmarkets’’). With the market design inthese regions, there is no risk that awholesale customer will not be able todeliver power to its retail customers(although they remain exposed to pricerisk).115 See Box 3–2 for a discussion of how transmission is provided inorganized wholesale markets.

Box 3–2: How Transmission Is Priced in an

ISO or RTOISOs and RTOs (hereinafter RTOs) provide

transmission service over a region under asingle transmission tariff. They also operateorganized electricity markets for the tradingof wholesale electric power and/or ancillaryservices. Transmission customers in these

regions schedule with the RTO injections andwithdrawals of electric power on the system,instead of signing contracts for a specific typeof transmission service with the transmissionowner under an OATT.

The pricing for transmission service issubstantially different in these regions thanunder the OATT. RTOs generally managecongestion on the transmission grid througha pricing mechanism called Locational

Marginal Pricing (LMP). Under LMP, theprice to withdraw electric power (whether

bought in the exchange market or obtainedthrough some other method) at each locationin the grid at any given time reflects the costof making available an additional unit of electric power for purchase at that locationand time. In other words, congestion mayrequire the additional unit of energy to comefrom a more expensive generating unit thanthe one that cannot be accessed due to thesystem congestion. In the absence of transmission congestion, all prices within agiven area and time are the same. However,when congestion is present, the prices atvarious locations typically will not be thesame, and the difference between any two

locational prices represents the cost of transmission system congestion betweenthose locations.

All existing organized markets have auniform price auction or exchange todetermine the price of electric power.Because of this variation in exchange pricesat different locations, a transmissioncustomer is unable to determine beforehandthe price for electric power at any location

because congestion on the grid changesconstantly. To reduce this uncertainty, RTOsmake a financial form of transmission rightsavailable to transmission customers, as wellas other market participants. Generallyknown as financial transmission rights(FTRs), they confer on the holder the right to

receive certain congestion payments.Generally, an FTR allows the holder tocollect the congestion costs paid by any userof the transmission system and collected bythe RTO for electric power delivered over thespecific path. In short, if a transmissioncustomer holds an FTR for the path it takesservice over, it will pay on net either nocongestion charges (if the FTR matches thepath exactly) or less congestion charges (if the FTR partially matches), providing afinancial ‘‘hedge’’ against the uncertainty.

In general, FTRs are now available for one-year terms (or less), and are allocated toentities that pay access charges or fixedtransmission rates. Pursuant to EPACT 05,FERC has begun a rulemaking to ensure the

availability of long-term FTRs.

In regions with RTOs, wholesaleelectricity can be bought and soldthrough the use of negotiated bilateralcontracts, through ‘‘standardcommercial products’’ available in allregions, and through various productsoffered by the organized exchangemarket. For bilateral contracts, thecontract can be individually negotiatedand have terms and conditions uniqueto a single transaction. Standardproducts are available through brokers





116Companies can also limit their exposure toprice swings through financial instruments ratherthan contracts for physical delivery of electricity.Such contracts are essentially a bet between twoparties as to the future price level of a commodity.If the actual price for power at a given time andlocation is higher than a financial contract price,

Party A pays Party B the difference; if the price islower, Party B pays Party A the difference. In fact,in the United States electricity markets, suchagreements are sometimes called ‘‘contracts fordifferences’’. Purely financial contracts involve noobligation to deliver physical power. In this report,

we discuss contracts for physical delivery ratherthan financial contracts, unless otherwise noted.

117Fed. Energy Regulatory Comm’n, Staff Report

to the Fed. Energy Regulatory Comm’ n on the

Causes of Wholesale Electric Pricing Abnormalitiesin the Midwest During June 1998 (1998).

and over-the-counter (OTC) exchangessuch as the NYMEX andIntercontinental Exchange (ICE).116 Standard products have a standard setof specifications so that the main variantis price. Finally, there are organizedexchange markets operated by the RTOs.In addition to offering transmissionservices, these organized exchange

markets offer various productsincluding electric power and ancillaryservices. Electric power marketstypically involve sales of electric powerin both hour-ahead and day-aheadmarkets.

Ancillary services include variouscategories of generation reserves such as

spinning and non-spinning reserves inaddition to Automatic GenerationControl (AGC) for frequency control.The question remains, however,whether the price signals described inChapter 2 have functioned to elicit theconsumption and investment decisionsthat were expected to occur withwholesale market competition? The next

section reviews generation entry indifferent regions.

C. Generation Investment Has Varied by Region Since Competition Increased inWholesale Electric Power Markets

Since the adoption of open accesstransmission and the growth of

competition, the amount of newgeneration investment has variedsignificantly by region. Figure 3–1shows the overall pattern of newinvestment, broken down by region. Asubstantial amount of new investmenthas occurred in the Southeast, Midwest,and Texas. Other regions have notexperienced as much investment.

Wholesale customers obtaintransmission services under differentpricing formats in each region.Moreover, the regions that operateexchange markets for electric power andancillary services use different forms of locational pricing, price mitigation, andcapacity markets.

These regional differences provide

some insight into the impact of differentpolicy choices on the challenge to createmarkets with sufficient supply choicesto support competition and to allocateresources efficiently.

1. Midwest

Wholesale Market Organization: In2004, the Midwest RTO began providingtransmission services to wholesalecustomers in its footprint. On April 1,2005, the MISO commenced itsorganized electric power market

operations. Prior to this time, wholesale

customers obtained transmission undereach utility’s OATT and there were nocentralized electric power exchangemarkets.

New Generation Investment: TheMidwest experienced a wholesale pricespike during the summer of 1998.117 An





118FERC State of the Markets Report 2004 at 109.119FERC State of the Markets Report 2004 at 50.120FERC State of the Markets Report 2005 at 77.121Southern Companies.122See Fitch Ratings, Wholesale Power Market

Update (Mar. 13, 2006), available at http:// www.fitchratings.com/corporate/sectors/special _reports.cfm?sector _ flag=2&marketsector=1&detail=&body _content=spl _rpt.

123FERC State of the Markets Report 2005 at 69;FERC State of the Markets Report 2004 at 41–43.

124California ISO.

125FERC State of the Markets Report 2004 at 109.126FERC State of the Markets Report 2005 at 83.127FERC State of the Markets Report 2004 at 36.128Press Release, ISO New England, ISO New

England Announces Broad Stakeholder Agreementon New Capacity Market Design (Mar. 6, 2006),available at http://www.iso-ne.com/nwsiss/pr/2006/ march _6 _settlement _ filing.pdf.

increase in demand due to unusuallyhot weather combined with unexpectedgeneration outages created a rapid spikein wholesale prices. A significantamount of new generation was built inresponse to the price spike as shown inTable 3–1. For example, from January2002 through June 2003, the Midwestadded 14,471 MW in capacity.118

Most of the new generation was gas-fired, even though the region as a wholerelies primarily on coal-firedgeneration.119 More-recent entry has infact been coal fired, in part because of rising natural gas prices.120 The resultsof this entry and the subsequent drop inwholesale power prices have included:(1) merchant generators in the regiondeclaring bankruptcy and (2) vertically-integrated utilities returning certaingeneration assets from unregulatedwholesale affiliates to rate-base.

2. Southeast

Wholesale Market Organization:Wholesale customers in the regionobtain transmission under each utility’sOATT (e.g., Entergy or SouthernCompanies). There are no centralizedelectric power markets specific to theregion.

New Generation Investment: TheSoutheast’s proximity to natural gassources in the Gulf of Mexico andpipelines to transport that natural gashave made natural gas a popular fuelchoice for those building plants in theregion. The Southeast has seenconsiderable new generationconstruction as shown in Figure 3–1.

More than 23,000 MW of capacity wereadded in the Southern control area

between 2000 and 2005,121 and severalgeneration units owned by merchants orload-serving entities have been built inthe Carolinas in the past few years. Asignificant portion of the newgeneration in the Southeast was non-utility merchant generation. A numberof merchant companies that built plantsin the 1990s have sought bankruptcyprotection. Often, the plants of the

bankrupt companies have beenpurchased by local vertically-integratedutilities and cooperatives, such as

Mirant’s sale of its Wrightsville plant toArkansas Electric CooperativeCorporation and NRG’s sale of itsAudrain plant to Ameren.122 Even apartfrom bankruptcies, some independent

power producers have withdrawn fromthe region.

3. California

Wholesale Market Organization: TheCalifornia ISO began operation in 1998to provide transmission services.Concurrently, a separate PowerExchange (PX) operated electric power

exchanges. Subsequent to the 2000–01energy crisis, the California dissolvedthe PX.

New Generation Investment: Evenprior to the California energy crisis,California was dependent on importedelectric power from neighboring states.Much of the generation capacity forSouthern California was built asubstantial distance away from thepopulation it serves, making the regionheavily-dependent upon transmission.In the past few years, much of thegeneration in California has operatedunder long-term contracts negotiated bythe State during the energy crisis. Since2000–01, demand has increased inCalifornia, but construction of localgeneration has not kept pace. Over 6,000MW of new generation capacity hasentered California in 2002–03, but verylittle of it was built in congested, urbanareas like San Francisco, Los Angelesand San Diego.123 The commentersacknowledged that significant newgeneration has been announced or builtin California in the past few years, butmost of the projects have been inNorthern California.124 In the past fiveyears, transmission investment hasimproved links between Southern and

Northern California and accessiblegeneration investment in the Southwestmore generally has increased.

4. The Northeast

a. New England

Wholesale Market Operation: TheNew England ISO (ISO–NE) providestransmission services as well asoperating a centralized electric powermarket. Under the electric powerpricing mechanism adopted by the NewEngland ISO, the expensive units usedto maintain resource adequacy in somelocal areas are often not eligible to set

the market clearing price because of theISO’s use of must-run reliabilitycontracts. Rather, the cost of these high-priced units is spread across the regionto all users.

New Generation Investment: Much of the generation in New England has been

built in less populated areas of theregion, such as Maine, but much of thedemand for power is in southern New

England. From January 2002 through June 2003, ISO–NE added 4159 MW incapacity.125

Capacity additions in 2004 were lessthan in the two previous years. In 2004,four generation projects came on line.Generation retirements in 2004 totaled343 MW, of which 212 MW aredeactivated reserves.

Demand growth in the organized NewEngland markets has led to ‘‘loadpockets,’’ areas of high populationdensity and high peak demand that lackadequate local supply to meet demandand transmission congestion preventsuse of distant generation units to meetlocal demand. These pockets have notseen entry of generation to meet thatdemand. Transmission has not always

been adequate to bridge this gap. Ingeneral, New England needs newgeneration in the congested areas of Boston and Southwest Connecticut orincreased transmission investment to

reduce congestion.Moreover, the need for more supplyin these load pockets is not reflected inhigh locational prices that would signalinvestment.126 ISO–NE has recognizedthis issue and in 2003, it implementeda temporary measure known as PeakingUnit Safe Harbor (PUSH). PUSH enabledgreater cost recovery for high-cost, low-use units in designated congestionareas, although PUSH units still may not

be able to recover completely all theirfixed costs.127 ISO–NE also seeks toestablish a locational capacity productthat will project the demand three yearsin advance and hold annual auctions to

purchase power resources for theregion’s needs. This proposal is part of a settlement pending before FERC. ISO– NE originally proposed a differentmarket model called LocationalInstalled Capacity (LICAP). That modelwas opposed by a variety of stakeholders.128

b. New York

Wholesale Market Operation: TheNew York ISO (NYISO) providestransmission services as well asoperating a centralized electric powermarket. On the one hand, NYISO uses

price mitigation to guard againstwholesale price spikes but, on the other,it allows high cost generators to beincluded in marginal location prices.

New Generation Investment: NewYork has traditionally built generation





129FERC State of the Markets Report 2004 at 109.130FERC State of the Markets Report 2005 at 97.131FERC State of the Markets Report 2004 at 39.132 Intial Order on Reliability Pricing Model, 115

FERC ¶61,079, *3 (2006).133FERC State of the Markets Report 2004 at 109.134FERC State of the Markets Report 2005 at 112.135 Id. at 188.

136American Electric Power proposes to build anew 765-kilovolt (kV) transmission line stretchingfrom West Virginia to New Jersey, with a projectedin-service date of 2014. AEP Interstate ProjectSummary, available at http://www.aep.com/ newsroom/resources/docs/AEP _InterstateProjectSummary.pdf. Allegheny Power proposes toconstruct a new 500 kV transmission line, with atargeted completion date of 2011, which will extend

from southwestern Pennsylvania to existingsubstations in West Virginia and Virginia andcontinue east to Dominion Virginia Power’sLoudoun Substation. Allegheny PowerTransmission Expansion Proposal, available at http://www.alleghenypower.com/TrAIL/TrAIL.asp.More recently, Pepco has proposed to build a 500-kv transmission line from Northern Virginia, acrossthe Delmarva Penninsula and into New Jersey.

in less populated areas and moved it tomore populated areas. For example, theNew York Power Authority wasresponsible for getting hydroelectricpower from the Niagara Falls area intomore congested areas of the state. From

January 2002 through June 2003, NYISOadded 316 MW in capacity.129 Threegenerating plants with a total summer

capacity of 1,258 MW came on line in2004. Three plants totaling 170 MWretired in 2004.130

Transmission constraints are thereforea concern, and currently, transmissionconstraints in and around New YorkCity limit competition in the city andlead to more use of expensive localgeneration, thereby raising prices.NYISO uses price mitigation that seeks

to avoid mitigating high prices that arethe result of genuine scarcity, thoughNYISO has separate mitigation rules forNew York City. In an effort to lessendistortion of market signals, NYISOincludes the cost of running generatorsto serve load pockets in its calculationof locational prices. Thus, potentialentrants get a more accurate price signal

regarding investment in the load pocket.In a further effort to spur new

capacity construction, NYISO also sets amore generous ‘‘reference price’’ fornew generators in their first three yearsof operation.131 (Bids above thereference prices may trigger pricemitigation.) Unlike New England, NewYork is seeing new generationinvestment in a congested area.

Approximately 1,000 MW of newcapacity is planned to enter intocommercial operation in the New YorkCity area in 2006. The fact that NewYork is better able than New England tomatch locational need with investmentis likely due to clearer market pricesignals in New York, both in energymarkets and capacity markets.

The effect of load pockets on pricesare shown in Figure 3–2, whichestimates the annual value of capacity

based on weighted average results of three types of auctions run by theNYISO. Capacity prices are higher in thetighter supply areas of NYC and LongIsland.

c. PJM

Wholesale Market Operation: The PJMInterconnection provides transmissionservices as well as operating acentralized electric power market. PJMhas both energy and capacity markets.PJM’s energy market has locationalprices. FERC recently approved theconcept of PJM’s proposal to shift tolocational prices in its capacitymarkets.132 The locational capacitymarket has not yet been implemented.

New Generation Investment: PJMcapacity includes a broad mix of fueltypes. Recent PJM expansion has addedsignificant low-cost coal resources toPJM’s overall generation mix. From

January 2002 through June 2003, PJMadded 7458 MW in capacity.133 Capacity additions in 2004 were lowerthan in the two previous years. In 2004,4,202 MW of new generation wascompleted in PJM. During the year, 78MW of generation was mothballed and2,742 MW was retired.134

Like other areas, PJM depends ontransmission to move power from theareas of low-cost generation to the areasof high demand. In PJM, the flow isgenerally from the western part of PJM,

an area with significant low-cost coal-fired generation, to eastern PJM. Theeasternmost part of PJM is limited by aset of transmission lines known as theEastern Interface, which at times limits

the deliverability of generation from thewest. This means that higher-costgeneration must be run in the easternregion to meet local demand. Within theeastern region, there are also areas of still-more-limited transmission. As aresult of these kinds of transmissionlimitations, generation in some areasthat is not economical to run is beinggiven reliability must-run (RMR)contracts to prevent it from retiring andpossibly reducing local reliability.135

Recently, three utilities in PJM haveproposed major transmissionexpansions to increase capacity formoving power from into eastern parts of PJM.136





137ERCOT Response to the DOE QuestionRegarding the Energy Policy Act 2005, available at http://www.oe.energy.gov/document/ercot2.pdf.

138Ross Baldick and Hui Niu, Lessons Learned:The Texas Experience, available at http:// www.ece.utexas.edu/baldick/papers/lessons.pdf.

139U.S. Gen. Accounting Office, GAO–02–427,Restructured Electricity Markets, Three States’ Experiences in Adding Generating Capacity 9(2002).

140 Id. at 19.141For a complete discussion of generation

characteristics of the Northwest, see Nw. Power &Conn. Council, The Fifth Northwest Power andConservation Plan, Ch. 2 (2005), available at http:// www.nwcouncil.org/energy/powerplan/plan/ Default.htm.

142ELCON; NRECA; APPA.143E.g., PJM; EPSA.144ELCON.

5. Texas

Wholesale Market Operation: TheElectric Reliability Council of Texas(ERCOT) manages the scheduling of power on an electric grid consisting of about 77,000 megawatts of generationcapacity and 38,000 miles of transmission lines. ERCOT also managesfinancial settlement for marketparticipants in Texas’s deregulatedwholesale bulk power and retail electricmarket. ERCOT is regulated by thePublic Utility Commission of Texas.ERCOT is generally not subject to FERCjurisdiction because it does notintegrated with other electric systems,i.e., there is not interstate electrictransmission. ERCOT is the only marketin which regulatory oversight of thewholesale and retail markets isperformed by the same governmentalentity.

In ERCOT, for each year, ERCOTdetermines a set of transmission

constraints within its system which itdeems Commercially SignificantConstraints (CSCs). These constraintscreate Congestion Zones for which zonal‘‘shift factors’’ are determined. Onceapproved by the ERCOT Board, theCSCs and Congestion Zones are used bythe ERCOT dispatch process for the nextyear. In 2005, ERCOT has six CSCs andfive Congestion Zones. When the CSCs

bind, ERCOT economically dispatchesgeneration units bid against load withineach zone. To keep the system in

balance in real time, ERCOT issues unit-specific instructions to manage Local

(intrazonal) Congestion, then clears thezonal Balancing Energy Market. The balancing energy bids from all thegenerators are cleared in order of lowestto highest bid.137

At least one study argues that whenthere is local congestion, local marketpower is mitigated in ERCOT by ad hocprocedures that are aimed at keepingprices relatively low while maintainingtransmission flows within limits. As aresult, prices may be too low when thereis local scarcity. In particular, pricesmay not be high enough to attractefficient new investment to provide

long-term solutions to local marketpower problems. It is difficult for newentrants to contest such local markets,so that the local monopoly positions areessentially entrenched.138

New Generation Investment: In thelate 1990s, developers added more than16,000 megawatts of new capacity to the

Texas market.139 Certain aspects of theTexas market may make it attractive tonew investment. Texas consumersdirectly pay (via their electricity bills)for updates to the transmission systemrequired by the addition of new plants.In other states, FERC often requiresdevelopers to pay for system upgradesupfront and recoup the cost over time

through credits against theirtransmission rates.140

6. The Northwest

Wholesale Market Organization:Wholesale customers obtaintransmission service throughagreements executed pursuant toindividual utility OATTs. There are nocentralized exchange markets specific tothe region, but there is an active

bilateral market for short-term saleswithin the Northwest and to theSouthwest and California. Severaltrading hubs with significant levels of liquidity also are sources of priceinformation. Multiple attempts toestablish a centralized Northwesttransmission operator have provenunsuccessful for a variety of reasons,including difficulties in applyingstandard restructuring ideas to a systemdominated by cascading (i.e.,interdependent nodes) hydroelectricgeneration and difficulties inunderstanding the potential cost shiftsthat might result in restructuringcontract-based transmission rights.

New Generation Investment: TheNorthwest’s generation portfolio isdominated by hydroelectric generation,

which comprises roughly half of allgeneration resources in the region on anenergy basis.141 The remaininggeneration derives primarily from coaland natural gas resources, (with smallercontributions from wind, nuclear andother resources). The hydroelectricshare of generation has decreasedsteadily since the 1960s.

The Northwest’s hydroelectric baseallows the region to meet almost anycapacity demands required of theregion— but the region is susceptible toenergy limitations (given the finiteamount of water available to flowthrough dams). This ability to meet peakdemand buffers incentives for buildingnew generation, which might be neededto assure sufficient energy supplies

during times of drought because in threeyears out of four, hydro generation candisplace much of the existing thermalgeneration in the Northwest. There has,however, been generation addition inthe past years to meet load growth andto attempt to capitalize on high-pricesduring the Western energy crisis of 2001–02. Due to high power purchase

costs during this crisis, some utilitieshave added thermal resources asinsurance against drought-inducedenergy shortages and high prices.Altogether, over 3800 MWs of newgeneration has been added to theNorthwest Power Pool since 1995—75%of that was commissioned in 2001 orlater.

D. Factors That Affect Investment Decisions in Wholesale Electric Power Markets

The Task Force examined commentson how competition policy choices have

affected the investment decisions of both buyers and sellers in wholesalemarkets. A number of issues emergedincluding the difficulty of raising capitalto build facilities that have revenuestreams that are affected by changingfuel prices, demand fluctuations andregulatory intervention and a perceivedlack of long term contracting options.Some comments to the Task Force assertthat significant problems still exist inthese markets, particularly steep priceincreases in some locations without themoderating effect of long-termcontracting and new construction.142 Insome markets, the problem is that prices

are so low as to discourage entry by newsuppliers, despite growing need.143 Experience over the last 10 years showsthree different regional competitionmodels emerging. Each has its own setof benefits and drawbacks.

1. Long-Term Purchase Contracts— Wholesale Buyer Issues

Many wholesale buyers suggested thatthey had sought to enter into long-termcontracts but found few or no offers.144 The Task Force attempted to determinewhether the facts supported theseallegations by examining 2004–05 data

collected by FERC through its ElectricQuarterly Reports for three regions— New York, the Midwest, and theSoutheast. Appendix E contains thisanalysis. Although not conclusive

because of data limitations described inAppendix E, the analysis showed thatcontracts of less than one-yeardominated each of the three regionalmarkets examined and that in two of the





145 In competitive markets, customers also havethe ability to build their own generation facility if they are unable to obtain the long-term purchasecontracts that they seek.

146APPA, NRECA.147See, e.g., Public Advocate’s Office of Maine,

National Association of State Utility ConsumerAdvocates.

148 Inquiry Concerning Alternative Power PoolingInstitutions Under the Federal Power Act, DocketNo. RM94–20–000.

149

Comments of the U.S. Department of Justice,Inquiry Concerning Alternative Power PoolingInstitutions Under the Federal Power Act, DocketNo. RM94–20–00 filed March 2, 1995 at p. 6. Seealso Reply Comments of the U.S. Department of Justice, Inquiry Concerning Alternative PowerPooling Institutions Under the Federal Power Act,Docket No. RM94–20–00 filed April 3, 1995.

150See Comment of the Federal TradeCommission. Docket No. RM–04–7–000 (Jul. 16,2004) at 7–8, available at http://www.ftc.gov/os/ comments/ferc/v040021.pdf .

151APPA, Carnegie Mellon.152Nodir Adilov, Forward Markets, Market

Power, and Capacity Investment (Cornell Univ.Dep’t of Econ. Job Mkt. Papers, 2005), available at http://www.arts.cornell.edu/econ/na47/JMP.pdf .

153APPA, TAPS.154Pub. L. 109–58, §1233, 119 Stat. 594, 958

(2005) (emphasis added).155Constellation, Mirant.

markets, longer contract terms areassociated with lower contract prices ona per MWh basis.

Three reasons may exist to explain theperceived lack of ability to enter long-term purchase power contracts.145 First,some comments argued that organizedexchange markets based on uniformprice auctions (e.g., PJM and NYISO)

have made it difficult to arrangecontracts with base-load and mid-meritgenerators at prices near theirproduction costs.146 These generatorswould rather sell in the exchangemarkets and obtain the market-clearingprice, which may be higher than theirproduction costs at various times. Base-load and mid-merit generators may seerelatively high profits when gas-fueledgenerators are the marginal units,particularly when natural gas pricesrise. Box 3–2 describes how prices areset in organized exchange markets.Natural gas-fueled generators in a

uniform price auction may see lowerprofits as their fuel costs rise, to theextent other generation becomesrelatively more economical.147 Statedanother way, when natural gas units setthe market price, these units mayrecover only a small margin over theiroperating costs, while nuclear and coalunits recover larger margins. Undertraditional regulation, by contrast, all of an owner’s generation units generallyare allowed the same return, which may

be less than marginal units, and morethan infra-marginal units, incompetitive markets.

In addition, the very competitivenessof these markets cannot be assumed. Forexample, over ten years ago, FERCrequested comments on a wholesale‘‘PoolCo’’ proposal, which was thepredecessor entity to today’s organizedelectricity market with opentransmission access.148 At the time, theDepartment of Justice generallysupported the emerging market form butwarned: ‘‘The existence of a PoolCocannot guarantee competitive pricing,since there may be only a small numberof significant sellers into or buyers fromthe pool. The Commission should notapprove a PoolCo unless it finds that thelevel of competition in the relevantgeographic markets would be sufficientto reasonably assure that the benefits of

eliminating traditional rate regulationexceed the costs.’’ 149

The fact that the market-clearing pricein organized exchange markets may beestablished by a subset of generatorsdepending upon demand andtransmission congestion heightens thecompetitiveness concern in theorganized markets. At one end,

generators with high costs do not havemuch impact on the market prices whenthere is low demand and lowtransmission congestion, andconversely, generators with low costs donot have much impact on the market-clearing prices when there is highdemand and high transmissioncongestion. There is a wide-range of market-clearing prices between thesetwo end points based on the diversity of generator costs available in eachregion.150 Indeed, some commentersspecifically cited to recent studies of theelectric industry that argue that a larger

number of suppliers are needed tosustain competitive pricing in electricitymarkets than are needed for effectivecompetition in other commodities.151

Second, the perceived lack of long-term purchase contracts may be due toa lack of trading opportunities to hedgethese long-term commitments. Long-term contracts in other commodities areoften priced with reference to a‘‘forward price curve.’’ A forward pricecurve graphs the price of contracts withdifferent maturities. The forward pricesgraphed are instruments that can beused to hedge (or limit) the risk thatmarket prices at the time of delivery

may differ from the price in a long-termcontract. In a market with liquidforward or futures contracts, parties toa long-term contract can buy or sellproducts of various types and durationsto limit their risk due to such pricedifferences. Currently, liquid electricityforward or futures markets often do notextend beyond two to three years.152 Insome markets, one-year contracts are thelongest products generally available; inmarkets where retail load is beingserved by contracts of fixed durations,such as the three-year obligations in

New Jersey and Maryland, contracts forthe duration of that period are slowlygrowing in number. But the relative lackof liquidity may discourage parties fromsigning long-term contracts, becausethey lack the ability to ‘‘hedge’’ theselonger-term obligations.

Third, the availability of long-termpurchase contracts depends on the

availability and certainty of long-termdelivery options. Particularly inorganized markets, transmissioncustomers have argued that the inabilityto secure firm transmission rights formultiple years at a known priceintroduces an unacceptable degree of uncertainty into resource planning,investment and contracting.153 Theyreport that this financial uncertainty hashurt their ability to obtain financing fornew generation projects, especially new

base-load generation.Congress addressed this issue of

insufficient long-term contracting in thecontext of RTOs and ISOs in EPACT05.In particular, section 1233 of EPACT05provides that:

[FERC] shall exercise the authority of theCommission under this Act in a manner thatfacilitates the planning and expansion of transmission facilities to meet the reasonableneeds of load-serving entities to satisfy theservice obligations of the load-servingentities, and enables load-serving entities tosecure firm transmission rights (or equivalent tradable or financial rights) on a long-termbasis for long-term power supply arrangements made, or planned, to meet such needs.154

To implement this provision in RTOsand ISOs, FERC proposed new rulesregarding FTRs in February 2006. Therules would require RTOs and ISOs tooffer long-term firm transmission rights.FERC did not specify a particular typeof long-term firm transmission right, butinstead proposed to establish guidelinesfor the design and administration of these rights. The proposed guidelinescover basic design and availabilityissues, including the length of terms therights should have and the allocation of those rights to transmission customers.FERC has received comments on itsproposal but has not yet adopted finalrules.

2. Long-Term Supply Contracts— Generation Investment Issues

Commenters cited the certainty of long-term contracts as a criticalrequirement for obtaining financing fornew generators.155 These contracts,however, are vulnerable to certainregulatory risks. First, contracts are





156 In December 2005, FERC proposed to adopt ageneral rule on the standard of review that must bemet to justify proposed modifications to contractsunder the Federal Power Act and the Natural GasAct. Standard of Review for Modifications to Filed Agreements, 113 FERC ¶61,317 (2005) (ProposedRule). Specifically, FERC proposed that, in theabsence of specified contractual language, a partyseeking to change a contract must show that thechange is necessary to protect the public interest.FERC explained that its proposal recognized theimportance of providing certainty and stability inenergy markets, and helped promote the sanctity of contracts. A final rule is pending.

157Nevada Power Company v. Enron, 103 FERC¶61,353, order on reh’ g , 105 FERC ¶61,185 (2003);Public Utilities Commission of California v. Sellersof Long Term Contracts, 103 FERC ¶61,354, order on reh’ g , 105 FERC ¶61,182 (2003); PacifiCorp v.Reliant Energy Services, Inc., 103 FERC ¶61,355,order on reh’ g , 105 FERC ¶61,184 (2003).

158See Northeast Utilities Service Co., v. FERC ,55 F.3d 686, 689 (1st Cir. 1995).

159See Howard L. Siegel, The Bankruptcy Court vs. Ferc—The Jurisdictional Battle, 144 Pub. Util.Fortnightly 34 (2006).

160At least one rating agency treats a utility’s self- built generation as an asset while treating long-termpurchase contracts as imputed debt, thus making itless attractive for utilities to choose the contractoption.

161See infra Chapter 4 for a discussion of regulated service offerings in states with retailcompetition.

162Mirant, Constellation.163Cong. Budget Office, Financial Condition of

the U.S. Electric Utility Industry (1986), availableat http://www.cbo.gov/ showdoc.cfm?index=5964&sequence=0.

164Southern, Duke.165Commodity Futures Trading Comm’n, The

Economic Purpose of Futures Markets, available at http://www.cftc.gov/opa/brochures/ opaeconpurp.htm.

166APPA.167Task Force Meetings with Credit Agencies, see

Appendix B.168U.S. Gen. Accounting Office, GAO–02–427,

Restructured Electricity Markets, Three States’ Experiences in Adding Generating Capacity 13(2002).

169Connecticut DPUC.

subject to regulation by FERC, and aparty to a contract can ask FERC tochange contract prices and terms, evenif the specific contract has beenapproved previously.156 For example, in2001–2002 several wholesale purchasersof electric power requested that FERCmodify certain contracts entered intoduring the California energy crisis. The

customers alleged that problems in theCalifornia electricity exchange marketshad caused their contracts to beunreasonable. The sellers argued that if FERC overrides valid contracts, marketparticipants will not be able to rely oncontracts when transacting for powerand managing price risk. FERC declinedto change the contracts.157 FERC citedits obligation to respect contracts exceptwhen other action is necessary toprotect the public interest.158

A second type of regulatoryuncertainty involving bankruptcy maylimit future market opportunities for

merchant generators and, thus, reducetheir ability to raise capital. In recentyears, several merchant generators(NRG, Mirant and Calpine) have soughtto use the bankruptcy process to breaklong-term power contracts.159 Theseefforts, when successful, leavecounterparties facing circumstances thatthey did not anticipate when theyentered into their contracts. This riskmay give state regulators an incentive tofavor construction of generation by theirregulated utilities over wholesalepurchases from merchant generators.These disputes have spawned

conflicting rulings in the courts. Inparticular, these cases have centered onseparate, but intertwined, issues: first,where jurisdiction over efforts to endpower contracts properly lies, as

between FERC and the bankruptcycourts and to what extent courts may

enjoin FERC from acting to enforcepower contracts; and second, whatstandard applies to such efforts (that is,what showing must a party make to riditself of a contract). As FERC and thecourts have only recently begun toconsider these questions, the lawremains unsettled, as do parties’ expectations.160

A third type of regulatory uncertaintyconcerns the regulated retail serviceofferings in states with retailcompetition.161 The uncertainty of howmuch supply a distribution utility willneed to satisfy its customers due tocustomer switching that can occur inretail markets can prevent or discouragethose utilities from signing long-termcontracts.162 The extent of thisdisincentive is unclear if competitiveoptions are available for distributionutilities to purchase needed supply orsell excess supply.

3. Risk and Reward in the Face of Price

and Cost Volatility—CapitalRequirements

Building new generation in wholesalemarkets also is based on the ability of a company to acquire capital, eitherfrom internal sources or external capitalmarkets. If a company can acquire thenecessary capital it can build. There isno Federal regulation of entry, and moststates that have permitted retailcompetition have eliminated any ‘‘need-

based’’ showing to build a generationplant.

Private capital has generally fundedthe electric power transmission network

in the United States. Under traditionalcost-base rate regulation, utilityinvestment decisions were based in parton the promise of a regulated revenuestream with little associated risk to theutility. The ratepayers often bore therisk. Money from the capital marketswas generally available when utilitiesneeded to fund new infrastructure. Onesignificant problem, however, was thatregulators had limited ability to ensurethat utilities spent their moneywisely.163 Regulatory disallowances of imprudent expenditures are viewed byinvestors as regulatory risk. This risk

can be mitigated somewhat byIntegrated Resource Planning, to the

extent it limits or avoids after-the-factregulatory reviews of investmentdecisions.164

In competitive markets, projectsobtain funding based on anticipatedmarket-based projections of costs,revenues and relevant risks factors. Theability to obtain funding is impacted bythe degree to which these projections

compare with projected risks andreturns for other investmentopportunities.165 Therefore, potentialentrants to generation markets have to

be able to convince the capital marketsthat new generation is a viableprofitable undertaking. In the late 1990sinvestors appeared to prefer marketinvestments over cost-based rate-regulated investments, as merchantgenerators were able to financenumerous generation projects, evenwithout a contractual commitment froma customer to buy the power.166

In recent years, however, investorshave generally favored traditionalutilities over merchant generators whenit comes to providing capital for largeinvestments.167 In part, this preferencereflects the reduced profitability of many merchant generators in recentyears, and the relative financial strengthof many traditional utilities. It also mayreflect a disproportionate impact of thecollapse of credit and thus tradingcapability of non-utilities after Enron’sfinancial collapse.168 As shown in theTable in Appendix G, for example,virtually all of the companies rated A-or higher are traditional utilities, notmerchant generators.

Investor preference for traditionalutilities also may be affected byincreasing volatility in electric powermarkets. As wholesale markets haveopened to competition, investorsrecognized that income streams from thenewly-built plants would not be aspredictable as they had been in thepast.169 Under cost-based regulation,vertically integrated utilities’ monopolyfranchise service territories significantlylimited the risk that they would notrecover the costs of investments. Oncegenerators had to compete for sales,generation plant investors were no

longer guaranteed that constructioncosts would be repaid or that the output





170U.S. Gen. Accounting Office, GAO–02–427,Restructurd Electricity Markets, Three States’ Experiences in Adding Generating Capacity 13(2002).

171Energy Info. Admin., DOE/EIA–0562(96), TheChanging Structure of the Electric Power Industry:An Update 38 (1996).

172 Id .173Hearing on Nuclear Power, Before the

Subcomm. on Energy of the S. Comm. on Energy& Nat’l Res., Mar. 4, 2004 (statement of Mr. JamesAsselstine, Managing Director, Lehman Brothers);see also Nuclear Energy Institute, InvestmentStimulus for New Nuclear Power PlantConstruction: Frequently Asked Questions,available at http://www.nei.org/documents/ New _Plant _Investment _Stimulus.pdf .

174Natural Gas, Factors Affecting Prices andPotential Impacts on Consumers, Testimony Beforethe Permanent Subcommittee on Investigations,Committee on Homeland Security andGovernmental Affairs, United States Senate; GA)– 06–420T (February 13, 2006) at 7.

175Occasionally in the past few years netrevenues have been sufficient to cover the costs of new peaking units, and in 2005 they were enoughto cover the costs of a new coal plant. MarketMonitoring Unit, PJM Interconnection, LLC, 2005State of the Market Report, at 118 (2006)[hereinafter PJM State of the Market Report 2005],available at http://www.pjm.com/markets/market-monitor/som.html .

176 Intial Order on Reliability Pricing Model, 115FERC ¶61,079, *3 (2006)

from plants could be sold at a profit.170 Financing was more readily accessed forprojects like combined cycle gas andparticularly gas turbines that can be

built relatively quickly and were viewedat the time to have a cost advantagecompared with existing generationalready in operation, including lessefficient gas-fueled generators.171 In

1996, the Energy InformationAdministration projected that 80% of electric generators between 1995 and2015 would be combined cycle orcombustion turbines.172 Base-load units,such as coal plants, with constructionand payout periods that would putcapital at risk for a much longer periodof time, were harder to finance.173

Box 3–3: The Use of Capacity Credits inOrganized Wholesale Markets

In theory, capacity credits could supportnew investment because suppliers and theirinvestors would be assured a certain level of return even on a marginal plant that ran onlyin times of high demand. Capacity creditsmight allow merchant plants to besufficiently profitable to survive even incompetition with the generation of formerly-integrated local utilities that may havealready recovered their fixed costs.

The increasing amount of newgeneration fueled by natural gas,however, has caused electricity prices tovary more frequently with natural gasprices, a commodity subject to wideswings in price.174 With input costsvarying widely, but merchant revenuesoften limited by contract or byregulatory price mitigation, investors

may worry that merchant generatorsmay not recover their costs and providean attractive rate of return.

4. Regulatory Intervention May AffectInvestment Returns

Generation investors must expect torecover not only their variable costs butalso an adequate return on their

investment to maintain long-termfinancial viability. One way forsuppliers to recover their investment isto charge high prices during periods of high demand. However, regulators maylimit recovery of high prices duringthese periods, and thus may detersuppliers from making neededinvestments in new capacity that would

be economical absent these price caps.This dynamic leads to a chicken-and-

egg conundrum: If there were efficientinvestment, there might not be a needfor wholesale price or bid caps. Moreinvestment in capacity would lead toless scarcity, and thus fewer or shorterepisodes of high prices that may requiremitigation. By contrast, it may be thatprice regulation during high-pricedhours diminishes the confidence of investors that they can rely on marketforces (rather than regulation) to setprices. That diminished confidence intheir ability to earn sufficient

investment returns thus deters entry of new generation supply.

Price mitigation through the use of price or bid caps has become an integralcomponent of most organized markets.The use of mitigation has led generatorsto seek a supplemental revenue stream(capacity credits) to encourage entry of new supply. See Box 3–3 for adiscussion of capacity credits.

In practice, however, the presence orabsence of capacity credits has notalways resulted in the predictedoutcomes. California did not havecapacity credits and did not experience

much new generation, but two of theregions (the Southeast and Midwest)experienced significant new generationentry without capacity credits.Northeast RTOs with capacity creditscontinue to have some difficultyattracting entry, especially in majormetropolitan areas.

As noted above, much of the newgeneration in the Southeast was non-utility merchant generation, and reliedon the region’s proximity to natural gassupplies. In the Midwest, in the late1990s, largely uncapped prices wereallowed to send price signals for

investment. In California, price caps of various kinds have been used for anumber of years, limiting price signalsfor new entry. In the Northeast,organized markets have offered capacitypayments for long term investments inaddition to electric power prices that aresometimes capped in the short term.Unfortunately, there is no conclusiveresult from any of these approaches—noone model appears to be the perfectsolution to the problem of how to spurefficient investment with acceptablelevels of price volatility.

Net revenue analyses for thecentralized markets with pricemitigation suggest that price levels areinadequate for new generation projectsto recover their full costs. For example,in the last several years, net revenues inthe PJM markets have been, for the mostpart, too low to cover the full costs of new generation in the region.175 Based

on 2004 data, net revenues in NewEngland, PJM and California wouldhave allowed a new combined-cycleplant to recover no more than 70% of its fixed costs.

Regulation also may interfere withefficient exit of generation plants due tothe use of reliability-must-runrequirements. In some load pockets inorganized markets, plant owners arepaid above-market prices to run plantsthat are no longer economical at themarket-clearing price. For example, inits Reliability Pricing Model filing withFERC, PJM states, ‘‘PJM also has been

forced to invoke its recently approvedgeneration retirement rules to retain inservice units needed for reliability thathad announced their retirement. As theCommission often has held, this is atemporary and sub-optimal solution.Such compensation, like the reliabilitymust run (‘‘RMR’’) contracts allowedelsewhere, is outside the market, andpermits no competition from, and sendsno price signals to, other prospectivesolutions (such as new generation ordemand resources) that might be morecost-effective.’’ 176 To the extent thatmarket rules allocate the cost of keepingthese plants running to customers

outside of the load pocket, suchpayments may distort price signals that,in the long run, could elicit entry.Graduated capacity payments that favornew entry of efficient plants may be apartial solution to retirement of inefficient old plants.

5. Investment in Transmission: ANecessary Adjunct to Generation Entry

Transmission access can be vital tothe competitive options available tomarket participants. For example,merchant generators depend on theavailability of transmission to sell

power, and transmission constraints canlimit their range of potential customers.Small utilities, such as many municipaland cooperative utilities, depend on the





177Par Holmberg, Comparing Supply FunctionEquilibria of Pay-as-Bid and Uniform PriceAuctions (Uppsala University, Sweden WorkingPaper 2005:17, 2005); G. Federico & D. Rahman,Bidding in an Electricity Pay-As-Bid Auction(Nuffield College Discussion Paper No 2001–W5,2001); Joskow, Difficult Transition at 6–7.

178Alfred E. Kahn, et al., Uniform Pricing or Pay-as-Bid Pricing: A Dilemma for California and Beyond (Blue Ribbon Panel Report, studycommissioned by the California Power Exchange,2001).

availability of transmission to buywholesale power, and transmissionconstraints can limit their range of potential suppliers. Much of thetransmission grid is owned byvertically-integrated, investor-ownedutilities and, traditionally, these utilitieshave an incentive to limit the use byothers of the grid, to the extent such use

conflicts with sales by their owngeneration. In short, the availability of transmission is often the keystone indetermining whether a generatingfacility is likely to be profitable and,thus, to elicit investment in the firstinstance.

Since FERC issued Order No. 888 in1996, questions have arisen concerningthe efficacy of various terms andconditions governing the availability of transmission. For example, transmissioncustomers have raised concernsregarding the calculation of AvailableTransfer Capacity (ATC). Another area

of concern is the lack of coordinatedtransmission planning betweentransmission providers and theircustomers. Finally, customers haveraised concerns about aspects of transmission pricing. Based on theseconcerns, FERC in May 2006 proposedmodifications to public utility tariffs toprevent undue discrimination in theprovision of transmission services.FERC is soliciting public comments onits proposed modifications.

As discussed above, generation that is built where fuel supplies are readilyavailable, but not necessarily neardemand, and construction costs are low,

rely heavily on readily availabletransmission. The Connecticut DPUCnoted that while generation growth mayhave been sufficient for some regionssuch as New England as a whole, somelocalized areas had demand growthwithout increases in supply, raisingprices in load pockets. If transmissionaccess to the load pocket were available,a large base-load plant outside the loadpocket might become an attractiveinvestment proposition.

Less regulatory intervention inwholesale markets for generation may

be necessary if transmission upgrades,

rather than unrestricted high prices orcapacity credits, are used to address theconcerns about future generationadequacy. Although capacity creditsmay spur generators within a loadpocket to add additional capacity,capacity credits may not be required for

base-load plants outside the loadpocket. Those base-load plants wouldnot have the problem of averagerevenues falling below average costs

because they would have access to moreload, and be able to run profitablyduring more hours of the day. Similarly,

price caps may be unnecessary if improved transmission brought powerfrom more base-load units into thecongested areas. Prices would be lower

because there would be less scarcity,and high cost units would be needed torun during fewer hours.

E. Observations on Wholesale Market

CompetitionOne of the most contentious issues

currently facing federal regulators iswhether the different forms of competition in wholesale markets haveresulted in an efficient allocation of resources. The various approaches used

by the different regions show the rangeof available options.

1. Open Access Transmission withoutan Organized Exchange Market

One option is to rely upon the OATTto make generation options available towholesale customers. No centralexchange market for electric poweroperates in regions taking this option(the Northwest and Southeast) Instead,wholesale customers shop foralternatives through bilateral contractswith suppliers and separately arrangefor transmission via the OATT. With arange of supply options to choose from,long-term bilateral contracts for physicalsupply can provide price stability thatwholesale customers seek and a roughprice signal to determine whether to

build new generation or buy generationin wholesale markets. However, pricesand terms can be unique to eachtransaction and may not be publicly

available. Furthermore, the lack of centralized information about tradesleaves transmission operators withsystem security risks that necessitateconstrained transmission capacity. Thelack of price transparency can also addto the difficulty of pricing long-termcontracts in these markets.

This model is extremely dependenton the availability of transmissioncapacity that is sufficient to allow

buyers and sellers to connect. Thus, italso is dependent upon the accuratecalculation and reporting of transmission capacity available to

market participants. Short-termavailability is not sufficient, even if accurately reported, to form a basis forlong term decisions such as contractingfor supply or building new generation.Not only must transmission beavailable, but it must be seen to beavailable on a nondiscriminatory basis.As the FERC noted in Order 2000,persistent allegations of discriminationcan discourage investment even if theyare not proven. Without the assurance of long term transmission rights, wholesalecustomers may remain dependent on

local generation owned by one or onlya few sellers and be denied thecompetitive options supplied by moredistant generation. Similarly, newsuppliers may have no means of competing with incumbent generatorslocated close to traditional load.

2. Policy Options in Organized

Wholesale MarketsIn organized markets, market

participants have access to an exchangemarket where prices for electric powerare set in reference to supply offers bygenerators and demand by wholesalecustomers (including Load ServingEntities or LSEs). Such an exchangemarket could have prices set by anumber of mechanisms. All existingU.S. exchange markets have a uniformprice auction to determine the price of electric power. Uniform price auctionstheoretically provide suppliers anincentive to bid their marginal costs, tomaximize their chance of gettingdispatched. The principal alternative touniform price auctions is a pay-as-bidmarket.

The academic research on whetherpay-as-bid auctions can actually resultin lower prices has been evolving, andthe results are at best mixed.Theoretically, pay-as-bid auctions donot result in lower market-clearingprices and may even raise prices, assuppliers base their bids on forecasts of market-clearing prices instead of theirmarginal costs. More recent researchsuggests that pay-as-bid can sometimesresult in lower costs for customers.177

But, the pay-as-bid approach mayreduce dispatch efficiency, to the extentgenerator bids deviate from theirmarginal costs.178

A uniform price auction may allowsome generators (e.g., coal- or nuclear-fueled units) to earn a return abovethose typically allowed under cost-

based regulation, but it also may limitthe return of other generators (e.g.,natural gas-fueled units) to a return

below those typically allowed undercost-based regulation. In a competitivemarket, a unit’s profitability in auniform price auction will depend on

whether, and by how much, itsproduction costs are below the marketclearing price. A uniform price auction





179See generally Edison Mission Energy, Inc. v.FERC , 394 F.3d 964 (DC Cir. 2005).

180Robert J. Michaels and Jerry Ellig, Price SpikeRedux: A Market Emerged, Remarkably Rational ,137 Pub. Util. Fortnightly 40 (1999). Wholesalecustomers with supply contracts for which theprices were tied to the market price paid higherprices for electric power during those hours.

181Siting in these areas can be difficult orimpossible as a result of land prices, environmentalrestrictions, aesthetic considerations, and otherfactors.

may thus produce prices that are veryhigh compared with the costs of somegenerators and yet not high enough togive investors an incentive to build newgeneration that could moderate pricesgoing forward. The uniform priceauction creates strong incentives forentry by low-cost generators that will beable to displace high cost generators in

the merit dispatch order. Three policyoptions have been suggested to addressthe tension between market-clearingprices with uniform auction and entry.

a. Unmitigated Exchange Market Pricing

One possible, but controversial, wayto spur entry is to let wholesale marketprices rise. As discussed in Chapter 2,the market will likely respond in twoways. First, the resulting price spikeswill attract capital and investment. Toassure that the price signals elicitappropriate investment andconsumption decisions, they must

reflect the differences in prices of electricity available to serve particularlocations. Where transmission capacitylimits the availability of electric powerfrom some generators within a regionalmarket, the cost of supplying customerswithin the region may vary. Withoutlocational prices, investors may notmake wise choices about where toinvest in new generation.

Unfortunately, it is difficult todistinguish high prices due to theexercise of market power from those dueto genuine scarcity. High prices due toscarcity are consistent with theexistence of a competitive market, and

therefore perhaps suggest less need forregulatory intervention. High pricesstemming from the exercise of marketpower in the form of withholdingcapacity may justify regulatoryintervention. Being able to distinguish

between the two situations is thereforeimportant in markets with market-basedpricing.179

Second, higher prices will likelysignal to customers that they shouldchange their decisions about how muchand when to consume. Price increasessignal to customers to reduce theamount they consume. Indeed, during

the Midwest wholesale price spikes inthe summer of 1998, demand fell duringthe period in which prices rose andcustomers purchased little supplyduring those periods.180 For an efficientreduction in consumption to occur,

however, retail customers must have theability to react to accurate price signals.As discussed in Chapter 4, customersoften have limited incentive, even inmarkets with retail competition, toreduce their consumption when themarginal cost of electricity is high. Thisis because retail rates in the short-termdo not vary to account for the costs of

providing the electricity at the actualtime it was consumed.

b. Moderation of Price Volatility WithCaps and Capacity Payments

To date, the alternative to unmitigatedexchange market pricing has been priceand bid caps in wholesale exchangemarkets. Although price and bid capsmay moderate wide swings in market-clearing prices, not all the caps in placemay be necessary to prevent exercise of market power or set at appropriatelevels. Higher caps may strike a balance

between the desire of policy makers tosmooth out the peaks of the highestprice spikes and the need todemonstrate where capital is requiredand can recover its full investment.Some argue, however, that high pricecaps may burden consumers with highprices and yet not allow prices to riseto the level that will actually insure thatinvestors will recover the cost of newinvestment. Thus prices can risesignificantly and yet not elicit entry byadditional supply that could moderateprice in later periods.

Capacity payments are one way toensure that investors recover their fixedcosts. Capacity payments can provide a

regular payment stream that, whenadded to electric power market income,can make a project more economicallyviable than it might be otherwise. Likeany regulatory construct, however,capacity payments have limitations. It isdifficult to determine the appropriatelevel of capacity payments to spur entrywithout over-taxing market participantsand consumers.

To the extent that capacity ruleschange, this creates a perception of riskabout capacity payments that may limittheir effectiveness in promotinginvestment and ultimately new

generation. When rules change, buildersand investors may also take advantageof short-term capacity payment spikesin a manner that is inefficient from alonger-term perspective.

If capacity payments are provided forgeneration, they may prompt generationentry when transmission or demandresponse would be more affordable andequally effective. Capacity paymentsalso may disproportionately rewardtraditional utilities and their affiliates

by providing significant revenues forunits that are fully depreciated.

Capacity payments also may discourageentry by paying uneconomical units tokeep running instead of exiting themarket. These concerns can beaddressed somewhat by appropriaterules—e.g., NYISO’s rules givingcapacity payment preference to newly-entered units— but in general, it isdifficult to tell whether capacity

payments alone would spureconomically efficient entry.

One issue that has arisen is whethercapacity prices should be locational,similar to locational electric powerprices. PJM, ISO–NE and NYISO haveeither proposed or implementedlocational capacity markets that mayincrease incentives for building intransmission-constrained, high-demandareas. The combination of high electricpower prices and high capacity prices inthese areas may combine to create anadequate incentive to build generationin load pockets.181

c. Encouraging Additional TransmissionInvestment

Building the right transmissionfacilities may encourage entry of newgeneration or more efficient use of existing generation. But transmissionexpansion to serve increased or newload raises the difficulty of tying theeconomic and reliability benefits of transmission to particular consumers. Inother words, because transmissioninvestments can benefit multiple marketparticipants, it is difficult to assess whoshould pay for the upgrade. Thischallenge may cause uncertainty aboutthe price for transmission and aboutreturn on investment both for newgenerators and for transmissionproviders.

If transmission entry can connect low-cost resources to high-demand areas, itis closely linked to the issues of generation entry. Transmission entry,however, can in theory remove thekinds of transmission congestion thatresults in higher prices in load pockets.Transmission entry may be a double-edged sword: if it is expected to occur,it would reduce the incentive of companies to consider generation entry,

by eliminating the high prices they hopeto capture.

Both generation and transmission builders face the issue of dealing withan existing transmission owner or anRTO/ISO to obtain permission to build.Moreover, there are substantialdifficulties to site new transmissionlines. It is difficult to assess whether





182Regulatory solutions, more so than market- based outcomes, may outlive the circumstances thatmade them seem reasonable.

183Restructured states as of May 2006 include:Connecticut, Delaware, Illinois, Maine, Maryland,Massachusetts, Michigan, New Hampshire, New Jersey, New York, Ohio, Oregon, Pennsylvania,Rhode Island, Texas, and Virginia, plus the Districtof Columbia. The seven profiled states include arange of conditions that are similar to the otherstates with retail competition. Virginia is similar toPennsylvania in that their transitions to retailcompetition are over approximately a 10-yearperiod. Maine and Rhode Island are similar to NewYork and Texas in that prices for POLR service have been regularly adjusted to reflect changes in

wholesale prices. Delaware, the District of Columbia, Illinois, Michigan, New Hampshire, Ohioand Rhode Island share the situation in Marylandwith the transition period of fixed prices forresidential and small C&I POLR service coming toan end in the near future. Massachusetts’ rate capperiod ended recently. Many of the states about toend the transition period, share the development of approaches to bring POLR prices for residential andsmall C&I customers up to market rates in stagesrather than all at once. Several of these states alsoshare Maryland’s and New Jersey’s interest inauctions for procuring POLR service supplies.Oregon’s situation differs from the other states inthat only nonresidential customers can shop andthe shopping is limited to a short window of t imeeach year.

these risks are higher for transmission builders than for generation builders.

d. Governmental Control of GenerationPlanning and Entry

The final alternative is a regulatoryrather than a market mechanism toassure that adequate generation isavailable to wholesale customers. As a

method to spur investment, regulatoryoversight of planning has some positiveaspects, but it also has costs. Usingregulation through governmentallydetermined resource planning toencourage entry could result in moreentry than market-based solutions, butthat entry may not occur where, whenor in a way that most benefitscustomers. Regulatory oversight of investment also means regulators can

bar entry for reasons other thanefficiency. The stable rate of return oninvested capital offered under rate-regulation can encourage investment.On the other hand, rate-regulation canlead to overinvestment, excessivespending and unnecessarily high costs.Regulation also lacks the accountabilitythat competition provides. Mistakes asto where and how investments should

be made may be borne by ratepayers. Incompetitive markets, the penalties forsuch mistakes would fall onmanagement and shareholders. Thespecter of future accountability forinvestment decisions can lead to betterdecision-making at the outset.182

It is possible that regulatory oversightof planning would result in greater fueldiversity, and thus less exposure to risks

associated with changes in fuel prices oravailability. It could also lessenpotential boom-bust cycles whereinvestors overreact to market signalsand too many parties invest in oneregion. That reaction createsovercapacity, which in turn leads tolower prices. One large drawback toregulation, however, is the regulator’slack of knowledge about the correctprice to set. It is difficult to set thecorrect price unless frequentexperimentation with price changes ispossible, and yet consumers generallydo not favor significant price variation.

Chapter 4—Competition in RetailElectric Power Markets

A. Introduction and Overview

Congress required the Task Force toconduct a study of competition in retailelectricity markets. This chapterexamines the development of competition in retail electricity marketsand discusses the status of competition

in the 16 states and District of Columbiathat currently allow their customers tochoose their electricity supplier.

Although it has been almost a decadesince states started to implement retailcompetition, residential customers inmost of these states still have very littlechoice among suppliers. Few residentialcustomers have switched to alternative

suppliers or marketers in these states.Commercial and industrial customers,however, have more choices andoptions than residential customers, butin several states these customers have

become increasingly dissatisfied withincreasing prices. Residential,commercial, and industrial customers instates with retail competition often havelimited ability to adjust theirconsumption in response to pricechanges.

One of the main impediments tomarket-based competition has been thelack of entry by alternative suppliersand marketers to serve retail customers.Unlike markets in other industries, moststates required the distribution utility tooffer customers electricity at a regulatedprice as a backstop or default if thecustomer did not choose an alternativeelectricity supplier or the chosensupplier went out of business. Statesargued that a regulated service wasnecessary to ensure universal access toaffordable and reliable electricity.

States often set the price for theregulated service at a discount belowthen-existing rates and capped the pricefor multi-year periods. These initialdiscounts sought to approximate the

anticipated benefits of competition forresidential customers. Since then,wholesale prices have increased. Morethan any other policy choicesurrounding the introduction of retailcompetition, this policy of requiringdistribution utilities to offer service atlow prices unintentionally impededentry by alternative suppliers to serveretail customers—new entrants cannotcompete against a below-marketregulated price.

States with below-market, regulatedprices now face a chicken-or-eggproblem and ‘‘rate shock.’’ With rate

caps set to expire for the regulatedservice that most residential customersuse, states are loath to subject theircustomers to substantially higher marketprices that the distribution utilitiesindicate they must charge. These higherprices are even more painful tocustomers because they have few toolsto adjust their consumption aswholesale prices vary over time.However, if states require thedistribution utility to offer regulatedservice at below-market rates, retailentry, and thus competition, will not

occur. Moreover, below-market rates putthe solvency of the distribution utility atrisk.

This conundrum is furthercomplicated by the fact that mostdistribution utilities that offer theregulated service no longer owngeneration assets. The utilities in manystates sold their generation assets or

transferred them to unregulatedaffiliates at the beginning of retailcompetition. Thus, distribution utilitiesthat offer the regulated service mustpurchase supply in wholesale markets.Attempts to reassemble the verticallyintegrated distribution company face thereality that prices for many generationassets may be higher now than whenthey were divested at the beginning of retail competition. If the utility re-purchases these assets at these higherprices, it is likely to have ‘‘sold low and

bought high.’’ In both cases, thecompetitiveness of wholesale prices has

a direct impact on the retail pricesconsumers pay.This chapter addresses the status and

impact of retail competition in sevenstates that the Task Force examined indetail: Illinois, Maryland,Massachusetts, New Jersey, New York,Pennsylvania, and Texas. See AppendixD for each state profile. These sevenstates represent the various approachesthat states have used to introduce retailcompetition.183 The Chapter alsodiscusses why it is difficult at this timeto determine whether retail prices arehigher or lower than they otherwisewould be absent the move to retail

competition.The chapter provides several

observations based on the experiencesof states that have implemented retail





184 In 30 states retail electric customers continueto receive service almost exclusively under atraditional regulated monopoly utility servicefranchise. These states include 44% of all U.S. retailcustomers which represents 49% of electricitydemand.

185For example, Georgia law allows any newcustomers with loads of 900 kilowatts or more tomake a one time selection from among competingeligible electric suppliers. Southern.

186The FERC and the state will continue toregulate the price for transmission and distribution

services and, in most states, the local distributionutility will continue to deliver the electricity,regardless of which generation supplier thecustomer chooses.

competition with an emphasis on howstates can minimize market distortionsonce the rate caps expire. States withexpiring rates caps face several choiceson whether and how to rely oncompetition, rather than regulation, toset the retail price for electric power.

B. Background on Provision of Electric

Service and the Emergence of Retail Competition

For most of the 20th century, localdistribution utilities typically offeredelectric service at rates designed fordifferent customer classes (e.g.,residential, commercial, and industrial).State regulatory bodies set these rates

based on the utility’s costs of generating,transmitting, and distributing theelectricity to customers. Locally elected

boards oversaw the rates for customersof public power and cooperativeutilities. For investor-owned systems,the regulated rate included anopportunity to earn an authorized rateof return on investments in utility plantused to serve customers. Public powerand cooperative systems operate undera cost of service non-profit structure and

rates typically include a marginadequate to cover unanticipated costsand support new investment.

With minor variations, monopolydistribution utilities deliver electricityto retail customers.184 Industrialcustomers sometimes had more optionsas to service offerings and ratestructures (e.g., time-of-use rates, etc.)than residential and small businesscustomers.185

Beginning in the early 1990s, severalstates with high electricity prices beganto explore opening retail electric serviceto competition. As discussed in Chapter1 and Figure 4–1, rates variedsubstantially among utilities, even thosein the same state. Some of the disparitywas due to different natural resourceendowments across regions—most

important the hydroelectricopportunities in the Northwest andstates such as Kentucky and Wyomingwith abundant coal reserves. Also, somestates required utilities to enter intoPURPA contracts at prices much higherthan the utilities’ avoided costs. Inaddition to these rate disparities, someindustrial customers contended thattheir rates subsidized lower rates forresidential customers.

With retail competition, customers

could choose their electric supplier ormarketer, but the delivery of electricitywould still be done by the localdistribution utility.186 The idea was thatcustomers could obtain electric serviceat lower prices if they could chooseamong suppliers. For example, they

could buy from suppliers located

outside their local market, from newentrants into generation, or frommarketers, any of which might havelower prices than the local distributionutility. Moreover, the ability to chooseamong alternative suppliers wouldreduce any market power that local

suppliers might otherwise have, so that

purchases could be made from the localsuppliers at lower prices than wouldotherwise be the case. Also, customersmight be able to buy electricity oninnovative price or other terms offered

by new suppliers.





187Ca. AB 1890, available at http:// www.leginfo.ca.gov/pub/95– 96/bill/asm/ab _1851– 1900/ab _1890 _bill _960924 _chaptered.pdf.

188See, e.g., California Attorney General’s EnergyWhite Paper, A Law Enforcement Perspective onthe California Energy Crisis, Recommendations forImproving Enforcement and Protecting Consumersin Deregulated Energy Markets (Apr. 2004),available at http://ag.ca.gov/publications/ energywhitepaper.pdf; Federal Energy RegulatoryCommission, Final Report on Price Manipulation inWestern Energy Markets: Fact Finding Investigationof Potential Manipulation of Electric and Natural Gas Prices, Docket No. PA02–2–000 (March 26,2003); U.S. General Accounting Office, Restructured Electricity Markets, California Market DesignEnabled Exercise of Market Power, (June 2002),available at http://www.gao.gov/new.items/ d02828.pdf.

In 1996, California enacted acomprehensive electric restructuringplan to allow customers to choose theirelectricity supplier. To accommodateretail choice, California extensivelyrestructured the electric power industry.The legislation:

(1) Established an independentsystem operator to operate the

transmission grid throughout much of the state so that all suppliers couldaccess the transmission grid to servetheir retail customers;

(2) Established a separate wholesaletrading market for electricity supply sothat utilities and alternative supplierscould purchase supply to serve theirretail customers;

(3) Mandated a 10 percent immediaterate reduction for residential and smallcommercial customers for thosecustomers that did not choose analternative supplier;

(4) Authorized utilities to collect

stranded costs related to thosegeneration investments that wereunlikely to be as valuable in acompetitive retail environment; and

(5) Implemented an extensive public benefits program funded by retailratepayers.187

Other states also enactedcomprehensive legislation. In May 1996,New Hampshire enacted retailcompetition legislation—Rhode Island(August 1996), Pennsylvania (December1996), Montana (April 1997), Oklahoma(May 1997), and Maine (May 1997)—allfollowed suit. By January 2001, some 22states and the District of Columbia hadadopted retail competition legislation.Regulatory commissions in four otherstates (including Arizona which alsoenacted legislation) had issued ordersrequiring or endorsing retail choice forretail electric customers. (See chart andtimeline with retail choice legislationdates) Several states, primarily thosewith low-cost electricity such asAlabama, North Carolina, and Colorado,concluded that the retail competitionwould not benefit their customers. InColorado, for example, limitations ontransmission access and a highconcentration among generator

suppliers led the state to be concernedthat these suppliers would exercisemarket power to the detriment of customers. These states opted to keeptraditional utility service.

States adopting retail competitionplans generally did so to advanceseveral goals. These goals included:

• Lower electricity prices than undertraditional regulation through access to

lower cost power in competitivewholesale markets where generatorscompeted on price and performance;

• Better service and more options forcustomers through competition fromnew suppliers;

• Innovation in generatingtechnologies, grid management, use of information technology, and new

products and services for consumers;• Improvements in the environment

through displacement of dirtier, moreexpensive generating plants withcleaner, cheaper, natural gas andrenewable generation.

At the same time, legislatures andregulators affirmed support for theavailability of electricity to allcustomers at reasonable rates withcontinuation of safe and reliable serviceand consumer protections underregulatory oversight under therestructured model. Boxes 4–1 and 4–2describe the Pennsylvania and New

Jersey Legislatures’finding andexpected results of retail competition.

Box 4–1: Findings of the PennsylvaniaLegislature

The findings of the Pennsylvania GeneralAssembly demonstrate these varied goals:

(1) Over the past 20 years, the federalgovernment and state government haveintroduced competition in several industriesthat previously had been regulated as naturalmonopolies.

(2) Many state governments areimplementing or studying policies thatwould create a competitive market for thegeneration of electricity.

(3) Because of advances in electric

generation technology and federal initiativesto encourage greater competition in thewholesale electric market, it is now in thepublic interest to permit retail customers toobtain direct access to a competitivegeneration market as long as safe andaffordable transmission and distribution isavailable at levels of reliability that arecurrently enjoyed by the citizens and

businesses of this Commonwealth.(4) Rates for electricity in this

commonwealth are on average higher thanthe national average, and significantdifferences exist among the rates of Pennsylvania electric utilities.

(5) Competitive market forces are moreeffective than economic regulation incontrolling the cost of generating electricity.

Source: Pennsylvania HB 1509 (1995),available at http://www.legis.state.pa.us/ WU01/LI/BI/BT/1995/0/ HB1509P4282.HTMhttp://www.legis.state.

pa.us/WU01/LI/BI/BT/1995/0/ HB1509P4282.HTMhttp://www.legis.state.

pa.us/WU01/LI/BI/BT/1995/0/ HB1509P4282.HTM

Box 4–2: Findings of the New JerseyLegislature

‘‘The [New Jersey] Legislature finds anddeclares that it is the policy of this State to:

(1) Lower the current high cost of energy,and improve the quality and choices of

service, for all of this State’s residential, business and institutional consumers, andthereby improve the quality of life and placethis State in an improved competitiveposition in regional, national andinternational markets;

(2) Place greater reliance on competitivemarkets, where such markets exist, to deliverenergy services to consumers in greater

variety and at lower cost than traditional, bundled public utility service; * * *

(3) Ensure universal access to affordableand reliable electric power and natural gasservice;

(4) Maintain traditional regulatoryauthority over non-competitive energydelivery or other energy services, subject toalternative forms of traditional regulationauthorized by the Legislature;

(5) Ensure that rates for non-competitivepublic utility services do not subsidize theprovision of competitive services by publicutilities; ** *

C. Meltdown and Retrenchment

Starting in the late spring 2000 andlasting into the spring of 2001,California experienced high natural gasprices, a strained transmission system,and generation shortages. Wholesaleprices increased substantially duringthis time frame. State law cappedresidential provider of last resort (POLR)rates at levels that were soon below themarket price paid by utilities forwholesale electric power. One of California’s large investor ownedutilities declared bankruptcy because itcould not increase its retail rates to

cover the high wholesale power prices.The state stepped in to acquireelectricity supply on behalf of two of thethree IOUs operating in California.188 California eventually suspended retailcompetition for most customers while itreconsidered how to assure adequateelectric supplies and continuation of service at affordable rates in acompetitive wholesale marketenvironment. The suspension continuestoday. Box 4–3 describes the State’s rolein purchasing electricity and the all-time high prices it paid, and continuesto pay, for such electricity.





Box 4–3: The State of California’s ElectricityPurchases at All-Time High Prices

In 2001, the California spent over $10.7 billion to purchase electricity on the spotmarket to supply customer’s daily needs. Thestate also signed long-term contracts worthapproximately $43 billion for 10 years. Thesecontracts represented about one-third of thethree utilities’ requirements for the sameperiod (2001–2011). Viewed with the benefitof perfect hindsight, the state entered theselong-term contracts when prices were at anall-time high. Future prices hovered in therange of $350–$550 per MWh during the timethe State negotiated its long-term contractsand in April future prices peaked at $750/MWh as the state finalized its last contract.By August 2001, future prices had sunk

below $100. Thus, as of May 2006, the state

is obligated to pay well over market prices forat least 5 more years. See Southern CaliforniaEdison.

The experience in California and itsripple effects in the western regionprompted several states to defer orabandon their efforts to implement retailcompetition. Since 2000, no additionalstates have adopted retail competition.Indeed, some states including Arkansasand New Mexico, which had previouslyadopted retail competition plans,repealed them.

Other large states such as Texas, NewYork, Pennsylvania, New Jersey, andIllinois moved ahead with retailcompetition as planned. These states

have ended, or are about to end, theirPOLR service rate caps and will soonrely on competitive wholesale and retailmarkets for electricity.

As shown in Figure 4–2, at present, 16states and the District of Columbia haverestructured at least some of the electricutilities in their states and allow at leastsome retail customers to purchaseelectricity directly from competitiveretail suppliers. Restructured states as of April 2006 include: Connecticut,Delaware, District of Columbia, Illinois,Maine, Maryland, Massachusetts,Michigan, New Hampshire, New Jersey,New York, Ohio, Oregon, Pennsylvania,Rhode Island, Texas, and Virginia.

D. Experience with Retail Competition

With these expected benefits in mind,

the Task Force examined seven states indepth to report the status of retailcompetition. These states represent thedifferent approaches taken to introduceretail competition. The states includeIllinois, Maryland, Massachusetts, New

Jersey, New York, Pennsylvania, andTexas and they. These states are referredto as ‘‘profiled states.’’

In most profiled states, competitionhas not developed as expected. Fewalternative suppliers currently serveresidential customers. To the extent that

there are multiple suppliers servingcustomers, prices have not decreased as

expected, and the range of new optionsand services is limited. Much of the lackof expected benefits can be attributed tothe fact that some states still havecapped residential POLR rates.Commercial and industrial customersgenerally have more choices thanresidential customers because most donot have the option to take POLRservice at discounted, regulated rates,have substantially larger demand (load),and have lower marketing/customerservice costs.

This section first reviews the status of retail competition in the profiled states

with an emphasis on entry of newsuppliers, migration of customers toalternative suppliers, and thedifficulties in drawing conclusionsabout retail competition’s effect onprices. The section then discusses howregulated POLR service has distortedentry decisions of alternative suppliers.The section also discusses the lessonslearned from the use of POLR that mayassist states as they decide how tostructure future POLR service.





189See Massachusetts, New Jersey, and New Yorkprofiles, Appendix D. See also FTC Staff ReportCompetition and Consumer Protection Perspectiveson Electric Power Regulation Reform: Focus onRetail Competition (Sept. 2001) at 43 [hereinafterFTC Retail Competition Report].

190The price of generation assets have beenvolatile since these divestitures occurred. The assetprices are often based not only to the cost of thefuel necessary to generate the electricity, but alsoto the location of the asset on the transmission grid.

191See Illinois and Pennsylvania profiles,Appendix D. See also FTC Retail CompetitionReport, Appendix A (State profiles of Illinois andPennsylvania).

192Texas profile, Appendix D.193New York profile, Appendix D.194Massachusetts Department of

Telecommunications and Energy, List of Competitive Suppliers/Electricity Brokers, availableat http://www.mass.gov/dte/restruct/company.htm.

195Massachusetts Department of Telecommunications and Energy, Active LicensedCompetitive Suppliers and Electricity Brokers,available at http://www.mass.gov/dte/restruct/ competition/index.htm#Licensed%20Competitive%20Suppliers%20and%20Electricity%20Brokers.

196New Jersey Board of Public Utilities, List of Licensed Suppliers of Electric, available at http:// www.bpu.state.nj.us/home/supplierlist.shtml. Forexample, in the Connectiv territory, there are 18commercial and industrial (C&I) and 1 residentialsuppliers. Eighteen suppliers serving C&I customersand 1 serving residential customers in the PSE&Gservice territory.

197Texas Public Utilities Commission, TexasElectric Choice Compare Offers from Your LocalElectric Providers, available at http:// www.powertochoose.org/default.asp.

198New York State Public Service Commission,Competitive Electric and Gas Marketer SourceDirectory, available at http://www3.dps.state.ny.us/ e/esco6.nsf/ .

1. Status of Retail Competition

a. States Have Allowed DistantSuppliers to Access Local Customersand Have Encouraged DistributionUtilities to Divest Generation

The profiles revealed that each statetook some measures to encourage entryof new suppliers to compete with the

supply offered by the incumbent utility.Each of the profiled states adoptedpolicies to allow suppliers other thanthe local incumbent distribution utilityaccess to local retail customers byrequiring the utilities in the state to joinan independent system operator (ISO) orregional transmission organization(RTO). As discussed in Chapter 3, largerwholesale electricity geographic marketsenable retail suppliers and marketers to

buy generation supplies from a widerrange of local and distant sources (e.g.,neighboring utilities with excessgeneration, independent powerproducers, cogenerators, etc.). Even if nonew generation facilities are built,independent operation and managementof the transmission grid increases thechoices available to retail customers andmakes it more difficult for localgenerators to exercise market power.

Some states such as Massachusetts,New Jersey, and New York ordered orencouraged utilities to divest generationassets to independent power producers(IPP) either to eliminate possibletransmission discrimination or to secureaccurate stranded cost valuations.189 These divestitures have generally notrequired that a utility sell its generation

assets to more than one company toeliminate the potential for the exerciseof generation market power, but oftengenerating facilities have beenpurchased by more than one IPP.190 Inother states, such as Illinois andPennsylvania, several utilitiesvoluntarily divested their generationassets by selling them or moving theminto unregulated affiliates.191

The result of these divestitures has been that regulated distribution utilitiesin profiled states operate fewergeneration assets than in the past.Distribution utilities that are required toserve customers must access the

wholesale supply market to obtaingeneration supply to serve theircustomers. Table 4–2 shows the amountof a state’s generation that was underoperation by the state’s regulateddistribution utilities (i.e., in the ‘‘rate

base’’) prior to retail competition andafter the start of retail competition.

TABLE 4–1.—DISTRIBUTION UTILITY OWNERSHIP OF GENERATION AS-SETS IN THE STATE IN WHICH IT OP-ERATES

StatePrior to re-structuring(percent)

2002(percent)

Illinois ................ 97.0% 9.1%Maryland ........... 95.4 0.1Massachusetts .. 86.6 9.0New Jersey ....... 81.2 6.8New York .......... 84.3 32.4Pennsylvania .... 92.3 12.3Texas ................ 88.3 41.2

Source: U.S. Department of Energy, EnergyInformation Administration, State Profiles,Table 4 in each state profile, available at http://www.eia.doe.gov/cneaf/electricity/st _pro- files/e _profiles _sum.html . The pre-retail com-petition statistics are from 1997 and the post-retail competition statistics are from 2002.

Other states, such as Texas, limitedthe market share that any one generationsupplier can hold in a region, thusproviding more of an opportunity forother suppliers to enter.192 Still otherssuch as New York have helped organizeintroductory discounts from alternativesuppliers, thus providing customers anincentive to switch to these new

suppliers.193

b. Alternative Suppliers Serving RetailCustomers and Migration Statistics

In the profiled states, substantialnumbers of generation suppliers servelarge industrial and large commercialcustomers. For example, inMassachusetts, over 20 direct suppliersprovide service to commercial andindustrial customers, along with over 50licensed electricity brokers ormarketers.194 In Massachusetts,however, there are substantially feweractive suppliers serving residential

customers—only four inMassachusetts.195 In New Jersey,

commercial and industrial customerscan choose among nearly 20 suppliers,

but residential customers have a choiceof one or two competitive suppliers.196

For residential customers, Texas andNew York are the two states in whichmore than just a handful of suppliersserve residential customers. In Texas,residential customers have

approximately 15 suppliers from whichto choose.197 In New York, between sixand nine suppliers offer services toresidential customers in each serviceterritory.198 Very few, if any, suppliersprovide service to residential customersin the other profiled states or in otherretail competition states. One notableexception has been the municipalaggregation program in Ohio describedin Box 4–4.

Box 4–4: Customer Choice ThroughMunicipal Aggregation in Ohio

In New York, Texas, and most other statesretail customer switching occurs primarily

through individual customers making achoice to pick a specific alternative retailsupplier. In Ohio, however, most switchingactivity has occurred through aggregations of customers seeking a supplier under thestatewide ‘‘Community Choice’’ aggregationoption. In Ohio, the retail competition lawprovides for municipal referendums to seekan alternative supplier and allowsmunicipalities to work together to find analternative supplier. The largest aggregationpool, the Northeast Ohio Public Energycouncil is made up of 100 membercommunities and serves approximately500,000 residents. Aggregation accounts formost of the residential switching in Ohio.The Ohio program allows individual

customers to opt out of the aggregation. Inmost other states, aggregation programs usean approach under which customers mustspecifically opt in to participate.Participation rates generally are much higherunder opt out than under opt in programs.

In those territories with moregeneration suppliers, the migration ornumber of residential customersswitching from the POLR service to analternative competitive supplier is thegreatest. For example, in Massachusetts,as of December 2005, 8.5 percent of theresidential customers had migrated to acompetitive supplier. Approximately 41





199Massachusetts profile, Appendix D.200Texas profile, Appendix D.

201New Jersey profile, Appendix D. See also

Kenneth Rose, 2003 Performance of Electric PowerMarkets, Review Conducted for the Virginia StateCorporation Commission (Aug. 29, 2003) at II–19.

percent of large commercial andindustrial customers had switched toalternative suppliers, representing57.5% of the load.199 In states with alarge number of suppliers servingresidential customers, higherpercentages of residential customers hadswitched to a new supplier withapproximately 26% choosing a new

supplier in Texas.200 Of course, oncealternative suppliers serve customers,

the local distribution utility no longerprovides generation supply, butcontinues to deliver the generationsupply over its transmission anddistribution system.

c. Retail Price Patterns by Type of Customer

Figures 4–3 shows average revenues

per kilowatt hour for all customer typesin the profiled states against the

national average for the period 1990– 2005. The U.S. national average wasgenerally flat at 8 cents per kWh duringthis period. New York, Massachusetts,and New Jersey have generally beenhigher than the national average andTexas, Pennsylvania, Maryland, andIllinois have been lower. In 2004 and2005 retail prices in all states have

begun to increase.

i. Residential and CommercialCustomers

It is difficult to draw conclusions

about how competition has affectedretail prices for residential customers inthose states in which residentialcustomers continue to take cappedPOLR service (e.g., Maryland, Illinois,and portions of New York,Pennsylvania, and Texas). Pricecomparisons of regulated prices shedlittle light on the price patterns as aresult of retail competition.

For those states in which theresidential rate caps have expired, POLRprices have increased recently. In New

Jersey, residential rate caps on POLR

service expired in the summer of 2003.Since then, the state has conducted aninternet auction to procure POLRsupply of various contract lengths (oneand three year contracts). The stateholds annual auctions to replace thesuppliers with expiring contracts and toacquire additional supply. Rates for thegeneration portion of POLR service wereflat in 2003 and 2004 after adjusting for

deferred charges, but they increased in2005 and 2006 with rates increasingapproximately 13% between 2005 and2006.201

In Massachusetts, capped POLR ratesexpired in February 2005. Since thencustomers who had not chosen analternative supplier were still able toobtain POLR service. Massachusetts

based the generation portion of thePOLR service on the price of supplyprocured in wholesale markets throughfixed-priced, short-term (three or sixmonths) supply contracts. Rates for the





202Massachusetts profile, Appendix D.203Although POLR price is based on the hourly

wholesale price of electricity, customers in NewYork and New Jersey who purchase this service areunaware of the price until they are billed.

204See, e.g., ELCON; Portland Cement; Allianceof State Leaders; Alcoa.

205Portland Cement; Lehigh Cement.

206Constellation, PEPCO, Southern and EEI, ICC,IURC, and NYPSC, ISO–NE.

207National Grid.208For example, when PEPCO divested its

generation assets it stopped actively supporting itsair-conditioner DLC program.

generation portion of POLR service inthe Boston Edison (north) territoryincreased from 7.5 to 12.7 cents perKWh from 2005 to 2006.202

ii. Large Industrial Customers

Similar to the situation describedabove for residential customers, large

industrial customers that continue touse a fixed price POLR service shedlittle light on price patterns. A numberof states, however, have revised theirPOLR policies for large customers suchthat the POLR price for generation is apass-through of the hourly wholesaleprice for electricity plus a fixedadministrative fee. For example,Maryland, New Jersey, and New Yorkhave adopted this type of POLR pricingfor large industrial customers.203 Inthese states, substantial numbers of customers, as described above, haveswitched to alternative suppliers.

Large industrial customers have citedhow their rates have increased since the

beginning of retail competition.204 Indeed, some commenters suggestedthat the Task Force compare prices forcustomers of the same utility thatoperates in a state that did notimplement retail competition toexamine the effect of retail competitionon rates.205

The difficulty with this type of comparison is that many factorssimultaneously influence prices thatmay not be related to retail competition.For example, one state may havereduced the cross-subsidies of residential by industrial customers, andanother may not have, so that a pricecomparison would be misleading.Access to different generators (with lowor high prices) may be affected bytransmission congestion such thatcomparing two states as if they were inthe same physical location would bemisleading. Finally, some states may bedeferring recovery of costs to a futuretime period whereas other states are not.Thus, a simple price comparison maynot reveal whether retail competitionhas benefited customers, withoutconsideration of these and other factors.At this point it is difficult for the TaskForce to provide a definitiveexplanation of price differences betweenstates.

d. Results of Efforts To Bring AccuratePrice Signals Into Retail Electric PowerMarkets

The impact of retail competition to bring efficient price signals to retailcustomers has been mixed. ResidentialPOLR service rate caps have notincreased customer exposure to time-

based rates. The exception has beenreal-time pricing as the POLR service forthe largest customers in New Jersey,Maryland, and New York.

Commenters argue that POLR ratestructure can have a major effect oncustomer price responsiveness,especially among larger customers. A

broad spectrum of utilities, stateregulators, and ISOs argue that variablerates permit customers to react to pricechanges because these rates allowcustomers to clearly see how muchmoney they can save.206 Indeed, theexperience of the largest customers inNational Grid USA’s New York area,

suggests that after the introduction of retail competition, customers using real-time pricing demonstrate pricesensitivity.207

In states with traditional cost-basedregulation, utilities have used variousincentives for customers to reduceconsumption during periods in whichthere is high demand and transmissioncongestion (e.g., hot summer days). Theexistence of retail competition has, insome instances, discouraged the use of these traditional types of programs,particularly when POLR is no longer theresponsibility of distribution utilities.208

Without the need to maintain a portfolioof resources to meet POLR, distributionutilities may no longer value these typesof programs as a resource to ensurereliable and efficient grid operation.Shifting the responsibility of gridoperation and reliability to regionalorganizations such as ISOs/RTOs furtherdecreases the direct interest bydistribution utilities in these types of product offerings.

e. Retail Competition and Rural America

Many rural areas are served by smallnon-profit electric cooperative andpublic power utilities. Historically ruralareas were among the last to beelectrified and the most costly to serve.Customers are scattered and residentialand small loads predominate. Electricdistribution cooperative service areashave been opened to competition undersome state plans. No states have

required municipal and/or public powerutilities to implement retailcompetition.

Eight states with retail competitionrequired electric cooperatives toimplement retail competition in theirservice territories. These states areArizona, Delaware, Maine, Maryland,Michigan, New Hampshire,

Pennsylvania and Virginia. With theexception of Pennsylvania, state publicutility commissions regulated retailrates of electric cooperatives andapproved the retail competition plansfor each cooperative. Pennsylvania’srestructuring legislation left the designand implementation of retailcompetition to the individualdistribution cooperatives and their

boards. The Pennsylvania Public UtilityCommission is responsible for licensingcompetitive retail providers incooperative service territories.Cooperative retail competition plans

have been fully implemented inDelaware, Maine, New Hampshire,Pennsylvania, and Virginia. In Arizonaand Michigan some aspects of cooperative retail competition plans arestill in administrative or judicialproceedings. Michigan currently hasallowed electric cooperatives to offerretail competition to a portion of theirvery large industrial and commercialcustomers. Action on extendingcompetition to other customers inMichigan has been deferred.

Six more states allow electriccooperatives to opt in to retailcompetition on a vote of their boards or

membership. These are Illinois,Montana, New Jersey, Ohio, and Texas.None of these states regulate the rates orservices of electric distributioncooperatives, so design andimplementation of cooperative retailcompetition plans is left to theindividual cooperative. Licensing of competitive providers is handled by thestate, but providers must enter intoagreements with the cooperative inorder to begin enrolling retailcustomers. A handful of individualcooperatives in Montana and Texaselected to provide retail competition

options for their members.Tracking the progress of retailcompetition in rural areas is difficult

because most states do not postswitching data or maintain up to dateinformation on active suppliers incooperative service territories.Nevertheless, it was possible todetermine that there were fewalternative competitive providers, if any, for residential customers of ruralsystems open to retail competition.There were no competitive providersenrolling customers in coop systems in





209The comments also identified other factorsthat depress or delay entry into retail competitionmarkets besides the policies surrounding POLRdiscussed above. It is difficult for the Task Force toevaluate which additional factors are the mostimportant because of the lack of entry in moststates. For example, the Pennsylvania ConsumerAdvocate identified several factors that depressedretail entry by suppliers to serve residentialcustomers, including ‘‘the acquisition costsassociated with marketing programs to reachresidential customers, the costs of serving suchcustomers once acquired, and the rising prices forgeneration supply service in the wholesale market’’ PA OCA at 3. The Maine Public Advocate echoedthese and identified the ‘‘miscalculation by somesuppliers as to the risks and rewards for retailelectricity competition’’ ME PA at 3. The IndustrialCustomers identified that retail markets are not

fully competitive because of the insufficientgeneration divestitures that left suppliers withmarket power. ELCON at 2. Other factors identified by Industrial Customers include inability of alternative suppliers to gain access to necessarytransmission services to serve their customers.ELCON at 6. Others customers suggested the lackof uniform rules throughout every service territoryhinder ease of entry for suppliers. Wal-Mart at 13.Other commenters argued that alternative suppliersneed access to customer usage data from utilities to be able to market to prospective customers.Constellation at 43. Still others argued for nominimum stay requirements at POLR andconstrained shopping windows, which can dampenentry. RESA at 30–31, Strategic at 10, Wal-Mart at13.

210There is one potential exception. Suppliersthat offer a substantially different product, ‘‘green’’ power from wind turbines, for example, may beable to charge a higher price and still attractcustomers.

211See, e.g., ICC, PPL, and PA OCA.212See, e.g., PA OCA; NASUCA.213See, e.g., RESA, Wal-Mart, NEMA, and Suez.

214Most states have a mechanism by which highrisk drivers can obtain insurance. Often insurers ina state are assigned a portion of the pool of highrisk drivers based on that firm’s share of driversoutside the pool. AIPSO manages many of the poolsand maintains links with individual state programsat https://www.aipso.com/adc/ DesktopDefault.aspx?tabindex=0&tabid=1. Similarplans are available in many states for individualswith prior health conditions who are seeking healthinsurance coverage. See Communicating forAgriculture and the Self-Employed, ComprehensiveHealth Insurance of High-Risk Individuals, 19th Ed.(2005).

215Texas will end its ‘‘price to beat’’ system in2007 (Texas profile). Massachusetts ended its rate-capped POLR service in February 2005(Massachusetts profile). In the Atlanta Gas Lightdistribution territory, the distribution utilitypetitioned the Georgia Public Service Commissionto withdraw from retail sales. In Georgia, under theamended Natural Gas Competition andDeregulation Act of 1997, a customer who does notchoose as alternative supplier is randomly assignedto an alternative supplier. Discussion anddocumentation about the Georgia natural gas retailcompetition program are available at http:// www.psc.state.ga.us/gas/ngdereg.asp.

216New Jersey profile, Appendix D.

Maine, New Hampshire, Pennsylvania,Arizona, Maryland, and Virginia in May2006. In Delaware, and Montana,competitive providers had been licensedto serve coop customers, but it isunclear that any are currently enrollingcustomers. Licensed provider andswitching information for Texascooperatives is not yet available.

B. POLR Service Price Significantly Affects Entry of New Suppliers

Each of the profiled states hasrequired local distribution utilities tooffer a POLR service for customers whodo not select an alternative generationservice provider or whose supplier hasexited the market. The price that thedistribution utility charges for regulatedPOLR service is usually ‘‘fixed’’ for anextended period—that is, it does notvary with increases or decreases inwholesale prices. The most significantportion of the POLR service price is thegeneration portion of the POLR service.Many states denote this as the ‘‘price to

beat’’ or the ‘‘shopping credit.’’ It alsorepresents the amount that the customeravoids paying the distribution utilitywhen the customer chooses analternative generation service provider.The customer instead pays thealternative electricity supplier’s chargesfor generation services.

The comments reported that the priceof POLR service is the most significantfactor affecting whether new supplierswill enter the market and compete toserve customers.209 The POLR price is

the price that new suppliers, includingunregulated affiliates of the distributionutility, must compete against if they areto attract customers.210

1. Contrasting Visions of POLR Service

The comments revealed two long-termvisions of POLR service. In the firstvision, POLR is a long-term option for

customers. In the second vision, POLRis a temporary service for customers

between suppliers. The first visionentails POLR service that closelyapproximates traditional utility service,

but in a market place with other sourcesof supply available to customers. POLRservice under the first vision oftenfeatures prices that are fixed overextended periods of time. In this vision,government-regulated POLR servicecompetes head-to-head with private, for-profit retail suppliers.211 An analogousexample may be the United States PostalService as a provider of parcel postageservice in competition with for-profit,package delivery services such asUnited Parcel Service, DHL, and FederalExpress. Alternative suppliers may growin this vision as they find additionalapproaches to attract customers, butPOLR service will likely retain asubstantial portion of sales, particularlysales to residential customers. This typeof POLR service serves as a yardstickagainst which alternative supplierscompete. Most states have used thisversion of POLR.212

In the second vision, POLR service isa barebones, temporary serviceconsisting of retail access to wholesale

supply, primarily for customers who are between suppliers. In this vision,alternative suppliers serve the bulk of retail customers. The alternativesuppliers compete primarily againsteach other with a variety of price andservice offers designed to attractdifferent types of customers. This typeof POLR service acts as a stopgap sourceof supply that ensures that electricservice is not interrupted for customerswhen an alternative supplier leaves themarket or is no longer willing to serveparticular customers. Wholesale spotmarket prices or prices that vary with

each billing cycle may be acceptable asthe price for POLR service under thisvision.213 A comparable supplyarrangement for this version of POLRservice is the high risk pool forautomobile insurance operated in any of

several states.214 Texas andMassachusetts provide current examplesof this vision, as is Georgia in its designfor retail natural gas sales.215

Some of profiled states incorporatedaspects of both visions of POLR servicefor different types of customers. Forexample, New Jersey adopted the firstapproach for POLR service to residential

customers and the second approach forPOLR service to large commercial andindustrial customers.216 Large C&Icustomers are generally expected to bewell-informed buyers with wide energyprocurement experience. As such, somestates determined that large C&Icustomers are more likely to be able toquickly obtain the benefits of retailcompetition without additional helpfrom state regulators provided in theform of fixed price POLR prices.

2. Key POLR Service Design Decisions

The profiled states took different

approaches to design their POLR serviceofferings. Key design decisions involvedthe pricing of the POLR, how to acquirePOLR supply, and the duration of thePOLR obligation. Each of these canaffect entry conditions that alternativesuppliers face. This section describeseach of the decisions.

a. Pricing of POLR Service

The profiled states generally set thePOLR price at the pre-retail competitionregulated price for electric power less adiscount. The discounts usually persistover a specified multi-year period.Assuming that competition generally

lowers prices, one rationale for thediscounts was to provide a proxy for theeffects of competition applied tocustomers viewed as less likely to be





217 Illinois profile, Appendix D.218Texas profile, Appendix D.219See discussion of the California energy crisis

in which one of the state’s utilities declared bankruptcy because, in part, capped POLR rateswere substantially below wholesale prices.

220The distribution utility continues to charge thecustomer a delivery charge to cover the

transmission and distribution expense (the ‘‘wires’’ charge).

221Thomas L. Welch, Chairman, Maine PublicUtilities Commission, UtiliPoint PowerHittersinterview (January 24, 2003), available at http:// mainegov-images.informe.org/mpuc/ staying _informed/about _mpuc/commissioners/ph-welch.pdf .

222See Kenneth Rose, Electric Restructuring Issues for Residential and Small BusinessCustomers, National Regulatory Research InstituteReport NRRI 00–10 (June 2000), available at http:// www.nrri.ohio-state.edu/dspace/bitstream/2068/ 610/1/00– 10.pdf , for a discussion of adders andtheir relationship to wholesale prices and headroomfor entrants in Pennsylvania and other states.

223 Id .224Over time, the size of the shopping credit in

Pennsylvania faded in significance as thecompetitive rates increased relative to POLR serviceprices due to fuel cost increases. See the pattern of customer switching in the Pennsylvania profile inthe appendix.

225FTC Retail Competition Report, State Profiles,Appendix A.

226New York profile, Appendix D; FTC RetailCompetition Report, New York State Profile,Appendix A.

227 Illinois profile, Appendix D.228New Jersey profile, Appendix D.229See, e.g., ME OPA.230New York profile, Appendix D.

able to quickly obtain such savings forthemselves. The Illinois POLR servicediscount, for example, was developed to

bring local prices into line with regionalprices. Those customers in areas withrelatively low prices before customerchoice did not receive discounts belowprevious regulated rates at the beginningof retail competition. In contrast,

customers in the Commonwealth Edisonterritory, the area with the highest cost-

based rates, received 20% discounts to bring retail POLR prices there into linewith regional average bundled serviceprices prior to the restructuringlegislation.217

b. The Extent and Timing of PassThrough of Fuel Cost Changes

States also have considered the extentto which they should adjust theregulated POLR price to allow forchanges in fuel costs to generateelectricity. Some states have separated

fuel costs from other cost components, because fuel costs have been morevolatile than other input prices—theyare the largest variable cost component,and can be calculated for each type of generation unit, based on publicinformation. These factors also suggestthat a generation firm does not havemuch control over its fuel costs once thegeneration investment has been made.For example, Texas instituted twiceyearly adjustments in the POLR service(price to beat) price calculations. Byadjusting POLR prices for changes infuel costs, the Texas regulators have

been able to prevent the POLR pricefrom slipping too far away fromcompetitive price levels, thusmaintaining the POLR price as a closerproxy for the competitive price.218 If retail prices fall too far below wholesaleprices, the POLR supplier may havefinancial difficulties and alternativesuppliers will be unlikely to enter orremain as active retailers.219

c. POLR Price and the Shopping Credit

When a retail customer picks analternative supplier, the distributionutility with a POLR obligation avoids

the costs of procuring generation supplyfor that consumer. The distributionutility therefore ‘‘credits’’ the customer’s

bill so that the customer pays thealternative supplier for the electricitysupplied.220 This avoided charge is

known as the shopping credit and isequal to the regulated POLR serviceprice. States have used two approachesto determine the level of the shoppingcredit. One view is that the shoppingcredit equals the avoided cost or theproportion of POLR procurement costsattributable to a departing customer.Maine, for example, has estimated

avoided costs on this basis with noadditional estimated avoided costs.221 This view results in a lower shoppingcredit and total POLR price. Analternative perspective is that thedistribution utility also avoids othercosts on top of avoided procurementcosts, including marketing andadministrative costs.222 This viewresults in a higher shopping credit andtotal POLR price. In Pennsylvania, thePOLR shopping credit included severalother elements such as avoidedmarketing and administrative costs.223 Some observers attributed the early high

volume of switching to alternativesuppliers in Pennsylvania to theadditional avoidable costs that wereincluded in the Pennsylvania shoppingcredit calculations.224

d. The Multi-Year Period for POLRService

Every state that implemented retailcompetition has determined the lengthfor which POLR should continue to beavailable to customers at a discountfrom prior regulated prices. The lengthof this period has generallycorresponded to the distributionutility’s collection of ‘‘stranded’’

generation costs. In a competitive retailenvironment, utilities no longer wereassured that they could recover the costsof all of their state-approved generationinvestments. Most states faced claims of utility stranded costs associated withgeneration facilities that were unlikelyto earn enough revenues to recover fixedcosts once customers can seek out

alternative, lower-priced retailsuppliers. States allowed utilities withstranded costs to recover those coststhrough charges on distribution servicesthat cannot be bypassed.225

Each state that authorized thecollection of stranded costs faceddecisions on how to determine thesecosts and the duration of the collection

period. These decisions fundamentallyaltered the electric power industry andwere at the center of some of the mostcontentious issues facing stateregulators. First, some states requiredthat some or all generation be sold toobtain a market-based determination of the level of stranded costs. For example,Maine and New York took thisapproach.226 In other states, such asIllinois, utilities voluntarily divestedgeneration assets. As noted above, theresult of these divestitures is thatgeneration is no longer primarily in thehands of regulated distribution

utilities.227

e. Procurement for POLR Service

Given that most utilities no longerown generation to satisfy all of theirPOLR obligations, utilities have takendifferent approaches to acquire thenecessary generation supply. Forexample, the utilities in New Jersey thatoffer residential POLR service acquirethe generation supply through the use of three overlapping 3-year contracts, eachfor approximately one third of theprojected load.228 This ‘‘laddering’’ of supply contracts reduces the volatilityof retail electricity prices for customers,

but it does not assure that the pricespaid by POLR service consumers are atthe short-term competitive level.229 Other states have used different ways tohedge the volatility in short-term energyprices. For example, New Yorkdistribution utilities have long-termsupply contracts with the purchasers of their divested generation assets(‘‘vesting contracts’’) based on pre-divestiture average generation prices.230

E. Observations on How POLR ServicePolicies Affect Competition

One of the most contentious issues

currently facing state regulators iswhether and how to price POLR serviceonce the rate caps expire. This situationis especially vexing for those states thathad stranded cost recovery periods





231See, e.g., Wal-Mart; WPS Resources; ICC; PPL;RESA.

232See, e.g., Wal-Mart; RESA.233See, e.g., EEI. 234See, e.g., RESA.

235See, e.g., Wal-Mart and 10–11; Morgan.236 In case 03–E–0641, the New York Public

Service Commission required New York utilities tofile tariffs for mandatory real-time pricing (RTP) forlarge C&I customers. The order observed that‘‘average energy pricing reduces customers’ awareness of the relationship between their usageand the actual cost of electricity, and obscuresopportunities to save on electric bills that would become apparent if RTP were used to reveal varyingprice signals.’’ It further notes that ‘‘if a sufficientnumber of customers reduced load in response toRTP, besides benefiting themselves, the reductionin peak period usage would ameliorate extremes inelectricity costs for all other customers.’’

237New Jersey profile, Appendix D; RESA.

during which fixed POLR prices becamesubstantially lower than currentwholesale prices. The rate caps expirein 2006 for states such as Maryland,Delaware, Illinois, Ohio, and RhodeIsland, and customers that did notchoose an alternative supplier are facedwith the prospect of substantiallyincreased electricity prices relative to

those in effect when retail competition began six or seven years ago. Thevarious state POLR policies show therange of options available to thesestates.

1. POLR Service Price to Approximatethe Market Price

For the POLR service price to provideeconomically efficient incentives forconsumption and supply decisions, itmust closely approximate or be linkedto a competitive market price based onsupply and demand at a given point intime. If the POLR service price does not

closely match the competitive price, itis likely to distort consumption andinvestment decisions away fromtheoretically optimal allocation of electricity resources. Theoretically,competitive market prices alignconsumers’ willingness to pay for aservice with a suppliers cost of supply(where, in the long run, cost includes afair market return on investment). Thisalignment is thought to lead to aneconomically efficient allocation of resources, wherein no alternatedistribution of resources could lead togreater benefits to society as a whole.

Experience within the profiled statesshows that approximating thecompetitive price is not an easy task.Not only does the competitive pricechange when prices of inputs change,

but the price also acts as an investmentsignal for new generation. Thecompetitive price can quickly anddramatically move. Over the pastseveral years, the initial fixed discountsfor POLR service have resulted in POLRservice prices that are below marketprices or occasionally above marketprices, but never at the market price forlong.231 When the POLR prices are

below competitive levels, even efficient

alternative suppliers cannot profit byentering or continuing to serve retailcustomers.232 Firms with the POLRobligation can become financiallydistressed, as they did in Californiaduring its energy crisis.233

Some of the change in the marketprice is likely to be due to changes infuel prices. A POLR service design that

adjusts the retail electricity price forchanges in the prices of fuels used bymarginal generators makes a betterproxy for the market price than one thatis fixed. When the POLR price isadjusted to incorporate underlying fuelprice changes, but it is adjustedinfrequently, the POLR price canrepeatedly change from being above the

competitive market price to below thecompetitive market price.234 In thisway, a fixed price creates incentives forcustomers to move back and forth fromPOLR service to alternative suppliers.This repeated switching can createadditional costs for both POLR serviceproviders and alternative suppliers andit can reduce the certainty that bothPOLR service and competitive suppliersmay need in order to make long-termsupply arrangements. If there are otheridentifiable cost components thatfluctuate widely, including them inPOLR service price adjustments will

also increase the likelihood that thePOLR service price will be a reasonableproxy for the competitive price.

2. Lack of Market-Based Pricing DistortsDevelopment of Competitive RetailMarkets

A second issue arises when below-market POLR service prices persistduring a period of rising fuel prices andwholesale supply prices. In thesecircumstances, customers are likely toexperience a shock when POLR serviceprices are adjusted to match prevailingwholesale prices. This situation cancreate public pressure to continue the

fixed POLR rates at below-market levels.For example, some jurisdictions haveconsidered a gradual phase-in of theprice increase to bring POLR prices tothe market level. The shortfall betweenthe market POLR price and the pricecustomers pay is usually deferred andcollected later from the POLR provider’scustomers.

Although this approach reduces rateshock for customers, it is likely todistort retail electricity markets. First, aphase-in continues to provideinaccurate price signals for customersand undermines incentives to reduce

consumption or to conserve electricpower use. Second, it prevents entry of alternative suppliers by keeping thePOLR rate below market for additionalyears. Third, it results in higher pricesin future years as the deferred revenuesare recovered. Fourth, if surcharges topay for deferred revenues are notdesigned carefully, the charges candisrupt existing competition by forcingcustomers with alternative suppliers topay for part of the deferred revenues.

Fifth, if wholesale prices decline,customers will choose alternativesuppliers and this migration will createa stranded cost problem because thePOLR provider will have lost customerswho were counted on to pay the higherprices. Moreover, if the state preventsthe stranded cost problem by imposinglarge exit fees on POLR service

customers, competition may notdevelop even after POLR service pricesrise to market levels because POLRservice customers will be locked in tothe POLR provider. Finally, continuedPOLR service price caps in anenvironment of increasing wholesaleprice increases can endanger thefinancial viability of the distributionutility.

3. Different POLR Services Designed forDifferent Classes of Customer

Some states have different POLRservice designs for different customer

classes. POLR service prices offered tolarge C&I customers generally haveentailed less discounting from regulatedrates or competitive market-basedprocurement and have been based onwholesale spot market prices.

Large C&I customers generally have a better understanding of price risk, themeans to reduce it, and the costs toreduce it than do other customerclasses. In addition, suppliers often cancustomize service offerings to theunique needs of these largecustomers.235 Large C&I customers, withtheir larger loads, also may be betterequipped to respond to efficient pricesignals than other classes of customers.The result of this price response may beto improve system reliability anddissipate market power in peak demandperiods.236

In states in which this division between POLR service for large C&Icustomers and POLR service forresidential and small C&I customers has

been implemented, there has been moreswitching to competitive providersamong large C&I customers.237 Manyalternative suppliers have reportedlydeveloped customized time of use





238See, e.g., Consolidated Edison; Alliance for

240 James Zolnierek, Katie Rangos, and JamesEisner, Federal Communication Commission,Common Carrier Bureau, Industry AnalysisDivision, Long Distance Market Shares, Second Quarter 1998 (September 1998), pp. 19–20,available at http://www.fcc.gov/Bureaus/ Common _Carrier/Reports/FCC-State _Link/IAD/ mksh2q98.pdf , and Thomas L. Welch, Chairman,Maine Public Utilities Commission, UtiliPointPowerHitters interview (January 24, 2003) availableat http://mainegov-images.informe.org/mpuc/ staying _informed/about _mpuc/commissioners/ph-welch.pdf .

243See, e.g., ELCON; Progress Energy;

Constellation; PEPCO; PA OCA.244 In Case 05–M–0858, the New York Public

Service Commission adopted the ‘‘PowerSwitch’’ alternative supplier referral program, firstdeveloped by Orange and Rockland, as the modelfor all state utilities.

245New York State Consumer Protection Board,Comment to the New York State Public ServiceCommission Case 05–M–0334 Orange and

contracts for large C&I customers.238 Moreover, the profiled states show thatthere are a substantial number of suppliers actively serving large C&Icustomers. Box 4–5 describes theunique sign-up period that Oregon hasdeveloped for its non-residentialcustomers.

Box 4–5: Oregon’s Annual Window forSwitching for Nonresidential Customers

Nonresidential customers of the two largeinvestor-owned distribution utilities inOregon can switch to an alternative supplier,

but the switching process is unique.Nonresidential customers must make theirselections during a limited annual window.The window must be at least 5 days induration, but usually a month is allowed. Inaddition to picking the alternative supplier,the largest customers must select a contractduration. One option specifies a minimumduration of 5 years, with an annual renewalafter that. As of 2005, alternative supplierswere anticipated to serve about 10% of load

in one distribution area and about 2.1% inthe other. The former utility offered choice

beginning in 2003. The latter utility begancustomer choice in 2005. Detaileddescriptions are available at http:// www.oregon.gov/PUC/electric _restruc/ indices/ORDArpt12-04.pdf .

Exposure of all customers to time- based prices is not necessary tointroduce price-responsiveness into theretail market.239 As a first step,customers who are the most price-sensitive and elastic could be exposedto time-based rates. Niagara Mohawk inupstate New York has taken this

approach for its largest customers, ashave Maryland and New Jersey for theirlargest customers. California isconsidering setting real-time pricing asthe default rate for medium-sized andlarger commercial and industrialcustomers. Another means to introduceprice-responsiveness is to providecustomers voluntary time-based rateprograms, along with assistance inequipment purchase or financing. Theactions of the New York PSC to requirevoluntary TOU for residentialcustomers, and the Illinois legislature torequire that residential customers be

offered real-time pricing as a voluntarytariff are examples of such a policy. Of course, the point is that competitionwill provide customers with the mix of products and services that match theirneeds and preferences—not a

determination of the popularity of real-time pricing.

4. Use of Auctions To Procure POLRService

As discussed above, New Jersey hasused an auction process to procurePOLR supply for both residential andC&I customers. Illinois has proposed touse a similar auction when its rate capsexpire. Auctions may allow retailcustomers to obtain the benefit of competition in wholesale markets assuppliers compete to supply thenecessary load. However, as discussedin Chapter 3, if there is a load pocket,use of an auction is unlikely to help thisprocess and thus the benefits of competition may not be as great.

5. Consumer Awareness of CustomerChoice and Engendering Interest inAlternative Suppliers

Observers of restructuring in other

industries have found that the growth of customer choice can be a slow process.A commonly cited example is that ittook 15 years before AT&T lost half of long-distance service customers toalternative suppliers.240 One reasonwhy retail competition could be slow todevelop is that the expected gains fromlearning more about market choices aretoo small to make it worthwhile tolearn.241 Residential customers withsmall loads might be in this position instates with retail customer choice.242

The pricing of POLR service and aidin computing the ‘‘shopping credit’’ may be elements that can encouragemore rapid development of retailcompetition by making the rewards foractive search sufficient to motivatesearch behavior by residentialconsumers. Some states that have low‘‘shopping credits’’ have had little retailentry. Some retail competition stateshave had substantial consumereducation programs, including Websites with orientation materials and

price comparisons.243 These effortsminimize the cost of learning moreabout the market and about marketalternatives and can, therefore, makemarket search beneficial to customers.

New York has engaged in a differentapproach to encourage the developmentof retail competition. It is helping toorganize temporary discounts from

alternative suppliers and orderingdistribution utilities to make thesediscounts known to consumers whocontact the distribution utility.244 Theseefforts have increased residentialswitching and reduced prices, at leastfor the short term. Experience indicatesthat once residential customers switchto alternative suppliers, they seldomreturn to POLR service once thetemporary discounts no longer apply.245 [FR Doc. 06–5247 Filed 6–9–06; 8:45 am]

BILLING CODE 6717–01–C

ENVIRONMENTAL PROTECTIONAGENCY

[FRL–8183–6]

Science Advisory Board Staff Office;Advisory Council on Clean AirCompliance Analysis; Notification of aPublic Advisory Committee Meeting(Teleconference)

AGENCY: Environmental ProtectionAgency (EPA).ACTION: Notice.

SUMMARY: The Environmental ProtectionAgency (EPA or Agency), ScienceAdvisory Board (SAB) Staff Officeannounces a public teleconference forthe Advisory Council on Clean AirCompliance Analysis.DATES: The teleconference will takeplace on June 29, 2006 from 1 p.m. to3 p.m. (Eastern Time).FOR FURTHER INFORMATION CONTACT: Anymember of the public who wishes toobtain the teleconference call-numberand access code must contact Dr. HollyStallworth, Designated Federal Officer(DFO), EPA Science Advisory Board

us white house federal register: 06-5247

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